Galleon Energy Inc.
TSX : GO

Galleon Energy Inc.

March 09, 2011 19:45 ET

Galleon Announces 2010 Year End Reserves

CALGARY, ALBERTA--(Marketwire - March 9, 2011) - Galleon Energy Inc. ("Galleon" or the "Corporation") (TSX:GO) announces its 2010 year end reserves

2010 Performance

- Gross proved plus probable reserves were 64.1 million BOE (44% oil and NGLs);

- Gross proved plus probable oil and NGLs reserves were 28.2 million BOE;

- As previously disclosed, 14.5 million BOE (85% oil and NGLs) of proved plus probable reserves were divested during 2010. This accounts for 70% of the reduction in reserve volumes from 2009 to 2010.

- On a BOE basis, technical revisions were negative 2% on proved reserves and negative 4% on proved and probable reserves;

- The reserve life index is 13 years based on gross proved plus probable reserves and average Q4 2009 production of 13,556 BOE/d;

- 69 gross wells were drilled resulting in 30 (28.9 net) natural gas wells, 33 (29.9 net) light oil wells, and 3 (3.0 net) heavy oil wells; a success rate of 96%;

- Net capital expenditures were $22.9 million in 2010;

- 2010 production averaged 14,800 BOE/d: natural gas - 62.1 Mmcf/d and crude oil and NGLs - 4,450 Bbl/d; with an operating netback of $23.47/BOE;

- Galleon's net asset value per share based on PV 10% before tax at December 31, 2010 is estimated to be $ 9.47 per basic share.

- At December 31, 2010, an amount of $135.7 million was drawn under the Corporation's available credit facilities of $250 million. Net debt was $152.9 million at December 31, 2010, a reduction of approximately 33% from December 31, 2009.

- Undeveloped landholdings at December 31, 2010 were 600,497 net acres with an estimated value of $43.4 million based upon an independent evaluation prepared by Seaton-Jordan & Associates Ltd.;



Highlights:

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Drilling Activity Twelve months ended December 31
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2010 2009 Change
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Total gross wells drilled 69 44 +56%
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Total gross wells cased 66 41 +61%
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Net wells cased 61.8 38.6 +60%
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Twelve months ended December 31
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2010 2009 Change
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Gross proved plus probable reserves
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Oil & NGLs (MBbls) 28,155 42,626 (34%)
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Natural gas (Mmcf) 215,698 251,549 (14%)
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Combined (MBOE) 64,105 84,551 (24%)
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Finding, development, acquisition &
disposition cost (1)
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Before future capital ($/BOE) (i) $ 9.84
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Recycle ratio (1) before future capital (i) 2.1
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After including future capital ($/BOE) (i) $ 18.45
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Recycle ratio (1) after including future capital (i) 1.1
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(1) FD&A cost and recycle ratio relating to 2010 have been calculated using
unaudited financial information that may change on completion of the
audited financial statements.
(i) Due to the magnitude of the asset disposition that occurred in June,
2010, the one year FD&A is not meaningful in terms of reserve additions
versus capital spent.


Reserves

The reserves information is based upon an independent reserve assessment and evaluation prepared by DeGolyer and MacNaughton Canada Limited ("DeGolyer and MacNaughton") effective December 31, 2010 ("DeGolyer Report"). The following presentation summarizes the Corporation's crude oil, natural gas and natural gas liquids reserves and net present values before income taxes of future net revenues for the Corporation's reserves using forecast prices and costs based on the DeGolyer Report. The DeGolyer Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101.

Gross reserves are the total of the Corporation's working interest share before deduction of royalties owned by others and without including any of the Corporation's royalty interests. Net reserves are the total of the Corporation's working interest reserves after deducting amounts attributable to royalties owned by others, plus the Corporation's royalty interest reserves.



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Summary of Reserves
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Oil and NGLs (MBbls) Natural Gas (Mmcf) Total (MBOE)
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Gross Net Gross Net Gross Net
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Proved developed
producing 3,983 3,384 67,554 63,620 15,242 13,988
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Proved developed
non-producing 1,902 1,541 20,356 17,847 5,295 4,516
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Proved undeveloped 7,280 5,946 48,057 44,349 15,290 13,338
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Total proved 13,165 10,872 135,967 125,816 35,826 31,841
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Probable 14,990 11,700 79,731 70,577 28,279 23,463
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Total proved plus
probable 28,155 22,572 215,698 196,393 64,105 55,304
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Note: totals may not add due to rounding


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Net Present Value of Future Revenue Before Income
Taxes as of December 31, 2010 ($MM)
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Discounted at:
Reserves category Undisc 5% 8% 10% 15%
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Proved developed producing 385 317 289 273 242
Proved developed
non-producing 131 105 93 87 73
Proved undeveloped 304 200 158 136 94
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Total proved 820 621 540 495 408
Probable 812 560 462 410 311
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Total proved plus probable 1,631 1,182 1,002 905 719
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Note: Net present value of future revenues does not represent fair market
value. Totals may not add due to rounding.


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Net Present Value of Future Revenue After Income
Taxes as of December 31, 2010 ($MM)
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Discounted at:
Reserves category Undisc 5% 8% 10% 15%
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Proved developed producing 385 317 288 273 242
Proved developed
non-producing 131 105 93 86 72
Proved undeveloped 244 159 125 107 73
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Total proved 760 581 507 467 387
Probable 606 415 340 301 227
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Total proved plus probable 1,366 996 848 768 614
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Note: Net present value of future revenues does not represent fair market
value. Totals may not add due to rounding.


DeGolyer and MacNaughton's December 31, 2010 price forecast was used in the DeGolyer Report. The following is the price forecast for the first five years.



NYMEX HH Alberta Spot USD/CAD
Pricing WTI @ Cushing Natural gas Natural gas Exchange
assumptions ($US/Bbl) ($US/Mcf) ($Cdn/GJ) ($US)
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2011 88.00 4.73 3.78 0.98
2012 90.78 5.45 4.45 0.98
2013 93.64 6.15 5.10 0.98
2014 96.57 6.80 5.71 0.98
2015 99.58 7.10 5.99 0.98
5 year average 93.71 6.05 5.01 0.98


Reconciliation of Company gross reserves by principal product type
- forecast prices and costs

LIGHT AND MEDIUM OIL HEAVY OIL
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Gross Gross
Proved Proved
Gross Gross Plus Gross Gross Plus
Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
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December 31, 2009 12,857 13,239 26,096 7,660 6,064 13,725

Extensions 306 801 1,107 73 87 160
Improved Recovery 0 0 0 0 0 0
Technical Revisions (658) (644) (1,302) (333) (312) (646)
Discoveries 0 0 0 0 0 0
Acquisitions 165 67 232 0 0 0
Dispositions (6,363) (5,070) (11,433) 0 0 0
Economic Factors (25) (8) (33) 41 34 74
Production (1,040) 0 (1,040) (409) 0 (409)
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December 31, 2010 5,242 8,386 13,628 7,032 5,873 12,905
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NATURAL GAS LIQUIDS NATURAL GAS
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Gross Gross
Proved Proved
Gross Gross Plus Gross Gross Plus
Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf)
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December 31, 2009 1,619 1,185 2,805 163,965 87,584 251,549

Extensions 25 34 59 6,649 6,713 13,362
Improved Recovery 0 0 0 0 0 0
Technical Revisions (34) (82) (116) 1,084 (6,776) (5,692)
Discoveries 0 0 0 0 0 0
Acquisitions 1 0 1 132 53 185
Dispositions (517) (399) (916) (6,771) (6,056) (12,827)
Economic Factors (30) (7) (37) (6,516) (1,787) (8,303)
Production (172) 0 (172) (22,576) 0 (22,576)
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December 31, 2010 891 731 1,622 135,967 79,731 215,698
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TOTAL
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Gross
Proved
Gross Gross Plus
Proved Probable Probable
FACTORS (MBOE) (MBOE) (MBOE)
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December 31, 2009 49,464 35,086 84,550

Extensions 1,512 2,041 3,553
Improved Recovery 0 0 0
Technical Revisions (844) (2,168) (3,012)
Discoveries 0 0 0
Acquisitions 188 76 264
Dispositions (8,009) (6,479) (14,487)
Economic Factors (1,101) (278) (1,379)
Production (5,383) 0 (5,383)
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December 31, 2010 35,827 28,278 64,105
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Finding, Development and Acquisition Costs

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Year ended Year ended
December 31, December 31, Three year
2010 2009 2008-2010
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GROSS PROVED RESERVES
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Capital expenditures -
exploration & development
($000) 127,232 106,095 506,925
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Change in future capital costs
required to develop reserves -
exploration & development ($000) 8,257 26,585 75,995
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Total capital costs - exploration
& development ($000) 135,489 132,680 582,920
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Total capital expenditures
(including acquisitions &
dispositions) ($000) 22,903 97,644 574,716
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Total change in future capital
costs required to develop
reserves (including acquisitions
& dispositions) ($000) (23,473) 26,645 65,457
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Total capital costs (including
acquisitions & dispositions) ($000) (570) 124,289 640,173
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Gross reserve additions
- exploration & development (MBOE) (434) 6,314 21,626
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Total gross reserve additions
including acquisitions &
dispositions (MBOE) (8,255) 5,956 19,239
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F&D costs, before future capital
($/BOE) (i) 16.80 23.44
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FD&A costs, before future capital
($/BOE) (i) 16.40 29.87
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F&D costs, including future
capital ($/BOE) (i) 21.01 26.95
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FD&A costs, including future
capital ($/BOE) (i) 20.87 33.28
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Operating netback ($/BOE)
(unaudited) 23.47 21.08 28.97
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Recycle ratio (operating netback/F&D) (i) 1.0 1.1
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Recycle ratio (operating netback/FD&A) (i) 1.0 0.9
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GROSS PROVED PLUS PROBABLE RESERVES
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Capital expenditures - exploration
& development ($000) 127,232 106,095 506,925
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Change in future capital costs
required to develop reserves -
exploration & development ($000) 9,473 84,149 148,832
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Total capital costs - exploration
& development ($000) 136,705 190,244 655,757
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Capital expenditures (including
acquisitions & dispositions) ($000) 22,903 97,644 574,716
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Change in future capital costs
required to develop reserves
(including acquisitions &
dispositions) ($000) (33,548) 85,459 156,582
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Total capital costs (including
acquisitions & dispositions) ($000) (10,645) 183,103 731,298
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Gross reserve additions (MBOE) (839) 10,388 28,434
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Gross reserve additions, including
acquisitions & dispositions (MBOE) (15,063) 9,923 22,128
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F&D costs, before future capital
($/BOE) (i) 10.21 17.83
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FD&A costs, before future capital
($/BOE) (i) 9.84 25.97
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F&D costs, including future capital
($/BOE) (i) 18.31 23.06
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FD&A costs, including future capital
($/BOE) (i) 18.45 33.05
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Operating netback ($/BOE) (unaudited) 23.47 21.08 28.97
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Recycle ratio (operating netback/F&D) (i) 1.1 1.3
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Recycle ratio (operating netback/FD&A) (i) 1.1 0.9
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(1) The aggregate of exploration and development costs incurred in the most
recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
(2) The Corporation calculates finding, development and acquisition ("FD&A")
costs which incorporate both the costs and associated reserve additions
related to acquisitions net of any dispositions during the year. Since
the acquisitions can have a significant impact on the Corporation's
annual reserve replacement costs, Galleon believes that FD&A costs
provide a more meaningful portrayal of Galleon's cost structure.
(3) Operating netbacks per BOE are calculated by subtracting royalties and
operating and transportation costs from revenues including realized
financial derivatives and dividing the result by average production for
the period.
(4) Certain financial figures include information based on estimated
unaudited financial results that may change on the completion of the
audited financial statements.
(i) Due to the magnitude of the asset disposition that occurred in June,
2010, the one year FD&A is not meaningful in terms of reserve additions
versus capital spent. Due to the large proportion of drills that were
previously booked as undeveloped locations, the one year F&D is not
separately reported. For both FD&A and F&D, the 2010 values are included
in the three-year calculations presented above.


FD&A in 2010 was heavily influenced by the major property disposition that occurred during the year. The Corporation's strategy for the second half of 2010 was to convert reserves from undeveloped to developed categories. This activity was, therefore, not expected to result in significant proved or proved and probable reserve additions.

At December 31, 2010, future development capital was $176.3 million for gross proved reserves and $363.0 million for gross proved plus probable reserves. Components of the future capital for gross proved plus probable reserves include 2011 - $45.4 million (28.6 net wells), 2012 - $124.3 million (96.4 net wells), 2013 - $65.6 million (46.9 net wells) and thereafter $127.7 million (approximately 108.1 net wells). Note that capital for the first quarter of 2011 includes expenditures that will be eligible for Alberta Crown drilling credits. At December 31, 2009, future development capital was $199.7 million for gross proved reserves and $396.5 million for gross proved plus probable reserves.



Net Asset Value
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December 31, 2010 December 31, 2010
forecast prices forecast prices
8% discount rate 10% discount rate
($MM) ($MM)
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Net present value of future revenues of
reserves, discounted, before tax (1) 1,001.7 904.9
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Undeveloped land (2) 43.4 43.4
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Bank debt (3) (135.7) (135.7)
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Working capital deficiency (3) (17.2) (17.2)
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Net asset value 892.2 795.4
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Basic common shares outstanding (000's) 84.0 84.0
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Net asset value per share ($/share) 10.62 9.47
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(1) Derived from the DeGolyer Report.
(2) Based on an independent evaluation prepared by Seaton-Jordan &
Associates Ltd. effective December 31, 2010. The values in the
evaluation were based on factors including actual cost of the land to
the Corporation, recent land sales, recent farm-in agreements and work
commitments related to the unproven property.
(3) Based on 2010 unaudited financial information that may change on
completion of the audited financial statements


Credit Facilities

The Corporation has credit facilities of $250 million in place with a bank syndicate comprised of four banks. An annual review is scheduled to occur on or before May 28, 2011. At December 31, 2010, an amount of $135.7 million was drawn under these credit facilities.



Hedging Activity

At March 3, 2011, the Corporation has the following financial contracts in
place:

Crude oil:
500 Bbl/day $92.00 WTI CAD Jan 1/11-Dec 31/11
1,000 Bbl/day $85.00 WTI USD CALL Jan 1/12-Dec 31/12
1,100 Bbl/day $85.00 WTI USD SWAPTION Jan 1/12-Dec 31/12
527 Bbl/day $85.00 WTI USD CALL Jan 1/12-Dec 31/12
1,000 Bbl/day $84.15 WTI CAD Jan 1/11-Dec 31/11
1,000 Bbl/day $77.10 WTI CAD - $90 WTI CAD Jan 1/11-Dec 31/11

Natural gas:
5,000 GJs/day $5.75 GJ CDN Jan 1/10-Dec 31/11
5,000 GJs/day $5.85 GJ CDN Jan 1/10-Dec 31/11
5,000 GJs/day $5.76 GJ CDN Apr 1/10-Mar 31/11
5,000 GJs/day $5.60 GJ CDN Apr 1/11-Dec 31/11
10,000 GJs/day $5.20 GJ CDN Jan 1/11-Dec 31/11
10,000 GJs/day $5.20 GJ CDN Jan 1/11-Dec 31/11


Galleon has approximately 83.9 million shares issued and outstanding which trade on the TSX under the symbol "GO".

Galleon is scheduled to release 2010 audited financial results on or about March 10, 2011. Additional reserve disclosure tables, required under NI 51-101, will be contained in the Annual Information Form expected to be filed on SEDAR before March 31, 2011.

ADVISORIES:

Certain information regarding Galleon in this news release including management's assessment of future plans and operations may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and reserve estimates of Galleon's reserves provided herein are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect Galleon's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Galleon's website (www.galleonenergy.com). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and Galleon does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

All evaluations and reviews of future net revenues are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimates of future net revenues presented in the tables herein represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, natural gas and natural gas liquids reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Certain financial and operating information included in this news release for the period ended December 31, 2010, such as finding and development costs, acquisition costs, production information, recycle ratios, operating netbacks and net asset value, are based on estimated unaudited financial results for the period then ended, and are subject to the same limitations as discussed in this advisory. These estimated amounts may change upon completion of the audited financial statements for the year ended December 31, 2010 and the changes could be material.

Disclosure provided herein in respect of barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Contact Information

  • Galleon Energy Inc.
    Steve Sugianto
    President and Chief Executive Officer
    (403) 261-6012
    or
    Galleon Energy Inc.
    Glenn R. Carley
    Executive Chairman
    (403) 261-6012
    or
    Galleon Energy Inc.
    Shivon Crabtree
    Vice President and Chief Financial Officer
    (403) 261-6012
    www.galleonenergy.com