Galleon continues to grow its Montney resource portfolio with focus on cost effectiveness and announces Q1 2009 financial results

    CALGARY, May 14 /CNW/ - Galleon Energy Inc. (TSX: GO) ("Galleon" or the
Corporation") announces first quarter 2009 financial and operational results.


    -   Drilled 11 wells in Q1 2009: 7 (7 net) Eastern Montney gas wells,
        1 (0.9 net) Central Montney gas well, 1 (1.0 net) Puskwa oil well,
        1 (1.0 net) light oil resource stratigraphic test and 1 (0.1 net)
        non- operated gas well. All wells were cased for production with the
        exception of the light oil resource stratigraphic test. This well
        was drilled as a control point for an upcoming horizontal multi-
        fractured well and was abandoned.
    -   During Q1 2009, one of Galleon's 3 light oil resource plays was
        advanced by drilling a stratigraphic test from which a horizontal
        multi-fractured well will be drilled later in the 2009.
    -   Average production from the Montney resource projects rose to
        approximately 8,000 BOE/d (with another 1,000 BOE/d behind pipe) in
        Q1 2009 which represents an increase of 7,800 BOE/d from Q3 2005
        average production of 200 BOE/d from these projects.
    -   In Q1 2009, Galleon received down spacing approvals for (i) 4 wells
        per section on 73 sections of land in the core Eastern Montney
        fairway; (ii) 4 wells per section per Montney zone on 2 sections of
        land in the Central Montney No. 2 project; and (iii) 8 wells per
        section on 6 sections of land at Puskwa.
    -   Galleon has only reserve assignments on a fraction of its Montney
        lands. In the Eastern Montney project, reserves have been assigned on
        72 sections (69.9 net) of land. Galleon's landholdings extend to over
        220 sections in the Eastern Montney core fairway and another
        380 sections along the Montney trend.
    -   In the Central Montney projects, 10 sections in a fairway of
        320 Galleon owned sections had reserves assigned to them in the
        December 31, 2008 reserve evaluation.

    FINANCIAL AND OPERATING HIGHLIGHTS           Three months ended March 31
    ($000s except per share and per BOE amounts)              2009      2008

      Revenue before royalties and financial
       derivatives                                          56,987   101,516
      Funds flow from operations(1)                         26,150    55,445
        Per share - basic                                     0.35      0.83
        Per share - diluted                                   0.35      0.81
      Net income (loss)                                     (5,091)   10,417
        Per share - basic                                    (0.07)     0.16
        Per share - diluted                                  (0.07)     0.15

      Capital expenditures - exploration &
       development                                          30,391    71,326
      Total assets                                       1,158,329   975,911
      Net debt(2)                                          284,001   260,558
      Shareholders' equity                                 686,170   539,296

      Weighted average shares outstanding (million)
        Basic                                                 75.2      67.0
        Diluted                                               75.2      68.6

      Average daily production
      Light oil (Bbl/d)                                      4,695     4,871
      Heavy oil (Bbl/d)                                        979     2,919
      NGLs (Bbl/d)                                             687       441
      Natural gas (Mcf/d)                                   69,632    52,644
      Total (BOE/d)                                         17,965    17,005

      Average selling prices(3)
      Light oil ($/Bbl)                                      46.74     94.04
      Heavy oil ($/Bbl)                                      33.91     60.95
      NGLs ($/Bbl)                                           34.07     61.02
      Natural gas ($/Mcf)                                     5.13      7.98
      Total (BOE/d)                                          35.24     65.60
    (1) See "Non-GAAP Measurements"
    (2) Net debt includes bank indebtedness, working capital and capital
        leases, but excludes financial derivatives.
    (3) The average prices reported are before realized derivatives and
        transportation charges.

    Results of Operations

    Comparative financial results for the quarter are as follows:

    Three months ended March 31                 2009                    2008
                                       1,616,979 BOE           1,547,476 BOE
    ($000s)                                    $/BOE                   $/BOE
    Revenues                     56,987        35.24    101,516        65.60
    Realized gain (loss) on
     financial derivatives        4,337         2.68     (3,361)       (2.18)
    Other income                    672         0.42        123         0.08
    Royalties                   (15,577)       (9.63)   (20,668)      (13.36)
    GCA(1)                        5,225         3.23      2,423         1.57
    Transportation costs         (2,342)       (1.45)    (1,615)       (1.04)
    Operating costs             (17,297)      (10.70)   (17,460)      (11.28)
    Net                          32,005        19.79     60,958        39.39
    G&A                          (4,201)       (2.60)    (2,371)       (1.53)
    Interest costs               (1,585)       (0.98)    (2,803)       (1.81)
    Capital and other taxes         (69)       (0.04)      (339)       (0.22)
    Funds from operations(2)     26,150        16.17     55,445        35.83
    (1) GCA means Gas Cost Allowance
    (2) See "Non-GAAP Measurements"

    Petroleum and Natural Gas Revenues
    Three months ended March 31                     2009                2008
    ($000s)                                            %                   %
    Light oil                           19,663        35    46,858        46
    Heavy oil                            2,989         5    13,887        14
    NGLs                                 2,105         4     2,452         2
    Natural gas                         32,007        56    38,181        38
    Royalty income                         223         -       138         -
    Total                               56,987       100   101,516       100

    Revenues for the three months ended March 31, 2009 decreased by 44% to
$57.0 million from $101.5 million for the same period of the prior year. This
decrease is primarily due to a 48% decrease in oil prices and a 36% decrease
in natural gas prices. A shift in the product mix towards natural gas was made
in the second half of 2008 and as a result, on a volume basis, the oil and
liquids to natural gas production ratio for the first quarter of 2009 was 35%
to 65% compared to a ratio of 48% to 52% in the prior year.
    In the first quarter of 2009, on a revenue basis, oil and liquids
generated 44% of revenues compared to 62% in the same period of the prior


    Three months ended March 31                     2009                2008
                                         BOE/d         %     BOE/d         %
    Light oil (Bbls/d)                   4,695        26     4,871        29
    Heavy oil (Bbls/d)                     979         5     2,919        17
    NGLs (Bbls/d)                          687         4       441         2
    Natural gas (Mcf/d)                 69,632        65    52,644        52
    BOE/d (6:1)                         17,965       100    17,005       100

    Average production was 17,965 BOE/d for the first quarter of 2009, 6%
higher than the average production of 17,005 BOE/d in first quarter 2008. By
product, production volume varied as follows: light oil production decreased
by 4%, heavy oil production decreased by 66%, natural gas volumes increased by
32% and natural gas liquids volumes increased by 56%. Overall production
growth has been impacted by a number of factors: the typical high flush
production decline in McLean Creek/Culp/Kimiwan high volume oil; backing out
existing Eastern Montney gas due to high pressure horizontal production;
behind pipe production waiting on facilities; and the loss of heavy oil
volumes in 2008.
    Light oil production in Q1 2009 decreased by 4% compared to Q1 2008 as a
function of a corporate shift toward natural gas resource drilling. Puskwa
production has remained stable and is currently producing at approximately
2,500 BOE/d. Fewer light oil wells have been drilled in the fourth quarter of
2008, and, as a result, production from the flush, high decline phase of
existing wells has not been replaced. The well declines have now flattened off
and rates of decline going forward are expected to be reduced.
    Natural gas volumes have increased as a result of the natural gas
resource brought on production in the last half of 2008 in the Central Montney
project as well as the production additions realized from horizontal drilling
and multi-stage fracture technology in the Eastern Montney project. Galleon
currently produces over 8,000 BOE/d of resource gas (not including NGL
volumes) with an additional 1,200 BOE/d behind pipe waiting on facility
expansion. This production compares with 200 BOE/d in Q3 2005 and 4,000 BOE/d
in Q1 2008. The Eastern and Central Montney projects have been responsible for
this growth and have also made significant additions to Galleon's proved plus
probable reserves.
    Heavy oil production suffered a set back in Q2 2008 with a number of
wells not recovering their production rates after being shut in during spring
breakup. This heavy oil production could only be recovered with new drilling,
which is not practical given the reduced heavy oil prices. Current heavy oil
production levels remain stable, but at lower levels.

    Commodity Pricing and Marketing

    Petroleum products are sold to major Canadian marketers at spot reference
prices or prices subject to commodity contracts based on US WTI for crude oil
and AECO for natural gas. As a means of managing the risk of commodity price
volatility, Galleon has entered into several natural gas and crude oil
financial contracts.
    As at March 31, 2009, the Corporation had entered into the following
financial contracts:

    Natural gas
    January 1, 2009 - June 30, 2009          5,000 GJ/d         CDN $6.00/GJ
    January 1, 2009 - June 30, 2009          5,000 GJ/d         CDN $6.00/GJ
    March 1, 2009 - March 31, 2010           5,000 GJ/d         CDN $5.96/GJ
    March 1, 2009 - March 31, 2010           5,000 GJ/d         CDN $6.01/GJ
    April 1, 2009 - October 31, 2009         5,000 GJ/d         CDN $7.40/GJ

    Crude Oil
    Fixed Price:
    March 1, 2009 - December                1,000 Bbl/d   WTI CDN $68.25/Bbl
    February 1, 2009 - December 31, 2009      500 Bbl/d   WTI CDN $63.30/Bbl
    February 1, 2009 - December 31, 2009      500 Bbl/d   WTI CDN $63.85/Bbl
    April 1, 2009 - December 31, 2009         500 Bbl/d   WTI CDN $70.15/Bbl
    Costless Collar:
    March 1, 2009 - December 31, 2009         500 Bbl/d   WTI CDN $60.00-

    In the first quarter of 2009, Galleon recorded realized gains of $1.3
million on these contracts. In March, the April 1 to October 31, 2009 natural
gas contract was unwound, which resulted in an additional realized gain of
$3.0 million.
    Subsequent to March 31, 2009, Galleon has entered into the following
financial contracts:

    Crude Oil
    Fixed Price:
    May 1, 2009 - December 31, 2009           500 Bbl/d   WTI CDN $72.00/Bbl
    January 1, 2010 - December 31, 2010       500 Bbl/d   WTI CDN $74.30/Bbl
    January 1, 2010 - December 31, 2010       500 Bbl/d   WTI CDN $74.50/Bbl
    January 1, 2010 - December 31, 2010       500 Bbl/d   WTI CDN $76.25/Bbl
    January 1, 2010 - December 31, 2010       500 Bbl/d   WTI CDN $76.50/Bbl
    January 1, 2010 - December 31, 2010       500 Bbl/d   WTI CDN $77.00/Bbl
    January 1, 2010 - December 31, 2010       500 Bbl/d   WTI CDN $77.00/Bbl

    Prices - prior to realized gains or losses on financial contracts and
     prior to transportation

    Three months ended March 31                               2009      2008
    Light oil ($/Bbl)                                        46.74     94.04
    Heavy oil ($/Bbl)                                        33.91     60.95
    Natural gas ($/Mcf)                                       5.13      7.98
    NGLs ($/Bbl)                                             34.07     61.02

    Light oil prices decreased by 50% to $46.74/Bbl, excluding the loss
incurred from the crude oil costless collars. Average heavy oil prices of
$33.91/Bbl decreased by 44% from the same period of the prior year. Average
natural gas prices of $5.13/Mcf decreased by 36% from the first quarter of

    Crude Oil Prices

    Three months ended March 31                     2009                2008
                                             $     $/Bbl         $     $/Bbl
    Crude oil                           22,740     44.53    60,813     85.79
    Realized financial contracts           217      0.42    (3,361)    (4.74)
    Transportation                        (557)    (1.09)     (390)    (0.55)
    Net crude oil                       22,400     43.86    57,062     80.50

    Natural Gas Prices

    Three months ended March 31                     2009                2008
                                             $     $/Mcf         $     $/Mcf
    Natural gas                         32,142      5.13    38,251      7.98
    Realized financial contracts         4,120      0.66         -         -
    Transportation                      (1,785)    (0.28)   (1,225)    (0.26)
    Net natural gas                     34,477      5.51    37,026      7.72

    Performance by Property

    Three months ended March 31

                             2009                  2008              2009
    ------------------------------------- ---------------------

                                Operating             Operating
                                netbacks/             netbacks/  Funds from
                     Production   BOE(1)   Production   BOE(1)  operations(2)
                      BOE/d     %       $   BOE/d     %       $            %
    Eastern Montney   4,439    25   14.77   3,872    23   33.03           27
    Eaglesham         2,959    16   17.77   2,973    17   45.39           22
    Puskwa            2,395    13   24.54   2,704    16   56.97           24
    Kakut             2,356    13   17.79     429     3   33.40           17
    Alexis/St.Anne    1,042     6    8.82     978     6   32.38            4
    Culp/Kimiwan        700     4   12.20     815     5   56.71            4
    Edam                609     3   (3.76)  1,803    11   24.47            -
    Other             3,465    20    2.38   3,431    19   38.58            2
                     17,965   100   13.50  17,005   100   40.32          100
    (1) Operating netbacks/BOE excludes GCA and are calculated by subtracting
        royalties and operating costs from revenues.
    (2) See "Non-GAAP Measurements".

    Eastern Montney production increased by 15% to an average of 4,439 BOE/d
(88% natural gas and 12% oil and liquids) during Q1 2009 compared to 3,872
BOE/d in Q1 2008. The Eastern Montney natural gas project represents a
significant resource to Galleon and is currently the largest producing area
contributing 27% to total funds from operating activities in Q1 2009 based on
25% of production volumes. The operating netbacks of $14.77/BOE have decreased
by 55% from Q1 2008 mainly due to significantly weaker natural gas prices.
    In the first quarter of 2009, Galleon successfully drilled seven (100%
working interest) Eastern Montney horizontal multi-fractured wells. Five of
the seven wells, on average, tested over a 48 hour flow period in excess of 1
Mmcf/d and concurrently produced oil and water as is typical of the zone. Six
of the seven wells were drilled from 2 well pads. Galleon plans to continue
utilizing pad drilling as the pool continues to be developed thereby reducing
tie in costs. The production data continues to suggest horizontal wells have a
higher production profile (2 to 3 times better) and lower initial production
decline rates than the vertical wells previously being drilled in this area.
To date, the economics of the horizontal wells have proven to be better than
the vertical wells on both a rate of return and reserve optimization basis.
Galleon has delineated a gas charged fairway with vertical well control that
is 35 miles long by 12 miles wide. Based on vertical well control and geologic
mapping Galleon has identified 350 horizontal drilling locations on over 200
sections of owned land within the delineated Eastern Montney fairway.
    Average production at Eaglesham in the first quarter 2009 averaged 2,959
BOE/d (75% natural gas and 25% oil and liquids) making it the second largest
producing property. Eaglesham contributed 22% of the first quarter 2009 funds
from operations from 16% of production. The operating netback of $17.77/BOE
has decreased by 61% compared to $45.39/BOE in the same period prior year as a
result of significantly weaker commodity prices.
    The Montney is a new and unique project in the Eaglesham area with up to
seven natural gas charged Montney sands identified. To date, four sands have
been tested of which two of these are contributing to current production. The
remaining two sands are not on production as the sulphur content exceeds the
plant specifications. The Montney has shown significant growth at Eaglesham
during Q4 2008 and Q1 2009. One horizontal multi-fractured well (90% working
interest) was drilled into a mid Montney member in Q1 2009. The initial
production from this well was 3.5 Mmcf/d with 10 Bbl per million cubic feet of
natural gas liquids. The well cost was $1.6 million including tie in costs.
Current aggregate production is 7 Mmcf/d from the Montney wells. There are no
facility constraints in this area.
    At Puskwa, average production for Q1 2009 was 2,395 BOE/d (83% oil and
liquids and 17% natural gas) contributing 24% of Q1 2009 funds from operations
from 13% of total production. Operating netbacks of $24.54/BOE decreased by
57% compared to Q1 2008 due to the drastic drop in oil prices and to an
increase in royalty rates as a result of the Alberta New Royalty Program
("NRF"). Production levels decreased by 11% compared to Q1 2008. This decrease
was due to some down time on an injection well in the pool, which resulted in
reduced oil production in order to maintain a one to one voidage replacement.
The Puskwa project is now in the development stage with the implementation of
two enhanced recovery schemes. In Q1 2009, approval was received for 80 acre
down spacing on six Galleon sections, which allows 8 wells per section. During
first quarter 2009, Galleon successfully drilled a Beaverhill Lake light oil
well (100% working interest) at Puskwa. This was the first well drilled on the
approved 80 acre down spacing. This well flowed oil at 550 BOE/d and natural
gas at 1.2 Mmcf/d over a 62 hour test period. It is anticipated that the well
will initially be brought on production at approximately 400 BOE/d.
    Production at Puskwa will be managed to target 2,500 BOE/d with minor
quarterly variations as a function of maintaining a one to one injection to
production ratio. The focus has been on increasing water injection to maintain
this one to one voidage replacement ratio. One well was drilled for this
purpose in Q3 2008 and a second well was converted into an injection well in
Q1 2009. Wells such as these with low costs provide a low risk method of
increasing production by allowing an incremental increase in oil production
for every barrel of water injected. Additional activity will be dictated by
commodity prices, but as many as two more wells may be drilled at Puskwa over
the remainder of 2009. One of these will likely be a water injection well as
optimization of the water flood continues to be an ongoing project.
    Kakut production increased by 449% in the first quarter 2009 compared to
the same period of 2008 and contributed 13% of total production in Q1 2009.
The operating netback was $17.79/BOE in Q1 2009, a decrease of 47% compared to
Q1 2008 as a result of much lower commodity prices.


    Three months ended March 31                               2009      2008
    ($000s) except as indicated
    Crown                                                   13,839    18,563
    Freehold                                                   647       454
    GORR and other                                           1,091     1,651
    Subtotal                                                15,577    20,668
    GCA                                                     (5,225)   (2,423)
    Net royalties                                           10,352    18,245
    % of revenue                                              27.3      20.4
    % of revenue net of GCA                                   18.2      18.0

    Gross royalties were 27.3% of revenues for the first quarter of 2009
compared to 20.4% for the same period in 2008. By product, gross royalties
were 25.8% for light oil, 29.7% for natural gas, 11.2% for heavy oil, and
22.7% for liquids. For the first quarter of 2008, gross royalties were 15.4%
for light oil, 24.7% for natural gas, 22.7% for heavy oil, and 28.1% for
    Net royalties were 18.2% for the first quarter of 2009 compared to 18.0%
for the same period in 2008. Galleon's Q1 2009 corporate net royalty rate as a
percentage of revenue is 9.1% lower than the gross royalty rate due to a
significant GCA credit received in Q1 2009 for eligible capital expenditures
and capital retirement relating to prior periods.
    Gross royalties for light oil as a percentage of light oil revenue
increased by 10.4% in Q1 2009 mainly due to a reduced number of light oil
wells qualifying for a royalty holiday in the first quarter 2009 compared to
Q1 2008. Most royalty holiday incentives in Alberta were terminated December
31, 2008 with the implementation of the NRF. Under the NRF oil royalty
calculations are substantially based on par price. In the first quarter of
2009, January par price was significantly higher than the par prices for
February and March. Light oil royalties for January were 31.7% of light oil
revenues compared to light oil royalties in March of 20.8% of light oil
revenues. This also contributed to the increased royalty rate in Q1 2009.
    Gross royalties for natural gas as a percentage of natural gas revenue
increased by 5% for Q1 2009 compared to the same period in Q1 2008 due to an
increase in natural gas royalty rates under the NFR and to an over accrual of
natural gas royalty credits in Q4 2008 relating to prior periods.
    Gross royalties for heavy oil as a percentage of heavy oil revenue
decreased by 11.5% as a result of the reduced production volumes and lower
heavy oil prices in Q1 2009 compared to Q1 2008.
    Gross royalties for liquids as a percentage of liquids revenue decreased
by 5.4% in Q1 2009 compared to Q1 2008 as a function of reduced commodity

    Operating Costs

    Three months ended March 31                               2009
                                                         Operating Operating
                                              Production     Costs     Costs
                                                       %         %     $/BOE
    Eastern Montney                                   25        16      7.14
    Eaglesham                                         16        10      6.17
    Puskwa                                            13         5      3.97
    Kakut                                             13         5      4.17
    Alexis/St.Anne                                     6         8     15.16
    Culp/Kimiwan                                       4         9     24.78
    Edam                                               3         9     28.39
    Other                                             20        38     20.91
                                                     100       100     10.70

    Three months ended March 31                               2008
                                                         Operating Operating
                                              Production     Costs     Costs
                                                       %         %     $/BOE
    Eastern Montney                                   23        11      5.35
    Eaglesham                                         17        11      7.33
    Puskwa                                            16        13      9.00
    Kakut                                              3         2      8.01
    Alexis/St.Anne                                     6         5      9.09
    Culp/Kimiwan                                       5         9     21.87
    Edam                                              11        20     21.53
    Other                                             19        29     16.34
                                                     100       100     11.28

    Operating costs were $17.3 million or $10.70/BOE for the first quarter of
2009 compared to $17.5 million or $11.28/BOE for the same period of the prior
year. This represents a decrease year over year of 5% on a per unit basis.
    In the Eastern Montney natural gas project, operating costs were
$7.14/BOE in Q1 2009 compared to $5.35/BOE in the same period prior year.
Operating cost increases in Q1 2009 compared to Q1 2008 were related to
emulsion trucking, water trucking and equipment rentals associated with the
increased emulsion storage requirements. In addition, operating costs of
approximately $1.00/BOE were recorded in Q1 2009 related to prior periods.
Operating costs are expected to average between $6.00/BOE and $7.00/BOE in
2009 in this area.
    Eaglesham operating costs for Q1 2009 were $6.17/BOE a decrease of 16%
compared to $7.33/BOE in first quarter 2008. Decreased operating costs in Q1
2009 compared to Q1 2008 are mainly due to the Eaglesham oil battery coming on
production with an increased ability to handle emulsion. With the oil battery
coming on production, emulsion processing was eliminated and emulsion trucking
costs were significantly reduced. Operating costs at Eaglesham are expected to
reduce further in 2009, with the installation of electricity at the plant and
well sites.
    Operating costs at Puskwa were $3.97/BOE in first quarter 2009 compared
to $9.00/BOE in the same period of 2008. Operating costs were higher in Q1
2008 due to the expansion of the water flood operations which resulted in
temporary water trucking and pump equipment rental costs which have now been
largely eliminated.
    Operating costs at Kakut were $4.17/BOE in Q1 2009 a decrease of 48%
compared to $8.01 in the same period prior year. Due to production increases,
the natural gas plant was expanded in Q4 2008 which resulted in significantly
lower operating costs on a per BOE basis.

    General and Administration Expenses

    Three months ended March 31                     2009                2008
    ($000s)                                        $/BOE               $/BOE
    Gross                                5,505      3.40     3,884      2.51
    Capitalized overhead                  (798)    (0.49)   (1,209)    (0.78)
    Overhead recoveries                   (506)    (0.31)     (304)    (0.20)
    Net                                  4,201      2.60     2,371      1.53

    Gross G&A expenses have increased from Q1 2008 due to the growth of the
Corporation. Office rent and salaries have increased during the past year as a
result of the growth. Gross G&A expenses per barrel of oil equivalent have
increased by 35%.
    Capitalized overhead has decreased year over year due to reduced capital
in Q1 2009. Net general and administrative (G&A) expenses of $2.60/BOE for the
first quarter of 2009 increased by 70% compared to the same period of the
previous year.
    For the three months ended March 31, 2009 G&A expenses by category were:
salary and employee - 52%, office - 22%, consulting - 9%, computer - 9%,
shareholder costs - 1%, audit, engineering and legal - 6%, and corporate - 1%.


    Interest expense of $1.6 million for the three months ended March 31,
2009 was 43% lower than in the same period of the prior year due to lower
interest rates charged on bank credit facilities being approximately 50% lower
than in the prior year. At March 31, 2009 an amount of $263.6 million was
drawn against the Corporation's credit facilities compared to $229.9 million
in the same period prior year.

    Stock Based Compensation

    Stock based compensation was a non-cash expense of $1.3 million for the
first quarter of 2009 compared to $2.8 million in the same quarter of the
prior year. During the first quarter of 2009, 120,000 stock options were
granted to employees at an average exercise price of $3.45, having fair values
of $1.18 per option.
    At March 31, 2009, 6,901,068 stock options were outstanding at an average
exercise price of $11.94.

    Depletion, Depreciation and Accretion

    Depletion and depreciation ("D&D") charges were $35.5 million or
$21.97/BOE for the three months ended March 31, 2009 compared to $33.6 million
or $21.73/BOE for the same period of the prior year. Reserve additions for the
first quarter of 2009 were estimated internally.
    Capital expenditures of $104.6 million ($103.5 million - March 31, 2008)
related to undeveloped land and seismic have been excluded from the depletion
and depreciation calculation and $161.9 million ($114.9 million - March 31,
2008) of future development costs have been added.
    Accretion expense on the Corporation's asset retirement obligation was
$659,000 for the first quarter of 2009 compared to $568,000 in the same
quarter of the prior year. The increase related to a greater asset retirement
obligation which is driven by the number of wells and facilities in which
Galleon has an interest.

    Capital and Future Taxes

    The current tax provision of $69,000 for the first quarter was comprised
of Saskatchewan capital and resource taxes, as was the provision for the first
quarter of 2008. The provision is calculated based on revenues earned in
Saskatchewan. It is not expected that Galleon will pay any income taxes in
    The provision for future income taxes was a recovery of $1.5 million for
the first quarter of 2009 compared to a tax provision of $3.1 million for the
first quarter of the prior year. The future tax recovery is a result of a net
loss recorded in the first quarter of 2009 compared with net earnings recorded
in the first quarter of 2008.

    Capital Expenditures

    Property & equipment balance at December 31, 2008              1,071,150
    Additions to property and equipment                               30,391
    Asset retirement obligation additions                                476
    Depletion and depreciation                                       (35,530)
    Property & equipment balance at March 31, 2009                 1,066,487

    Three months ended March 31                     2009                2008
    ($000s)                                       %                   %
    Land                                   778         3     2,039         3
    Geological and geophysical           1,055         3     5,353         8
    Drilling and completion             21,545        71    44,393        62
    Plant and facilities                 6,969        23    19,408        27
    Other assets                            44         -       133         -
    Exploration and Development
     Expenditures                       30,391       100    71,326       100

    Exploration and development expenditures during the first quarter of 2009
were $30.4 million. Drilling and completions expenditures comprised 71% of
exploration and development activity. Galleon drilled 11 gross wells resulting
in 9 (8.0 net) natural gas wells and 1 (1.0 net) light oil wells for a success
rate of 91% for the quarter.
    Facilities expenditures were $7.0 million in Q1 2009 or 23% of total
expenditures. Land and seismic expenditures totaled $0.8 million and $1.1
million, respectively in the first quarter 2009. Due to the substantially
lower commodity prices to date in 2009, Galleon's capital expenditure program
has been modified to a level which is expected to match funds from operations.
The Corporation does not plan to fund the capital program with incremental
bank debt.

    Liquidity and Capital Resources

    Three months ended March 31                               2009      2008
    Bank debt                                              263,619   229,865
    Capital leases - non current                             1,337     3,091
    Working capital deficiency                              19,045    27,602
    Total net debt                                         284,001   260,558

    Funding of Capital Program

    Three months ended March 31                               2009      2008
    Issuance of shares, net of costs                           458     1,746
    Funds from operations                                   26,150    55,445
    Change in bank debt                                     14,604    20,205
    Change in capital leases                                  (204)     (484)
    Change in working capital and other                    (10,617)   (5,586)
                                                            30,391    71,326

    At March 31, 2009, the Corporation has extendible revolving term credit
facilities of $310 million in place with a bank syndicate. Collateral for the
facilities consists of a demand debenture for $500 million collateralized by a
first floating charge over all of the property and equipment of the
Corporation. At March 31, 2009, an amount of $263.6 million was drawn against
the credit facilities (March 31, 2008 - $229.9 million). An annual review of
the credit facilities is scheduled to be completed prior to May 31, 2009.
    An annual review of the credit facilities is scheduled to be completed
prior to May 31, 2009. The level of the borrowing base will be determined by
the bank syndicate based on their review of, among other things, a review of
the Corporation's reserves and the value thereof utilizing commodity prices
determined by the bank syndicate, which will be different than that utilized
by the Corporation's independent reserve evaluator.


    During first quarter 2009, 11 wells were drilled and capital expenditures
totaled $30.4 million. This compares to 32 wells drilled in first quarter 2008
and $71.3 million spent on exploration and development activities. The first
quarter 2009 capital program was kept to within cash flow. The projects
selected in 2009 must provide superior cost effectiveness from a production
deliverability perspective as well as a reserves perspective.

    Eastern Montney
    The Eastern Montney is slowly gaining recognition as being a premium high
quality asset. Galleon's 2008 reserves evaluation at December 31, 2008
attributed proved plus probable gross gas reserves of 112 BCF to this area, an
increase of 79% compared to the December 31, 2007 reserves assignment of 63
Bcf. The reserve additions were attributable to horizontal well performance
and the extended production history of the existing verticals. Incremental
reserves are expected to result from new wells drilled on both developed and
undeveloped lands and also from extended production history on the existing
horizontal wells. Reserves booked to December 31, 2008 related to wells
drilled throughout 72 sections (69.9 net) of land. There are another 140 gross
sections of Galleon lands in the Eastern Montney core that have no reserves
assigned to them. In addition, Galleon believes that there are another 400
gross sections of land along trend that also have potential. To December 31,
2008, 59 horizontal locations have been evaluated in the Corporation's
December 31, 2008 reserve evaluation. Galleon has identified an additional 350
potential horizontal locations on the existing core lands based on vertical
well control and geologic mapping.
    The economics for the Eastern Montney project remain strong. Total well
costs, including drilling, completion and tie in costs, are approximately $1.3
million. The average annual rate of return on wells drilled to date based on
$4.50/Mcf (Cdn) is in excess of 100%. Due to these positive economics, a large
part of the Q1 2009 capital program was directed towards Eastern Montney
wells. This is expected to continue to play a major role for the remainder of
the year. Up to 25 horizontal multi-fractured wells are planned for 2009.
    Seven Montney horizontal multi-fractured wells were drilled in Q1 2009.
Each well tested in excess of 1 Mmcf/d net to Galleon in line during the test
periods. The horizontal wells typically have a high flowing pressure relative
to offset vertical producers. Accordingly, production from many of the
vertical wells has been backed out and will require field optimization in
order to be brought back on stream. Current modeling of the field is
addressing this issue and a field implementation plan is expected to commence
in the third quarter of 2009.
    To date in Q2 2009, three successful horizontal wells were drilled over
break up from one pad. Pad drilling will be more common as development of the
pool continues. This should translate to savings in drilling and tie-in costs.
Pad drilling is in part made possible by obtaining down spacing to 4 wells per
section. In Q1 2009 Galleon received approvals on 73 additional sections of
land to allow 4 wells per section.

    Central Montney
    In Q1 2009 no wells were drilled in the Central Montney project No. 1 but
the first phase of the natural gas plant expansion was completed. Production
from this project increased to 14 Mmcf/d (12 Mmcf/d net) in Q4 2008. An
additional 8 Mmcf/d (6 Mmcf/d net) is behind pipe. In September 2008 only one
well was on production at a rate of 1.6 Mmcf/d (1.2 Mmcf/d net). Production
has grown significantly in a short period of time. This strong production and
production from future wells confirmed the requirement to expand the plant
capacity to 28 Mmcf/d. The expansion has an expected completion date of early
Q4 2009. Up to two more wells are planned to be drilled in this area on trend
in 2009. Development of this project is planned using vertical wells which
have drilling, completion and tie-in costs of approximately $1.1 million. To
date, wells have produced between 1.5 Mmcf/d and 4.0 Mmcf/d per well.
    One horizontal multi-fractured well was drilled into a mid Montney zone
in the Central Montney project No.2 in Q1 2009. The drilling, completion and
tie-in costs for the well were $1.6 million. The well came on stream at an
initial flush rate of 3.5 Mmcf/d with 10 Bbls of NGLs per million cubic feet
of natural gas and is expected to stabilize at 1 to 1.5 Mmcf/d plus NGLs. Five
wells are currently producing approximately 6 Mmcf/d (5.5 Mmcf/d net) in
aggregate in this project.
    The Central Montney No. 2 project is characterized by having seven
Montney zones that are gas charged. To date four of those zones have been
tested with two producing. The other two zones have a sour component that
exceeds present plant specifications. The project provides exceptional
development drilling as down spacing to four wells per section per Montney
zone has been approved for two sections. Up to two more horizontal wells and
two more vertical wells are planned to be drilled on this project over the
remainder of 2009.

    Puskwa Beaverhill Lake light oil
    Approvals for down spacing to 80 acre spacing have been received on six
key Galleon owned sections at Puskwa. One well was drilled on the down spacing
and flowed at a rate of 550 BOE/d and 1.2mmcfd over a 62 hour test period.
This well has been on production at a rate of approximately 400 BOE/d net to
Galleon for 1 month. The well initially flowed without artificial lift but
recently has been put on pump.
    Approval for two more water injection wells was recently received at
Puskwa. These wells are required in order to maintain a one to one voidage
replacement ratio for the pool and to achieve effective optimization of the
project. Galleon plans to continue to pursue optimization throughout 2009.
Additional drilling activity will be dictated by commodity prices. Puskwa
continues to be an excellent light oil project. Net production has been stable
over the last year at approximately 2,500 BOE/d.


SOURCE EVALUATION ----------------------------------- Galleon engaged DeGolyer and MacNaughton Canada Limited ("DeGolyer"), its independent reserve evaluator, to complete an assessment of the Discovered Petroleum Initially-in-Place ("DPIIP") in Galleon's Eastern Montney Play. The Eastern Montney Play is located in the Peace River Arch area of Alberta approximately 600 km northwest of Edmonton. In a report dated May 12, 2009 and effective Dec. 31, 2008 DeGolyer estimated the DPIIP on 224 (201 net) sections of Galleon lands on its Eastern Montney Play. DeGolyer estimates that Galleon's gross working interest DPIIP attributed to these lands is 1.3 Tcf in the best case, 1.1 Tcf in the low case and 1.7 Tcf in the high case. Galleon holds interests in adjacent lands, which have not yet been assigned any DPIIP. Future activity will provide data that will help in assessing the potential of these lands. It should be noted that given the current early stage of development, these estimates, including the best case estimate of DPIIP, might change significantly in the future with further development activity and the amount of contingent resources (as defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook")) has yet to be estimated. Galleon is in the early stages of horizontal development of the Montney Play and, while management is encouraged by the results to date, additional drilling and testing is required to confirm deliverability potential and commercial economic development. The DPIIP estimates provided herein are estimates only and the actual DPIIP may be greater than or less than the estimates provided herein. The portion of the DPIIP volume that is ultimately recovered will be influenced by technical and economic factors. The recovery factor for the DPIIP identified, other than that portion classified as reserves, was not estimated by DeGolyer. As wells are added with future drilling and completions are made in previously uncompleted sections, this development may help in the quantification of the recovery factor associated with the sub-commercial component of the DPIIP which may allow for the quantification of the volumes of contingent resources at that time. There is no certainty that it will be commercially viable or technically feasible to produce any portion of this natural gas currently classified as DPIIP, other than the portion currently estimated as reserves. 2009 GUIDANCE ------------- In 2009, Galleon intends to spend within cash flow, continue to selectively hedge production and sell certain non-core assets. To date, Galleon has captured a number of significant Montney natural gas and light oil resource plays. To maximize the value of the initial flush production period of these resource plays, Galleon plans to focus the majority of the capital expenditures during the second and third quarters of 2009 towards optimizing infrastructure and increasing facility capacity. Drilling projects are anticipated to receive the largest portion of the Q4 2009 and Q1 2010 capital budget in order to take advantage of the benefits from the recently announced Alberta royalty incentive programs and to fill the expanded facility capacity when commodity prices are expected to be higher. This approach is both financially prudent and positions Galleon to quickly ramp up production when commodity prices recover. Approximately 65% of the capital program in the second and third quarters of 2009 is directed towards (i) a natural gas plant expansion in the Central Montney No.1 project (capacity will increase from 14 Mmcf/d to 28 Mmcf/d), (ii) optimizing oil recovery and lowering the pressure in gas gathering systems in the Eastern Montney project, and (iii) constructing an oil battery in the St. Anne property and initializing the waterflood project at the Alexis property. The remaining capital in the second and third quarters of 2009 is expected to be directed towards drilling wells in two light oil resource projects that Galleon believes have the potential to add significant light oil reserves and production in 2009 and 2010. Currently, Galleon plans to direct up to 90% of the fourth quarter 2009 capital program towards development drilling in the Eastern Montney project and the two Central Montney projects thereby driving gas production growth. Based on current commodity prices, Galleon plans to drill up to 14 wells over the second and third quarters of 2009 and then to increase the drilling program in fourth quarter of 2009 to between 15 and 20 wells. Production is expected to decline through the second and third quarters of 2009 with a substantial increase in the fourth quarter of 2009 fueled by the Central Montney No. 1 project. Average 2009 production is expected to be in the range of 17,000 and 17,500 BOE/d. Forward-Looking Statements and Advisories Statements herein that are not historical facts may be considered forward looking statements including management's assessment of future plans and operations, growth expectations within the Corporation, expected initial production rates from certain new wells, expected decline rates of certain wells, expected reduction in operating costs in certain areas, expectation that the Corporation will not be taxable in 2009, drilling plans and the timing thereof, timing of review of credit facilities, capital expenditures, the timing thereof and the method of funding thereof and expected reserve additions in the Eastern Montney area and expected production levels,. These forward-looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Corporation's objectives, goals or future plans are forward-looking statements. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties 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, 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. As a consequence, Galleon's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although Galleon believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Galleon can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Galleon operates; the timely receipt of any required regulatory approvals; the ability of Galleon to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which Galleon has an interest in to operate the field in a safe, efficient and effective manner; the ability of Galleon to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion; the ability of Galleon to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Galleon operates; and the ability of Galleon to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list of factors and assumptions 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 (, or at Galleon's website ( 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. BOEs 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. Non-GAAP Measurements The MD&A contains terms commonly used in the oil and gas industry, such as funds from operations, funds from operations per share, and operating netback. These terms are not defined by GAAP and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with Canadian GAAP as an indicator of Galleon's performance. Management believes that in addition to net earnings, funds from operations is a useful financial measurement which assists in demonstrating the Corporation's ability to fund capital expenditures necessary for future growth or to repay debt. Galleon's determination of funds from operations may not be comparable to that reported by other companies. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. The Corporation calculates funds from operations per share by dividing funds from operations by the weighted average number of Class A shares outstanding. Galleon uses the term net debt in the MD&A and presents a table showing how it has been determined. This measure does not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures presented by other companies. Discovered Petroleum Initially in Place and Reserves "DPIIP" or "discovered petroleum initially in place" is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. Discovered petroleum initially in place is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. A recovery project cannot be defined for these volumes of DPIIP at this time. There is no certainty that it will be commercially viable to produce any portion of the recoverable discovered petroleum initially in place. The DPIIP, including the reserves, are all natural gas. Gross working interest reserves are Galleon's working interest share (operating or non-operating) before deduction of royalties and without including any royalty interests of Galleon. In their December 31, 2008 evaluation, DeGolyer assigned 112 bcf of proved plus probable gross working interest remaining reserves to the Eastern Montney assets. See Galleon's annual information form for the year ended December 31, 2008, which includes a summary of Galleon's reserves as at December 31, 2008 as evaluated by DeGolyer, which is available on SEDAR at The estimates of reserves estimated by DeGolyer and disclosed herein, may not reflect the same confidence level as estimates of reserves for all of Galleon's properties, due to the effects of aggregation.

For further information:

For further information: see or contact: Steve
Sugianto, President and Chief Executive Officer, (403) 261-9287,; Glenn R. Carley, Executive Chairman, (403) 261-9277,; Shivon Crabtree, Vice President and Chief Financial
Officer, (403) 261-9276

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