Celtic reports financial and operating results for the second quarter of 2009



    (Stock Symbol "CLT" - TSX)

    CALGARY, Aug. 7 /CNW/ -

    
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                                 Three months               Six months
                                ended June 30,             ended June 30,
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    ($ thousands, unless
     otherwise indicated)  2009     2008   Change     2009     2008   Change
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    FINANCIAL
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    Revenue, before
     royalties and
     financial
     derivatives         30,668   80,220     -62%   72,102  137,591     -48%
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    Funds from
     operations          20,008   36,787     -46%   48,148   65,085     -26%
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      Basic ($/share)      0.46     0.92     -50%     1.14     1.67     -32%
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      Diluted ($/share)    0.46     0.90     -49%     1.13     1.65     -32%
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    Net loss             (5,459)  (9,116)    -40%  (10,498) -16,491     -36%
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      Basic ($/share)     (0.13)   (0.23)    -43%    (0.25)   -0.42     -40%
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      Diluted ($/share)   (0.13)   (0.23)    -43%    (0.25)   -0.42     -40%
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    Capital expenditures,
     net of
     dispositions        36,619   67,736     -46%   78,201  100,345     -22%
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    Total assets                                   663,531  572,691      16%
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    Bank debt, net of
     working capital                               145,976  156,483      -7%
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    Bank debt, net of
     working capital,
     excluding non-cash
     financial
     instruments                                   157,619  124,179      27%
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    Shareholders' equity                           394,870  304,523      30%
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    Weighted average
     common shares
     outstanding
     (thousands)
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      Basic              43,486   40,148       8%   42,402   38,924       9%
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      Diluted            43,792   40,822       7%   42,583   39,392       8%
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    OPERATIONS
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    Production
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      Oil (bbls/d)        2,929    3,367     -13%    3,268    3,338      -2%
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      Gas (mcf/d)        47,822   44,852       7%   52,737   41,785      26%
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      Combined (BOE/d)   10,909   10,842       1%   12,057   10,302      17%
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    Production per
     million shares
     (BOE/d)                251      270      -7%      284      265       7%
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    Realized sales
     prices, after
     financial
     instruments
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      Oil ($/bbl)         86.32    90.48      -5%    82.32    85.87      -4%
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      Gas ($/mcf)          3.77     9.52     -60%     4.64     9.05     -49%
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    Operating netbacks
     ($/BOE)
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      Oil and gas
       revenue, before
       hedging            30.88    81.31     -62%    33.02    73.39     -55%
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      Realized gain
       (loss) on
       financial
       instruments         8.90   -13.82              9.54    -8.85
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      Realized sales
       price, after
       hedging            39.78    67.49     -41%    42.56    64.54     -34%
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      Royalties           (4.05)  (17.39)    -77%    (6.50)  (16.30)    -60%
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      Production expense (12.13)   (9.59)     26%   (11.08)   (9.98)     11%
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      Transportation
       expense            (0.54)   (0.57)     -5%    (0.51)   (0.65)    -22%
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      Operating netback   23.06    39.94     -42%    24.47    37.61     -35%
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    Drilling activity
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      Total wells             9       10     -10%       24       25      -4%
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      Working interest
       wells                8.7      8.6       1%     21.4     20.9       2%
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      Success rate on
       working interest
       wells               100%     100%       0%      91%      86%       6%
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    Undeveloped land
     (acres)
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      Gross                                        344,846  319,882       8%
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      Net                                          272,000  250,113       9%
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    Message to Shareholders

    Celtic Exploration Ltd. ("Celtic" or the "Company") is pleased to report
to shareholders the Company's activities in the second quarter of 2009. During
the quarter, Celtic drilled 9 (8.7 net) wells with an overall success rate of
100%. For five weeks during the second quarter, Celtic had approximately 9,000
BOE per day shut-in as a result of the scheduled maintenance operations at the
KA Gas Plant. During the KA Gas Plant turnaround, which occurs every four to
five years, Celtic was able to divert some production to the K3 Gas Plant.
Despite the shut-in production, Celtic achieved growth in production during
the second quarter of 2009 when compared to the second quarter of 2008.
Production during the quarter averaged 10,909 BOE per day, an increase of 1%
from 10,842 BOE per day in the second quarter of 2008. Production during the
second quarter of 2009 would have been in excess of 14,000 BOE per day, had
the Company not been required to shut-in any production. In the second quarter
of 2009, Celtic recorded funds from operations of $20.0 million ($0.46 per
share, diluted), compared to $36.8 million ($0.90 per share, diluted) reported
in the same quarter of the previous year. Lower funds from operations in 2009
were primarily due to significantly lower realized natural gas prices compared
to the previous year.
    All of Celtic's drilling activity during the second quarter of 2009 took
place in the Greater Kaybob area of West Central Alberta, where 9 (8.7 net)
wells were drilled with an overall success rate of 100%. All nine wells were
horizontals with multi-fracture completions.
    At Kaybob South, Celtic drilled three horizontal wells targeting the
Triassic Montney formation. These wells are expected to be put on production
later in the third quarter in anticipation of higher natural gas prices at
that time.
    At KayFox, Celtic drilled four horizontal wells. These wells were
completed in the Triassic Montney formation in late July and are expected to
be put on production in August 2009.
    At Lower Kaybob South, Celtic drilled two horizontal wells and completed
both wells in the Cretaceous Bluesky formation. The first well (68.6% BPPO and
50% APPO) produced natural gas at an average rate of 6.5 MMCF (gross) per day
during a four day test. The second well (100% BPPO and 59.3% APPO) produced
natural gas at an average rate of 10.7 MMCF per day during a four day test.
These Bluesky wells also produce approximately 40 to 50 barrels of NGLs per
MMCF per day of raw gas. The Company is pleased with the initial results from
its Bluesky wells and plans to drill additional wells targeting the Bluesky
zone in the second half of 2009.
    At June 30, 2009, the Company's undeveloped land holdings in all areas
increased to 344,846 (272,000 net) acres. With this inventory of land and with
plans to continue developing its Kaybob prospects, Celtic continues to
generate numerous drilling locations that will provide continued growth over
the next few years. In addition to the Montney and Bluesky reservoirs, Celtic
plans to test its horizontal drilling with multi fracture completions in the
Nordegg and Notikewin zones at Kaybob during the second half of 2009.
    Celtic has maintained its planned 2009 capital expenditure budget of
$150.0 million that it established back in November 2008. While many of the
Company's peers have reduced their capital spending plans as a result of lower
commodity prices, Celtic has been able to maintain its capital spending plans
primarily due to a strong hedge book and the positive impact of Alberta's
royalty incentives.
    Oil and gas producers, like Celtic, are continually exposed to
fluctuations in commodity prices that are beyond the control of the companies
that produce hydrocarbons. In order to mitigate this risk and provide
certainty to a portion of its cash flow supporting its capital investment
program, Celtic employs an active risk management program. The Company's
outstanding financial derivative contracts relating to its oil production,
NYMEX to AECO basis differential, currency exchange rates and interest rates
on debt are disclosed in detail in the accompanying notes to the financial
statements. For the six months ended June 30, 2009, the Company realized $19.7
million in gains from all of its financial instrument contracts. The
mark-to-market value of remaining financial instrument contracts as at June
30, 2009 were valued at $16.4 million, before the effect of income taxes.
    The new royalty incentives announced by the Alberta Government will
benefit the Company significantly until expiry on March 31, 2011. The Drilling
Royalty Credit ("DRC") provides companies with a $200 per metre credit on new
wells drilled that may be applied against corporate crown royalties payable
during the period from April 1, 2009 to March 31, 2011, subject to a maximum
of 50% for Celtic. During the second quarter of 2009, Celtic earned $6.5
million of credits from its drilling activity. Based on estimated crown
royalties payable during the quarter, the Company could have reduced capital
expenditures by $1.9 million during the quarter. However, since the DRC has
not yet been passed into law, Celtic has not accrued reductions to capital
expenditures during the second quarter. It is anticipated that the DRC will
become law during the third quarter of 2009.
    The New Well Royalty Reduction ("NWRR") was also announced recently and
provides for a flat 5% royalty on new wells brought on production after March
31, 2009. This program applies to all new wells brought on production prior to
April 1, 2011. The 5% royalty remains in effect for twelve producing months or
for the first 500,000 MCF equivalent of gas (or 50,000 barrels of oil
equivalent) produced, whichever comes first. Celtic's horizontal wells at
Kaybob will benefit significantly from this program since the flat 5% royalty
will replace first year royalty rates in the 22% to 35% range in a $3.57 to
$7.14 per GJ AECO gas price environment.
    With the benefit of the NWRR incentive program and given Celtic's ability
to claim its calculated Gas Cost Allowance ("GCA"), net corporate royalties
for the remainder of 2009 are expected to be approximately 14%. For the second
half of 2009, Celtic is forecasting average commodity prices of US$62.55 per
barrel for WTI oil, US$5.05 per MMBTU for NYMEX natural gas, $4.30 per GJ for
AECO natural gas and a US/Canadian dollar exchange rate of US$0.903.

    
    Highlights - Second Quarter 2009

    The three months ended June 30, 2009 was another successful quarter in the
execution of the Company's growth strategy. Highlights for the second quarter
of 2009 are as follows:

    -   Drilled 9 (8.7 net working interest) natural gas wells during the
        quarter resulting in an overall success rate of 100%;

    -   Increased average daily production by 1% to 10,909 BOE per day, up
        from 10,842 BOE per day in the second quarter of 2008, despite having
        approximately 9,000 BOE per day shut-in for five weeks during plant
        turnaround operations;

    -   Generated $20.0 million in funds from operations for the three month
        period ended June 30, 2009, down 46% from $36.8 million in the same
        quarter of the previous year. Reported funds from operations per
        share, diluted, of $0.46, a decrease of 49% from $0.90 per share in
        the second quarter of the previous year;

    -   Received an average operating netback of $23.06 per BOE, down 42%
        from $39.94 per BOE in the corresponding quarter of 2008.
    

    Production

    Oil and gas production in the second quarter of 2009 increased 1% to
average 10,909 BOE per day compared to 10,842 BOE per day in the same quarter
of 2008. Production per million shares outstanding for the three months ended
June 30, 2009 averaged 251 BOE per day, down 7% from 270 BOE per day in the
corresponding quarter of the previous year.
    Oil and gas production for the six months ended June 30, 2009 increased
17% to average 12,057 BOE per day compared to 10,302 BOE per day in the
corresponding period of 2008. Production per million shares outstanding for
the six months ended June 30, 2009 averaged 284 BOE per day, up 7% from 265
BOE per day in the corresponding period of the previous year.
    Celtic's production is entirely based in Alberta and is divided into four
core areas. In Southern Alberta, the Company's primary natural gas producing
properties are located at Drumheller and Michichi and its primary oil
producing properties are located at Princess and Bantry. In East Central
Alberta, the principal producing asset is a shallow natural gas property at
Ashmont, with future oil development potential at Edwand/Figure Lake. In
Northern Alberta, the Company produces light oil primarily from Utikuma Lake.
In West Central Alberta, Celtic has both natural gas and light oil production
at Kaybob, Fox Creek and Swan Hills. West Central Alberta was the Company's
most active drilling area in the first six months of 2009.

    Revenue

    Revenue, before royalties, and before realized and unrealized gains or
losses on financial instruments, for the three months ended June 30, 2009, was
$30.7 million, a decrease of 62% compared to $80.2 million in the same quarter
of the previous year. Revenue, before royalties, and before realized and
unrealized gains or losses on financial instruments, for the six months ended
June 30, 2009, was $72.1 million, a decrease of 48% compared to $137.6 million
in the same period of the previous year.
    Lower revenue in 2009 was due to significantly lower natural gas prices
that more than offset increased production levels.
    The combined average product price received for oil and gas sales,
adjusted for realized gains or losses on financial instruments for the three
months ended June 30, 2009 was $39.78 per BOE, a decrease of 41% compared to
the corresponding three month period of the previous year. The combined
average product price received for oil and gas sales, adjusted for realized
gains or losses on financial instruments for the six months ended June 30,
2009 was $42.56 per BOE, a decrease of 34% compared to the corresponding six
month period of the previous year.

    Oil Operations

    Oil production for the second quarter ended June 30, 2009 averaged 2,939
barrels per day, a decrease of 13% compared to the same quarter of the
previous year. Oil production for the six months ended June 30, 2009 averaged
3,268 barrels per day, a decrease of 2% compared to the same period of the
previous year.
    The average price received for oil sales, after realized financial
instruments, for the second quarter ended June 30, 2009 was $86.32 ($55.30
before financial instruments) per barrel, down 5% from the average price of
$90.48 ($112.43 before financial instruments) per barrel received in the
second quarter of 2008. The average price received for oil sales, after
realized financial instruments, for the six months ended June 30, 2009 was
$82.32 ($49.67 before financial instruments) per barrel, down 4% from the
average price of $85.87 ($100.63 before financial instruments) per barrel
received in the first six months of 2008.
    For the quarter ended June 30, 2009, average oil royalties were 12.9% of
revenue, after financial instruments (20.2% of revenue, before financial
instruments). In the first quarter of the previous year, average oil royalties
were 31.4% of revenue, after financial instruments (25.3% of revenue, before
financial instruments). For the six months ended June 30, 2009, average oil
royalties were 15.8% of revenue, after financial instruments (26.2% of
revenue, before financial instruments). In the first six months of the
previous year, average oil royalties were 29.4% of revenue, after financial
instruments (25.1% of revenue, before financial instruments).
    Lower oil royalty rates in 2009, before financial instruments, reflect
the lower rates calculated with lower oil selling prices.
    Transportation expenses for oil production in the second quarter of 2009
averaged $0.35 per barrel compared to $0.55 per barrel in the second quarter
of 2008. Transportation expenses for oil production during the six month
period ended June 30, 2009 averaged $0.35 per barrel compared to $0.61 per
barrel in the corresponding period of 2008.
    Lower per unit transportation expenses in 2009 reflect the larger portion
of newer NGL production from Kaybob which is mostly pipeline connected and
therefore less expensive to transport compared to trucking oil.
    For the second quarter ended June 30, 2009, oil production expenses were
$13.97 per barrel. In the same quarter of the previous year, oil production
expenses were $12.54 per barrel. For the six months ended June 30, 2009, oil
production expenses were $13.91 per barrel. In the same period of the previous
year, oil production expenses were $13.53 per barrel.

    Gas Operations

    Gas production for the second quarter ended June 30, 2009 averaged 47,822
MCF per day, an increase of 7% compared to the corresponding quarter of the
previous year. Gas production for the six months ended June 30, 2009 averaged
52,737 MCF per day, an increase of 26% compared to the corresponding period of
the previous year.
    Increases in gas production in 2009 were primarily a result of Celtic's
successful drilling results in its resource development prospect located at
Kaybob, Alberta.
    The average price received for gas sales, after realized financial
instruments, for the second quarter ended June 30, 2009 was $3.77 ($3.65
before financial instruments) per MCF, down 60% from the average price of
$9.52 ($11.21 before financial instruments) per MCF received in the second
quarter of 2008. The average price received for gas sales, after realized
financial instruments, for the six months ended June 30, 2009 was $4.64 ($4.48
before financial instruments) per MCF, down 49% from the average price of
$9.05 ($10.05 before financial instruments) per MCF received in the first six
months of 2008.
    For the quarter ended June 30, 2009, average gas royalties were 6.4% of
revenue, after financial instruments (6.6% of revenue, before financial
instruments). In the second quarter of the previous year, average gas
royalties were 21.7% of revenue, after financial instruments (18.6% of sales,
before financial instruments). For the six month period ended June 30, 2009,
average gas royalties were 14.7% of revenue, after financial instruments
(15.4% of revenue, before financial instruments). In the first six months of
the previous year, average gas royalties were 15.9% of revenue, after
financial instruments (19.0% of revenue, before financial instruments).
    Lower gas royalty rates in 2009, before financial instruments, were
primarily a result of lower natural gas selling prices and longer depth
horizontal wells which receive favourable treatment under the new royalty
framework program. In addition, royalties are reduced further as the Company
continues to receive GCA which does not fluctuate with gas prices.
    Transportation expenses for the second quarter ended June 30, 2009 were
$0.10 per MCF, unchanged from $0.10 per MCF for the same quarter in the
previous year. Transportation expenses for the six months ended June 30, 2009
were $0.10 per MCF, a decrease of 9% compared to $0.11 per MCF for the
corresponding period in the previous year.
    Lower transportation expenses in 2009 reflect the Company's ownership in
the majority of the pipeline infrastructure at its main producing area of
Kaybob, Alberta, where the Company has been increasing its production volumes.
    For the second quarter ended June 30, 2009, production expenses of $1.91
per MCF were 38% higher than $1.38 per MCF in the corresponding quarter of the
previous year. For the six months ended June 30, 2009, production expenses of
$1.67 per MCF were 21% higher than $1.38 per MCF in the corresponding period
of the previous year.
    Higher production expenses in 2009 reflect certain one time expenses that
were incurred in the second quarter at Kaybob as a result of turnaround
operations at the KA Gas Plant where the majority of Celtic's gas is
processed.

    Other Expenses

    For the quarter ended June 30, 2009, general and administrative expenses
were $0.9 million ($0.87 per BOE), interest expense was $1.4 million, and
depletion, depreciation and accretion expenses were $19.9 million ($20.02 per
BOE). In the previous year, for the quarter ended June 30, 2008, general and
administrative expenses were $1.0 million ($1.02 per BOE), interest expense
was $1.6 million, and depletion, depreciation and accretion expenses were
$20.4 million ($22.70 per BOE).
    For the six month period ended June 30, 2009, general and administrative
expenses were $1.9 million ($0.86 per BOE), interest expense was $2.3 million,
and depletion, depreciation and accretion expenses were $44.6 million ($20.43
per BOE). In the previous year, for the six months ended June 30, 2008,
general and administrative expenses were $2.1 million ($1.10 per BOE),
interest expense was $3.4 million, and depletion, depreciation and accretion
expenses were $40.6 million ($21.65 per BOE).
    Aggregate general and administrative expenses in 2009 were essentially
unchanged as the Company has retained similar staffing levels at head office,
despite the growth in production year over year. Lower interest expense in
2009 reflects lower market interest rates. Higher depletion, depreciation and
accretion expenses reflect higher production volumes; however, per unit costs
are lower in 2009 as a result of proved reserve additions at lower than
historic costs.

    Taxes

    For the quarter ended June 30, 2009, Celtic provided for a recovery of
future income taxes in the amount of $2.0 million, compared to a recovery of
$3.6 million in the second quarter of 2008. For the six month period ended
June 30, 2009, Celtic provided for a recovery of future income taxes in the
amount of $3.9 million, compared to a recovery of $6.5 million in the first
six months of 2008.
    For the six months ended June 30, 2009, Celtic is not required to pay
current income taxes as it has sufficient income tax deductions available to
shelter taxable income for the period. Estimated income tax deductions
available at June 30, 2009 are $397.3 million and are comprised of $97.0
million of COGPE, $156.5 million of CDE, $31.6 million of CEE, $106.5 million
of UCC and $5.7 million of share issue costs.

    Earnings

    Net loss for the quarter ended June 30, 2009 was $5.5 million ($0.13 per
share, basic and diluted). During the same period, funds from operations were
$20.0 million ($0.46 per share, basic and diluted). On a barrel of oil
equivalent basis, funds from operations in the second quarter of 2009 were
$20.15 per BOE, down 46% from $37.29 per BOE in the same quarter of 2008.
    Net loss for the six months ended June 30, 2009 was $10.5 million ($0.25
per share, basic and diluted). During the same period, funds from operations
were $48.1 million ($1.14 per share, basic and $1.13 per share, diluted). On a
barrel of oil equivalent basis, funds from operations in the first six months
of 2009 were $22.06 per BOE, down 36% from $34.71 per BOE in the same period
of 2008.
    The main reason for the decrease in funds from operations per BOE in 2009
was the significantly lower realized natural gas prices received by the
Company.

    Capital Expenditures

    During the quarter ended June 30, 2009, Celtic spent $36.6 million on
capital projects. Drilling and completion operations accounted for $27.2
million, equipment and facility expenditures were $7.9 million and $1.8
million was spent on land and seismic. Acquisitions were reduced by $0.3
million as a result of adjustments. In the second quarter of the previous
year, capital expenditures were $67.7 million.
    During the six month period ended June 30, 2009, Celtic spent $78.2
million on capital projects. Drilling and completion operations accounted for
$60.0 million, equipment and facility expenditures were $15.5 million and $3.0
million was spent on land and seismic. Proceeds from property dispositions
were $0.3 million. In the corresponding period of the previous year, capital
expenditures were $100.3 million.
    At June 30, 2009, the Company had 344,846 (272,000 net) acres of
undeveloped land. The Company continues to build on its inventory of prospects
for future drilling.

    Drilling Activity

    During the second quarter of 2009, the Company drilled 9 (8.7 net) wells
resulting in 9 (8.7 net) natural gas wells, for an overall success rate of
100%. During the second quarter ended June 30, 2008, Celtic drilled 10 (8.6
net) wells, with an overall success rate of 100%. The average measured depth
of net wells drilled in the second quarter of 2009 was 3,665 metres, an
increase of 20% compared to the average drilling measured depth of 3,061
metres in the second quarter of 2008.
    During the first six months of 2009, the Company drilled 24 (21.4 net)
wells resulting in 21 (18.3 net) natural gas wells and 1 (1.0 net) oil wells,
for an overall success rate, based on net wells, of 91%. During the six months
ended June 30, 2008, Celtic drilled 25 (20.9 net) wells, with an overall
success rate of 86%. The average measured depth of net wells drilled in the
first six months of 2009 was 2,999 metres, an increase of 6% compared to the
average drilling measured depth of 2,820 metres in the first six months of
2008.

    Source of Funds

    Investment funding for capital expenditures incurred in the second
quarter of 2009 was provided by bank debt and cash provided by operating
activities.
    On June 30, 2009, the Company renewed its syndicated bank credit
facility, increasing the authorized borrowing amount by $15.0 million to
$215.0 million. At June 30, 2009, Celtic had drawn $154.9 million of its
$215.0 million authorized bank credit facility, leaving sufficient unused
credit lines available to fund on-going capital expenditures and working
capital deficiencies. Repayments of principal are not required provided that
the borrowings under the facility do not exceed the authorized borrowing
amount and the Company is in compliance with all covenants, representations
and warranties.
    Celtic expects to fund future capital expenditures through the use of a
combination of cash provided by operating activities and bank debt,
supplemented by new equity share offerings, as required.

    Working Capital

    The capital intensive nature of Celtic's activities may create a working
capital deficiency position during periods with high levels of capital
investment. However, during such periods, the Company maintains sufficient
unused bank credit lines to satisfy such working capital deficiencies. At June
30, 2009, the working capital amount, excluding non-cash financial
instruments, plus outstanding bank debt represented 73% of the Company's
maximum authorized bank borrowing credit limit.

    Liquidity

    Liquidity risk is the risk the Company will encounter difficulties in
meeting its financial liability obligations. The Company's financial
liabilities are comprised of accounts payable, accrued liabilities and bank
debt.
    During 2008, many oil and gas companies faced a number of challenges
resulting from weakening commodity prices and tight credit markets. With the
indications of a continuing global recession in 2009, oil and gas companies
continued to face significant challenges relating to credit availability in
2009. Celtic has good relationships with its syndicate of lenders and recently
added two new members to its syndicate, in order to spread the risk. The
Company's existing credit facility matures on June 29, 2010.
    The Company manages liquidity risk through the prudent use of debt,
interest rate, currency and commodity price risk management and through an
actively managed production and capital expenditure budget process.

    Share Information

    The Company is authorized to issue an unlimited number of common shares
and an unlimited number of preferred shares. As at June 30, 2009, there were
44.2 million common shares outstanding (as at August 5, 2009, there were 44.2
million common shares outstanding). There are no preferred shares outstanding.
    As at June 30, 2009, directors, employees and certain consultants have
been granted options to purchase 3.1 million common shares of the Company at
an average exercise price of $13.20 per share.
    The Company's common shares trade on the TSX under the symbol "CLT".

    Future Commitments - Financial Instruments

    The Company may, from time to time, enter into fixed price contracts and
derivative financial instruments with respect to oil and gas sales, currency
exchange and interest rates in order to secure a certain amount of cash flow
to protect a desired level of capital spending.
    The following is a summary of WTI fixed oil sales price derivative
contracts in effect as at June 30, 2009:

    
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                        Remaining term
    Quantity            of contract         Fixed price per BBL
    -------------------------------------------------------------------------
    2,000 BBLs/day      July 1 to
     (put-call spread)  December 31, 2009   CA$115.00 (floor) CA$145.00 (cap)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following is a summary of NYMEX-AECO fixed natural gas basis
differential derivative contracts in effect as at June 30, 2009:

    -------------------------------------------------------------------------
                                                                Fixed price
    Quantity                 Remaining term of contract           per MMBTU
    -------------------------------------------------------------------------
    30,000 MMBTU/day (swap)  July 1 to December 31, 2009            US$0.69
    40,000 MMBTU/day (swap)  January 1 to December 31, 2010         US$0.77
    -------------------------------------------------------------------------
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    The following is a summary of U.S. currency average rate forward swap
contracts in effect as at June 30, 2009:

    -------------------------------------------------------------------------
                                                         Fixed exchange rate
    Amount                Remaining term of contract                (CAD/USD)
    -------------------------------------------------------------------------
    US$4,000,000/month    July 1 to December 31, 2009                 1.2425
    US$4,000,000/month    January 1 to December 31, 2010              1.2106
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following is a summary of interest rate swap contracts that settle
based on the floating Canadian Dollar Banker Acceptance CDOR rate, in effect
as at June 30, 2009:

    -------------------------------------------------------------------------
    Amount           Remaining term of contract          Fixed interest rate
    -------------------------------------------------------------------------
    CA$80,000,000    July 1, 2009 to April 22, 2010                    3.30%
    CA$20,000,000    July 1, 2009 to April 22, 2010                    2.54%
    CA$100,000,000   April 21, 2010 to April 21, 2011                  2.07%
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    Advisory Regarding Forward-Looking Statements

    Certain information with respect to Celtic contained herein, including
management's assessment of future plans and operations, contains
forward-looking statements. These forward-looking statements are based on
assumptions and are subject to numerous risks and uncertainties, certain of
which are beyond Celtic's control, including the impact of general economic
conditions, industry conditions, volatility of commodity prices, currency
exchange rate fluctuations, imprecision of reserve estimates, environmental
risks, competition from other explorers, stock market volatility and ability
to access sufficient capital. As a result, Celtic's actual results,
performance or achievement could differ materially from those expressed in, or
implied by, these forward-looking statements and, accordingly, no assurance
can be given that any events anticipated by the forward-looking statements
will transpire or occur. In addition, the reader is cautioned that historical
results are not necessarily indicative of future performance.

    Current Economic Environment

    Late in 2008 and early in 2009, the financial community around the world
has been rocked with unprecedented losses and business failures. As a result,
the current economic environment is challenging and uncertain amidst a global
recession, low commodity prices, volatile financial markets and limited access
to capital markets.
    In this environment, Celtic has maintained financial flexibility through
the prudent use of bank debt and through an active risk management strategy
whereby cash flow for 2009 has been secured to a certain extent through the
use of commodity price, currency and interest rate financial derivative
instruments.
    Celtic's capital expenditure program for 2009 remains flexible and if the
current economic environment continues to deteriorate, the Company has the
ability to defer expenditures into the future.

    2009 Guidance

    Despite the current economic environment, Celtic remains optimistic about
its future prospects. Celtic is opportunity driven and is confident that it
can continue to grow the Company's production base by building on its current
inventory of development prospects and by adding new exploration prospects.
Celtic will endeavour to maintain a high quality product stream that on a
historical basis receives a superior price with reasonably low production
costs. In addition, the Company takes advantage of royalty incentive programs
in order to further increase netbacks. Celtic will continue to focus its
exploration efforts in areas of multi-zone potential.
    Celtic's Board of Directors previously approved a capital expenditure
budget in the amount of $150 million for 2009. There are no changes to the
amount of planned expenditures for 2009 at the time of this report. Capital
spending will be financed by funds from operations, available bank credit
lines and common share issuances. On April 23, 2009, the Company completed an
equity financing by way of a short form prospectus, by issuing 2.75 million
common shares at a price of $13.25 per share, for gross proceeds of $36.4
million. On June 30, 2009, the Company renewed its syndicated bank credit
facility, increasing the authorized borrowing amount by $15.0 million to
$215.0 million.
    After forecasting risked production discoveries, timing of production
on-stream dates resulting from the Company's planned capital expenditures for
2009, estimated decline rates on existing and new volumes and the shut-in of
production during the KA Gas Plant turnaround in the second quarter, Celtic
expects production in 2009 to average between 13,800 and 14,000 BOE/d (25% oil
and 75% gas). This represents between a 25% and 26% increase from the average
production of 11,071 BOE/d in 2008. Celtic expects to exit 2009 with
production of approximately 16,700 BOE/d.
    Financial turmoil and the global recession which have been in the
headlines for some time may now be starting to stabilize with expectations of
a global economic recovery in 2010. Celtic expects oil prices to be
significantly lower in 2009 compared to 2008. Industrial demand for natural
gas in North America has also been reduced as a result of the weakening
economy, at the same time when natural gas supply in the United States was
increasing. Both these factors have contributed to lower natural gas prices,
despite the increased demand for natural gas that was created by a colder than
average winter. Celtic also expects much weaker average natural gas prices in
2009 compared to 2008. However, with the rapid decrease in active rigs
drilling for gas in North America and with the expected decline of new "flush"
natural gas production recently brought on-stream in the United States, the
Company is optimistic that natural gas prices may recover towards the end of
2009 or early in 2010.
    The Company's average commodity price assumptions for 2009 is US$57.00
per barrel for WTI oil (previously US$53.50 per barrel), US$4.65 per MMBTU for
NYMEX natural gas (previously US$5.00 per MMBTU), $4.14 per GJ for AECO
natural gas (previously $4.70 per GJ) and a US/Canadian dollar exchange rate
of US$0.865 (previously US$0.837). These prices compare to 2008 average prices
of US$99.65 per barrel for WTI oil, US$8.93 per MMBTU for NYMEX natural gas,
$7.71 per GJ for AECO natural gas and a US/Canadian dollar exchange rate of
US$0.937.
    After giving effect to the aforementioned production and commodity price
assumptions and taking into effect commodity risk price management contracts
in place (as outlined under Future Commitments above), funds from operations
for 2009 is forecasted to be approximately $125.0 million or $2.86 per share
($2.82 per share, diluted) and net loss is forecasted to be approximately $7.0
million or $0.16 per share ($0.16 per share, diluted). Changes in forecasted
commodity prices and variances in production estimates can have a significant
impact to estimated funds from operations and net earnings. Please refer to
the advisory regarding forward-looking statements shown above.
    Bank debt, net of working capital, is estimated to be $140.0 million by
the end of 2009 or approximately 1.1 times forecasted 2009 funds from
operations.
    Celtic's capital expenditure budget for 2009 will see the Company
participate at high working interests in the drilling of approximately 45 to
50 wells during the year, of which approximately 80% will be horizontal wells.
Celtic continues to evaluate and pursue potential property acquisitions that
would complement its existing asset base and completion of such acquisitions
would be over and above the Company's planned capital expenditure budget.
    Celtic is excited about the growth prospects being generated in the
Company and remains optimistic about the Company's ability to deliver
continued per share growth in production, reserves, net asset value, earnings
and funds from operations. Given the Company's strong inventory of drilling
locations, we look forward to continued growth in 2009 and beyond.
    The information set out herein under the heading "2009 Guidance" is
"financial outlook" within the meaning of applicable securities laws. The
purpose of this financial outlook is to provide readers with disclosure
regarding Celtic's reasonable expectations as to the anticipated results of
its proposed business activities for 2009. Readers are cautioned that this
financial outlook may not be appropriate for other purposes.





For further information:

For further information: CELTIC EXPLORATION LTD., Suite 500, 505 - 3rd
Street SW, Calgary, Alberta, Canada, T2P 3E6; David J. Wilson, President and
Chief Executive Officer, (403) 201-5340; or Sadiq H. Lalani, Vice President,
Finance and Chief Financial Officer, (403) 215-5310; or Visit our website at
www.celticex.com

Organization Profile

Celtic Exploration Ltd.

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