Celtic Reports 35% Increase In Oil And Gas Production In The First Quarter Of 2009



    (Stock Symbol "CLT" - TSX)

    CALGARY, May 11 /CNW/ - Celtic Exploration Ltd. ("Celtic" or the
"Company") has released its financial and operating results for the three
months ended March 31, 2009. Summary of results are as follows:

    
    Highlights

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                                                 Three months ended March 31,
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    ($ thousands, unless otherwise indicated)         2009     2008  Change
    -------------------------------------------------------------------------

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    FINANCIAL
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    Revenue, before royalties and financial
     derivatives                                    41,435   57,371     -28%
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    Funds from operations                           28,140   28,298      -1%
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      Basic ($/SHARE)                                 0.68     0.75      -9%
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      Diluted ($/SHARE)                               0.68     0.74      -8%
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    Net loss                                        (5,039)  (7,375)    -32%
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      Basic ($/SHARE)                                (0.12)   (0.20)    -40%
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      Diluted ($/SHARE)                              (0.12)   (0.20)    -40%
    -------------------------------------------------------------------------

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    Capital expenditures, net of dispositions       41,583   32,608      28%
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    Total assets                                   658,765  511,705      29%
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    Bank debt, net of working capital              160,974  157,412       2%
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    Bank debt, net of working capital,
     excluding non-cash financial instruments      177,620  145,360      22%
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    Shareholders' equity                           363,376  268,083      36%
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Weighted average common shares outstanding
     (thousands)
    -------------------------------------------------------------------------
      Basic                                         41,307   37,701      10%
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      Diluted                                       41,359   38,050       9%
    -------------------------------------------------------------------------

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    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    -------------------------------------------------------------------------
                                                      2009     2008   Change
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    OPERATIONS
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    -------------------------------------------------------------------------
    Production
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      Oil (BBLS/D)                                   3,601    3,309       9%
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      Gas (MCF/D)                                   57,706   38,717      49%
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      Combined (BOE/D)                              13,219    9,762      35%
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    Production per million shares (BOE/D)              320      259      24%
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    Realized sales prices, after financial
     instruments
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      Oil ($/BBL)                                    79.01    81.17      -3%
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      Gas ($/MCF)                                     5.36     8.51     -37%
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    Operating netbacks ($/BOE)
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      Oil and gas revenue, before hedging            34.82    64.59     -46%
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      Realized gain (loss) on financial instruments   9.72    (3.33)
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      Realized sales price, after hedging            44.54    61.26     -27%
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      Royalties                                      (8.55)  (15.09)    -43%
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      Production expense                            (10.21)  (10.42)     -2%
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      Transportation expense                         (0.49)   (0.73)    -33%
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      Operating netback                              25.29    35.02     -28%
    -------------------------------------------------------------------------

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    Drilling activity
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      Total wells                                     15.0     15.0       0%
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      Working interest wells                          12.6     12.3       2%
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      Success rate on working interest wells           84%      77%       9%
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    Undeveloped land
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      Gross acres                                  334,152  310,577       8%
    -------------------------------------------------------------------------
      Net acres                                    262,430  237,725      10%
    -------------------------------------------------------------------------


    HIGHLIGHTS - FIRST QUARTER 2009

    The three months ended March 31, 2009 was another successful quarter in
the execution of the Company's growth strategy. Highlights for the first
quarter of 2009 are as follows:

    -  Drilled 15 (12.6 net working interest) wells during the quarter
       resulting in 12 (9.6 net) natural gas wells and 1 (1.0 net) oil wells,
       for an overall success rate, based on net wells, of 84%;

    -  Increased average daily production by 35% to a Company quarterly
       record of 13,219 BOE per day, up from 9,762 BOE per day in the first
       quarter of 2008 and achieved daily average production per million
       shares outstanding of 320 BOE per day, up 24% in 2009 compared to 259
       BOE per day in the corresponding quarter of the previous year;

    -  Generated $28.1 million in funds from operations for the three month
       period ended March 31, 2009, down 1% from $28.3 million in the same
       quarter of the previous year. Reported funds from operations per
       share, diluted, of $0.68, a decrease of 8% from $0.74 per share in the
       first quarter of the previous year;

    -  Received an average operating netback of $25.29 per BOE, down 28% from
       $35.02 per BOE in the same quarter of 2008.
    

    PRESIDENT'S MESSAGE

    Celtic Exploration Ltd. ("Celtic" or the "Company") is pleased to report
to shareholders the Company's activities in the first quarter of 2009. During
the quarter, Celtic drilled 15 (12.6 net) wells with an overall success rate
of 84%. On March 3, 2009, the Alberta Government announced a new Energy
Incentive Program ("EIP") whereby new wells drilled starting on April 1, 2009
would be eligible for a royalty credit. In addition, new wells that commence
commercial production starting on April 1, 2009 will also be eligible for a
royalty reduction. As a result of this announcement, Celtic re-scheduled
drilling operations by deferring new drills to commence on or after April 1,
2009, in order to take full advantage of the new EIP benefits. Despite the
re-scheduling of drilling operations, Celtic achieved record high production
during the first quarter of 2009. Production during the quarter averaged
13,219 BOE per day, an increase of 35% from 9,762 BOE per day in the first
quarter of 2008. In the first quarter of 2009, Celtic recorded funds from
operations of $28.1 million ($0.68 per share, diluted), compared to $28.3
million ($0.74 per share, diluted) reported in the same quarter of the
previous year.
    In Southern Alberta, the Company participated in the drilling of two
successful natural gas wells in the Drumheller area. Celtic's working interest
in these wells is 25.0%. In Northern Alberta, the Company drilled an
unsuccessful well targeting light oil at Utikuma (100% working interest). In
East Central Alberta, the Company drilled three wells including a horizontal
multi-stage fracture oil well at Edwand (100% working interest). The Company
expects to confirm production rates on this well after spring break-up. The
remaining two drills were vertical wells resulting in one potential natural
gas well (100% working interest) and one unsuccessful well (100% working
interest).
    During the first quarter, Celtic drilled a successful dual oil and gas
well at McLeod (100% working interest), south-east of Kaybob in West Central
Alberta. The well has been completed and put on production at initial rates of
300 BOE per day. A second well at McLeod is planned for the second quarter.
    The remainder of Celtic's drilling activity in the first quarter of 2009
took place in the Greater Kaybob area of West Central Alberta, where 8 (7.1
net) wells were drilled with an overall success rate of 100%. All eight wells
were horizontals with multi-fracture completions.
    At Kaybob South, Celtic drilled two horizontal wells including one on its
west block of lands. One well was put on-stream and the second well on the
west block of lands is expected to be put on production in early June after
the KA Gas Plant turnaround is completed.
    At KayFox, Celtic drilled four horizontal wells. Three wells were
completed in the Montney formation and one well was completed in the Bluesky
formation. The Company is encouraged by the results of its first two
horizontal Bluesky wells in the Greater Kaybob area and expects to drill
additional Bluesky wells during the remainder of 2009.
    At Pine Creek, Celtic drilled a Montney horizontal well (36.5% working
interest) on farm-in lands. This well was successfully completed and put on
production. At Chickadee, the Company drilled and completed a Montney
horizontal well (100% working interest) which is expected to be put on
production in early June after the KA Gas Plant turnaround is completed.
    Celtic processes the majority of its production from the Greater Kaybob
area through the KA and K3 Gas Plants, which are operated by SemCAMS ULC. The
KA Gas Plant is currently down for plant turnaround maintenance. This occurs
every four years. Celtic expects to have approximately 10,000 BOE per day
shut-in for four weeks during the plant turnaround. Celtic is currently
evaluating the economics and feasibility of building its own gas plant at
Kaybob. Based on a preliminary analysis, the Company could add to existing
facilities that it owns and operates and build a gas processing plant with
throughput capacity of 150 MMCF per day of raw gas, for approximately $35.0
million. The payout on this type of capital expenditure would be less than two
years based on the anticipated savings in operating costs and gas shrinkage
loss compared to processing gas through the KA and K3 Gas Plants. If Celtic is
satisfied with a final financial evaluation and it meets all regulatory
approvals, construction of a gas plant would likely take place in 2010.
    Celtic continues to acquire new lands in the Kaybob area. At March 31,
2009, the Company's undeveloped land holdings in all areas increased to
334,152 (262,430 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.
    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 hedged oil
production, NYMEX to AECO basis differential and currency exchange is
disclosed in detail in the accompanying notes to the financial statements.

    PRODUCTION

    Oil and gas production in the first quarter of 2009 increased 35% to
average 13,219 BOE per day compared to 9,762 BOE per day in the same quarter
of 2008. Production per million shares outstanding for the three months ended
March 31, 2009 averaged 320 BOE per day, up 24% from 259 BOE per day in the
corresponding quarter 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 three months of 2009.

    REVENUE

    Revenue, before royalties, and before realized and unrealized gains or
losses on financial derivatives, for the three months ended March 31, 2009,
was $41.4 million, a decrease of 28% compared to $57.4 million in the same
quarter of the previous year. Lower revenue in 2009 was due to lower commodity
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 derivatives for the three
months ended March 31, 2009 was $44.54 per BOE, a decrease of 27% compared to
the corresponding three month period of the previous year.

    OIL OPERATIONS

    Oil production for the first quarter ended March 31, 2009 averaged 3,601
barrels per day, an increase of 9% compared to the same quarter of the
previous year.
    The average price received for oil sales, after realized financial
derivatives, for the first quarter ended March 31, 2009 was $79.01 ($45.01
before financial derivatives) per barrel, down 3% from the average price of
$81.17 ($88.61 before financial derivatives) per barrel received in the first
quarter of 2008.
    For the quarter ended March 31, 2009, average oil royalties were 18.3% of
revenue, after financial derivatives (32.3% of sales, before financial
derivatives). In the first quarter of the previous year, average oil royalties
were 27.0% of revenue, after financial derivatives (24.8% of sales, before
financial derivatives). Higher royalty rates in 2009, before financial
derivatives, were primarily a result of the new royalty framework implemented
by the Alberta government effective January 1, 2009 which uses two month
lagging oil prices in order to calculate the applicable royalty rate applied
to current oil sales.
    Transportation expenses for oil production in the first quarter of 2009
averaged $0.34 per barrel compared to $0.66 per barrel in the first quarter of
2008. Lower per unit transportation expenses in 2009 reflect the larger
portion of newer NGL production which is mostly pipeline connected and
therefore less expensive to transport compared to trucking oil.
    For the first quarter ended March 31, 2009, oil production expenses were
$13.87 per barrel. In the same quarter of the previous year, oil production
expenses were $14.54 per barrel. Lower per unit production expenses in 2009
reflect the increasing portion of newer NGL production which is less expensive
to produce than oil.

    GAS OPERATIONS

    Gas production for the first quarter ended March 31, 2009 averaged 57,706
MCF per day, an increase of 49% compared to the corresponding quarter 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
derivatives, for the first quarter ended March 31, 2009 was $5.36 ($5.17
before financial derivatives) per MCF, down 37% from the average price of
$8.51 ($8.71 before financial derivatives and physical fixed price contracts)
per MCF received in the first quarter of 2008.
    For the quarter ended March 31, 2009, average gas royalties were 19.8% of
revenue, after financial derivatives (20.7% of sales, before financial
derivatives). In the first quarter of the previous year, average gas royalties
were 22.7% of revenue, after financial derivatives (22.5% of sales, before
financial derivatives). Lower gas royalty rates in 2009, before financial
derivatives, 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.
    Transportation expenses for the first quarter ended March 31, 2009 were
$0.09 per MCF, a decrease of 31% compared to $0.13 per MCF for the same
quarter 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
production.
    For the first quarter ended March 31, 2009, production expenses of $1.47
per MCF were 7% higher than $1.38 per MCF in the corresponding quarter of the
previous year. Higher production expenses in 2009 reflect certain one time
expenses that are being incurred 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 March 31, 2009, general and administrative expenses
were $1.0 million ($0.86 per BOE), interest expense was $0.9 million, and
depletion, depreciation and accretion expenses were $24.7 million ($20.78 per
BOE). In the previous year, for the quarter ended March 31, 2008, general and
administrative expenses were $1.1 million ($1.18 per BOE), interest expense
was $1.8 million, and depletion, depreciation and accretion expenses were
$20.2 million ($22.69 per BOE). Lower interest expense in 2009 reflect
declining interest rates and higher depletion, depreciation and accretion
expenses reflect higher production volumes.

    TAXES

    For the quarter ended March 31, 2009, Celtic provided for a recovery of
future income taxes in the amount of $1.9 million, compared to a recovery of
$2.9 million in the first quarter of 2008. For the three months ended March
31, 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.

    EARNINGS AND FUNDS FROM OPERATIONS

    Net loss for the quarter ended March 31, 2009 was $5.0 million ($0.12 per
share, basic and diluted). During the same period, funds from operations were
$28.1 million ($0.68 per share, basic and diluted). On a barrel of oil
equivalent basis, funds from operations in the first quarter of 2009 were
$23.65 per BOE, down 26% from $31.86 per BOE in the same quarter of 2008. The
main reason for the decrease in funds from operations per BOE in 2009 was
lower commodity prices.

    CAPITAL EXPENDITURES

    During the quarter ended March 31, 2009, Celtic spent $41.6 million on
capital projects. Drilling and completion operations accounted for $32.8
million, equipment and facility expenditures were $7.6 million and $1.2
million was spent on land and seismic. In the first quarter of the previous
year, capital expenditures were $32.6 million.
    At March 31, 2009, the Company had 334,152 (262,430 net) acres of
undeveloped land. The Company continues to build on its inventory of prospects
for future drilling.

    DRILLING ACTIVITY

    During the first quarter of 2009, the Company drilled 15 (12.6 net) wells
resulting in 12 (9.6 net) natural gas wells and 1 (1.0 net) oil wells, for an
overall success rate, based on net wells, of 84%. During the first quarter
ended March 31, 2008, Celtic drilled 15 (12.3 net) wells, with an overall
success rate of 77%. The average measured depth of net wells drilled in the
first quarter of 2009 was 2,559 metres, a decrease of 3% compared to the
average drilling measured depth of 2,651 metres in the first quarter of 2008.

    SHARE INFORMATION

    The Company is authorized to issue an unlimited number of common shares
and an unlimited number of preferred shares. As at March 31, 2009, there were
41.3 million common shares outstanding (as at May 8, 2009, there were 44.1
million common shares outstanding). There are no preferred shares outstanding.
    As at March 31, 2009, directors, employees and certain consultants have
been granted options to purchase 3.2 million common shares of the Company at
an average exercise price of $12.98 per share.
    The Company's common shares trade on the Toronto Stock Exchange 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 March 31, 2009:

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

    The following is a summary of NYMEX-AECO fixed natural gas basis
differential derivative contracts in effect as at March 31, 2009:

    -------------------------------------------------------------------------
    Quantity          Remaining term of contract     Fixed price per MMBTU
    -------------------------------------------------------------------------
    30,000 MMBTU/d    April 1 to April 30, 2009      US$0.69
     (swap)
    10,000 MMBTU/d    May 1 to May 31, 2009          US$0.69
     (swap)
    30,000 MMBTU/d    June 1 to December 31, 2009    US$0.69
     (swap)
    -------------------------------------------------------------------------

    The following is a summary of U.S. currency average rate forward swap
contracts in effect as at March 31, 2009:

    -------------------------------------------------------------------------
    Amount        Remaining term of contract   Fixed exchange rate (CAD/USD)
    -------------------------------------------------------------------------
    US$4,000,000  April 1 to April 30, 2009               1.2425
    US$2,000,000  May 1 to May 31, 2009                   1.2600
    US$4,000,000  June 1 to December 31, 2009             1.2425
    /month
    US$4,000,000  January 1 to December 31, 2010          1.2106
    /month
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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 March 31, 2009:

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

    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 has approved a capital expenditure budget in
the amount of $150 million for 2009. This capital spending will be financed by
funds from operations, available bank credit lines and common share issuances.
Subsequent to the end of the first quarter, 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.
    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 planned
turnaround at the KA Gas Plant in May 2009, Celtic expects production in 2009
to average between 13,800 and 14,200 BOE/d (25% oil and 75% gas). This
represents a 25% to 28% increase from the average production of 11,071 BOE/d
in 2008. The KA Gas Plant maintenance is expected to result in approximately
10,000 BOE/d of Celtic production to be shut-in during the month of May 2009.
Celtic expects to exit 2009 with production of approximately 16,700 BOE/d.
    Financial turmoil and the global recession continue to remain in the
headlines and could continue to put pressure on oil and gas prices in the
future. The high demand for oil by countries such as India and China, in the
past two years, has temporarily slowed down. As a result of these and other
factors, 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$53.50
per barrel for WTI oil (previously US$35.00 per barrel), US$5.00 per MMBTU for
NYMEX natural gas (previously US$4.80 per MMBTU), $4.70 per GJ for AECO
natural gas (previously $4.90 per GJ) and a US/Canadian dollar exchange rate
of US$0.837 (previously US$0.786). 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 $150.0 million or $3.46 per share
($3.41 per share, diluted) and net earnings is forecasted to be approximately
$6.3 million or $0.15 per share ($0.14 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 $127.7 million by
the end of 2009 or approximately 0.9 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.

    NON-GAAP FINANCIAL MEASUREMENTS

    This document contains the terms "funds from operations", "operating
netback" and "production per share" which do not have a standardized meaning
prescribed by Canadian GAAP and therefore may not be comparable with the
calculation of similar measures by other companies. Funds from operations and
operating netbacks are used by Celtic as key measures of performance. Funds
from operations and operating netbacks are not intended to represent operating
profits nor should they be viewed as an alternative to cash flow provided by
operating activities, net earnings or other measures of financial performance
calculated in accordance with GAAP. Operating netbacks are determined by
deducting royalties, production expenses and transportation expenses from oil
and gas revenue. The Company calculates funds from operations per share using
the same method and shares outstanding which are used in the determination of
earnings per share.

    OTHER MEASUREMENTS

    All dollar amounts are referenced in Canadian dollars, except when noted
otherwise. Where amounts are expressed on a barrel of oil equivalent ("BOE")
basis, natural gas volumes have been converted to oil equivalence at six
thousand cubic feet per barrel and sulphur volumes have been converted to oil
equivalence at 0.6 long tons per barrel. The term BOE may be misleading,
particularly if used in isolation. A BOE conversion ratio of six thousand
cubic feet per barrel is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. References to oil in this discussion include
crude oil and natural gas liquids ("NGLs"). NGLs include condensate, propane,
butane and ethane. References to gas in this discussion include natural gas
and sulphur.

    ADDITIONAL INFORMATION

    Additional information relating to Celtic, including the Company's Annual
Information Form ("AIF") is filed on SEDAR and can be viewed on their website
at www.sedar.com. Copies of the AIF can also be obtained by contacting Sadiq
H. Lalani, Vice President, Finance and Chief Financial Officer at Celtic
Exploration Ltd., Suite 500, 505 Third Street SW, Calgary, Alberta, Canada,
T2P 3E6. Further information relating to the Company is also available on its
website at www.celticex.com.





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 site
at www.celticex.com

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