Celtic Reports 2006 Financial and Operating Results



    (Stock Symbol "CLT" - TSX)

    CALGARY, March 14 /CNW/ - Celtic Exploration Ltd. ("Celtic" or the
"Company") has released its financial and operating results for the three
months and twelve months ended December 31, 2006.  Highlights are as follows:

    
    FINANCIAL:
    ----------

    ($ thousands, unless       Three months ended            Year ended
    otherwise indicated)          December 31,              December 31,
    -------------------------------------------------------------------------
                            2006      2005  Change    2006       2005  Change
    -------------------------------------------------------------------------

    Revenue, net of
     royalties           $ 33,091  $ 26,647   24%  $123,262   $ 76,578   61%

    Funds from
     operations          $ 19,183  $ 18,674    3%  $ 78,541   $ 56,969   38%

    Funds from operations
     per share
      Basic ($/share)    $   0.60  $   0.65   -8%  $   2.57   $   2.05   25%
      Diluted
       ($/share)         $   0.58  $   0.62   -6%  $   2.50   $   1.98   26%

    Net earnings         $  6,599  $  7,062   -7%  $ 35,231   $ 18,264   93%

    Earnings per share
      Basic ($/share)    $   0.21  $   0.24  -13%  $   1.15   $   0.66   74%
      Diluted
       ($/share)         $   0.20  $   0.24  -17%  $   1.12   $   0.64   75%

    Capital
     expenditures,
     net of
     dispositions        $ 32,051  $ 41,490  -23%  $164,050   $119,230   38%

    Total assets                                   $373,882   $242,113   54%

    Bank debt                                      $101,800   $ 41,700
    Working capital
     deficiency
     (surplus),
     excluding
     bank debt                                     $ (3,564)    21,726
    -------------------------------------------------------------------------
    Bank debt, net
     of working capital                            $ 98,236   $ 63,426   55%
    -------------------------------------------------------------------------

    Shareholders' equity                           $200,029   $125,847   58%

    Common shares issued
     and outstanding
     (thousands)
      Basic                                          32,180     28,973   11%
      Diluted                                        34,810     31,229   11%



    OPERATIONS:
    -----------

                               Three months ended            Year ended
                                  December 31,              December 31,
    -------------------------------------------------------------------------
                            2006      2005  Change    2006       2005  Change
    -------------------------------------------------------------------------

    Production
      Oil (bbls/d)          3,290     2,915   13%     3,284      2,524   30%
      Natural gas (mcf/d)  18,001    13,071   38%    16,072     11,396   41%
      Combined (BOE/d)      6,290     5,094   23%     5,963      4,423   35%

    Production per
     million shares (BOE/d)   196       176   11%       195        159   23%

    Realized sales
     prices, after
     financial
     derivatives
      Oil ($/bbl)        $  58.68  $  57.49    2%  $  63.78   $  58.91    8%
      Natural gas
       ($/mcf)           $  10.10  $  12.51  -19%  $   9.71   $   9.63    1%

    Operating
     netbacks ($/BOE)
      Oil and
       gas revenue,
       before financial
       derivatives       $  53.99  $  67.05  -19%  $  58.97   $  60.21   -2%
      Realized gain
       (loss) on
       financial
       derivatives           5.60     (2.05)    -      2.29      (1.80)    -
      Royalties             (9.67)   (12.02) -20%    (10.89)    (10.98)  -1%
      Production
       expense             (13.38)   (10.59)  26%    (10.90)     (9.51)  15%
      Transportation
       and selling
       expense              (0.75)    (0.63)  19%     (0.66)     (0.72)  -8%
    -------------------------------------------------------------------------
    Operating netback    $  35.79  $  41.76  -14%  $  38.81   $  37.20    4%
    -------------------------------------------------------------------------

    Drilling activity
      Total wells              10        27  -63%        83        100  -17%
      Working interest
       wells                  8.4      15.3  -45%      62.8       68.1   -8%
      Success rate on
       working interest
       wells                  65%       76%  -14%       74%        74%    0%

    Undeveloped land
      Gross acres                                   323,821    261,346   24%
      Net acres                                     235,308    164,239   43%

    Reserves
      Oil (mbbls)                                    11,634     10,527   11%
      Natural gas (mmcf)                             88,327     47,992   84%
      Combined (mBOE)                                26,355     18,526   42%
      Reserve life index (years)                       11.5       10.0   15%
    



    2006 Highlights

    The year ended December 31, 2006 was another successful year in the
execution of the Company's growth strategy. Highlights for 2006 are as
follows:

    
    -   Accumulated over 39 sections of land at Kaybob South where the
        Company made a Montney natural gas new pool discovery at the end of
        2005;

    -   Generated gross proceeds of $43.5 million by completing an equity
        financing that resulted in the issuance of 2.0 million common shares
        at a price of $13.15 per share and a flow-through share private
        placement  that resulted in the issuance of 1.0 million common shares
        at a price of $17.25 per share;

    -   Drilled 83 (62.8 net working interest) wells during the year
        resulting in 24 (20.8 net) oil wells, 34 (25.3 net)  natural gas
        wells and 3 (0.5 net) coal bed methane wells, for an overall success
        rate, based on net wells, of 74%;

    -   Reported earnings per share, diluted, of $1.12, an increase of 75%
        compared to $0.64 in 2005;

    -   Reported funds from operations per share, diluted, of $2.50, an
        increase of 26% from $1.98 in the previous year;

    -   Generated an average operating netback of $38.81 per BOE, up 4% from
        $37.20 per BOE in 2005;

    -   Increased average daily production by 35% to 5,963 BOE per day, up
        from 4,423 BOE per day in 2005 and achieved daily average production
        per million shares of 195 BOE per day, up 23% in 2006 compared to
        159 BOE per day in the previous year;

    -   Increased proved plus probable reserves by 42% to 26.4 million BOE,
        up from 18.5 million BOE at December 31, 2005 and increased net
        undeveloped land holdings by 43% to 235,308 acres compared to
        164,239 acres at December 31, 2005; and

    -   Improved the Company's net asset value per share at year-end to
        $12.25, an increase of 6% compared to $11.53 at December 31, 2005.
    

    OPERATIONS

    The year, 2006, was once again a rewarding year for Celtic. The oil and
gas industry was faced with a significant slowdown due to declining commodity
prices resulting in lower cash flows, however, Celtic continued to
aggressively drill and add land to its prospect inventory. To achieve this,
the Company benefited from its commodity price contracts whereby Celtic had
locked in high natural gas prices at certain opportune times which resulted in
Celtic achieving a netback of $38.81 per BOE in 2006. Also, the Company's
product split which is approximately 50% light oil and liquids, along with
lower than average royalties, enhanced the netback and associated cash flow.
    After drilling two wells at Kaybob at the end of 2005, Celtic was able to
tie-up 30 sections of land in 2006, most at 100% working interest. The Company
drilled a total of 14 wells in 2006 on the Kaybob South pool and other Montney
prospects in the Kaybob area. With up to six or seven BCF per section of
recoverable natural gas on this prospect, the Company has proceeded to
down-space the Kaybob South pool to three wells per section. This leaves the
Company with a very prolific development program in 2007.
    Celtic had significant success in its other core areas as well, with new
pools being discovered both at Swan Hills and Bantry. In total, 83 wells were
drilled with a success rate of 74% in 2006. Although service and land costs
were substantially higher, the Company's finding and development costs
remained competitive, compared to industry, at $16.40 per BOE before future
development capital and $19.56 after future development capital. The all-in
replacement cost gives Celtic a recycle ratio of 2.0 times which was achieved
even after incurring over $20 million for land, which will generate further
benefits in 2007. The reserve life index increased again in 2006 growing to
11.5 years, which for a growing junior company is a valuable attribute.

    PRODUCTION

    Oil and gas production in 2006 increased 35% to average 5,963 BOE per day
compared to 4,423 BOE per day in 2005. Average production in the fourth
quarter of 2006 was 6,290 BOE per day. Production per million shares
outstanding in 2006 averaged 195 BOE per day, up 23% from 159 BOE per day in
2005.
    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, Michichi and Richdale 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 and Figure Lake. In Northern Alberta, the Company produces mainly
light oil from Ogston, Otter and Utikuma Lake. In West Central Alberta, Celtic
has both natural gas and light oil production at Kaybob South, Fox Creek, Swan
Hills, Ferrier and Kakwa/Lator.

    REVENUE

    Revenue, after royalties, and after realized and unrealized gains or
losses on financial derivatives, for the year ended December 31, 2006 was
$123.3 million, an increase of 61% compared to $76.6 million in the previous
year. For the three months ended December 31, 2006, revenue was $33.1 million,
up 24% from the fourth quarter of 2005.
    The combined average product price received for oil and gas sales,
adjusted for realized gains or losses on financial derivatives for the year
ended December 31, 2006 was $61.26 per BOE, an increase of 5% compared to the
previous year. For the three months ended December 31, 2006, the average
adjusted product price received was $59.59 per BOE, down 8% from the average
adjusted price received in the fourth quarter of 2005.

    OIL OPERATIONS

    Oil production for the year ended December 31, 2006 averaged 3,284 bbls
per day, an increase of 30% compared to the previous year. For the three
months ended December 31, 2006, average oil production was 3,290 bbls per day,
up 13% from the fourth quarter of 2005.
    The average price received for oil sales, after realized financial
derivatives, for the year ended December 31, 2006 was $63.78 per bbl, an
increase of 8% compared to the previous year. For the three months ended
December 31, 2006, the average oil price received was $58.68 per bbl, up 2%
from the average price received in the fourth quarter of 2005.
    For the year ended December 31, 2006, average oil royalties were 21.0% of
sales, after financial derivatives (20.5% of sales, before financial
derivatives). In the previous year, average oil royalties were 18.0% of sales,
after financial derivatives (17.0% of sales, before financial derivatives).
Celtic participated in various royalty incentive programs in 2006 and 2005,
resulting in lower royalties for both years.
    Transportation and selling expenses for oil production in 2006 averaged
$0.54 per bbl compared to $0.61 per bbl in 2005. The lower per unit cost in
2006 reflects the smaller percentage of oil production that was trucked in
contrast to the previous year.
    For the year ended December 31, 2006, production expenses were $12.30 per
bbl. In the previous year, production expenses were $10.93 per bbl. The higher
per unit production expense in 2006 reflects the broad based increase in
service costs in the oil services industry and higher electricity prices
resulting in higher power costs incurred to operate oil handling facilities.
    The breakdown of oil netbacks for 2006 and 2005 is summarized in the
following table:

    
    Oil Netback
    Years ended December 31                      2006              2005
    -------------------------------------------------------------------------
                                           bbls/d    $/bbl   bbls/d    $/bbl
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Daily average production                3,284             2,524
    Sales price                                      65.43             62.06
    Loss on financial derivatives                    (1.65)            (3.15)
    Royalties                                       (13.40)           (10.58)
    Production expense                              (12.30)           (10.93)
    Transportation and selling expense               (0.54)            (0.61)
    -------------------------------------------------------------------------
    Oil netback                                      37.54             36.79
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    NATURAL GAS OPERATIONS

    Natural gas production for the year ended December 31, 2006 averaged
16,072 mcf per day, an increase of 41% compared to the previous year. For the
three months ended December 31, 2006, average natural gas production was
18,001 mcf per day, up 38% from the fourth quarter of 2006.
    The average price received for natural gas sales, after realized
financial derivatives, for the year ended December 31, 2006 was $9.71 per mcf,
an increase of 1% compared to the previous year. For the three months ended
December 31, 2006, the average natural gas price received was $10.10 per mcf,
down 19% from the average price received in the fourth quarter of 2005.
    For the year ended December 31, 2006, average natural gas royalties were
13.4% of sales, after financial derivatives (15.3% of sales, before financial
derivatives). In the previous year, average natural gas royalties were 19.9%
of sales. Celtic participated in various royalty incentive programs in 2006
and 2005, resulting in lower royalties for both years.
    Transportation and selling expenses for the year ended December 31, 2006
were $0.13 per mcf, an improvement of 13% compared to $0.15 per mcf for the
previous year.
    For the year ended December 31, 2006, production expenses were $1.53 per
mcf. In the previous year, production expenses were $1.27 per mcf.
    The breakdown of natural gas netbacks for 2006 and 2005 is summarized in
the following table:

    
    Natural Gas Netback
    Years ended December 31                      2006              2005
    -------------------------------------------------------------------------
                                            mcf/d    $/mcf    mcf/d    $/mcf
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Daily average production               16,072            11,396
    Sales price                                       8.52              9.63
    Gain (loss) on financial derivatives              1.19                 -
    Royalties                                        (1.30)            (1.92)
    Production expense                               (1.53)            (1.27)
    Transportation and selling expense               (0.13)            (0.15)
    -------------------------------------------------------------------------
    Natural gas netback                               6.75              6.29
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    



    INTEREST EXPENSE

    The Company has a committed term credit facility. The authorized
borrowing amount under this facility is $115.0 million. Interest is payable
monthly for borrowings through direct advances. Under the credit facility,
borrowings through the use of bankers' acceptances are also available.
Interest expense for the year was $4.0 million at an average rate of 5.6%
compared to $1.1 million at an average rate of 4.2% in 2005.

    GENERAL AND ADMINISTRATIVE EXPENSES

    General and administrative expenses for the year ended December 31, 2006
were $2.0 million or $0.91 per BOE compared to $1.9 million or $1.19 per BOE
in 2005. General and administrative expenses are reduced by overhead recovered
on Company operated properties. In addition, salaries relating to geological
and geophysical personnel are capitalized.

    STOCK BASED COMPENSATION EXPENSE

    For the year ended December 31, 2006, stock based compensation expense
was $1.1 million, compared to $0.8 million in 2005. The fair value of each
option granted is estimated on the date of grant using the Black-Scholes
option pricing model with weighted average assumptions.

    DEPLETION, DEPRECIATION AND AMORTIZATION

    The Company follows the full cost method of accounting whereby all costs
relating to the exploration and development of oil and gas reserves are
capitalized. These capitalized costs along with estimated future capital
expenditures to be incurred in order to develop proved reserves, are depleted
and depreciated on a unit of production basis using estimated proved oil and
gas reserves as evaluated by independent engineers. Depreciation of furniture
and office equipment is provided using the declining balance method at a rate
of 25%. Estimated future costs relating to asset retirement obligations are
provided for on a unit of production basis and the provision is included in
depletion, depreciation and amortization.
    Depletion, depreciation and amortization expense for the period ended
December 31, 2006 was $43.4 million or $19.96 per BOE, compared to the
previous year's amount of $28.9 million or $17.89 per BOE.

    CEILING TEST

    The Company performed a ceiling test calculation at December 31, 2006 in
accordance with the CICA full cost accounting guidelines. As a result of the
calculation, Celtic was not required to record an impairment loss. In
addition, based on the calculation in the previous year conducted at
December 31, 2005, there was no impairment loss required.

    TAXES

    For the year ended December 31, 2006, Celtic provided for a provision of
future income taxes in the amount of $11.9 million. This amount differs from
the expected provision for income taxes of $16.2 million based on the
statutory combined income tax rate of 34.5% due to the differences between the
resource allowance deduction and non-deductible Crown charges and non-taxable
Provincial tax credits ("Alberta Royalty Tax Credit" or "ARTC") and the
recognition of a benefit of $4.0 million related to substantively enacted
changes to the federal income tax rate and resource related deductions from
income. These changes, which will be phased in over the next four years, will
result in a lower corporate income tax rate, provide for the deduction of
crown royalties and eliminate the resource allowance deduction. An analysis of
the income tax provision is included in the notes to the financial statements.
    At December 31, 2006, Celtic had estimated unused income tax deductions
available of approximately $222.0 million.

    NET EARNINGS AND FUNDS FROM OPERATIONS

    Net earnings for the year ended December 31, 2006 was $35.2 million
($1.15 per share, basic and $1.12 per share, diluted). During the same period,
funds from operations were $78.5 million ($2.57 per share, basic and $2.50 per
share, diluted).

    CAPITAL EXPENDITURES

    Celtic is committed to future growth through its strategy to augment
strategic oil and gas acquisitions with exploitation upside, and at the same
time, implement a full cycle exploration and development program. Since the
Company began active oil and gas operations in September 2002, Celtic has
completed several corporate and property acquisitions in order to establish a
cash flow platform and an inventory of exploration and development prospects
from which the Company can grow through the drill bit. Examples of where
Celtic has successfully employed its strategy to acquire an initial position
in an area and subsequently expand the area making it core to the Company
include Fox Creek, Ashmont, Princess/Bantry and Swan Hills.
    During the year ended December 31, 2006, Celtic incurred $173.7 million
on exploration and development activity, $0.5 million on property acquisitions
and received net proceeds of $10.1 million from property dispositions.
Drilling and completion operations accounted for $104.9 million and equipment
and facility expenditures were $45.1 million. The balance of $23.7 million was
spent on land and seismic, building the Company's inventory of prospects for
future drilling. Approximately 53% of net wells drilled were development and
47% were exploratory.

    UNDEVELOPED LAND

    As at December 31, 2006, Celtic owned 235,308 net acres of undeveloped
land, representing a 43% increase compared to 164,239 net acres at the end of
2005. Approximately 17% of the Company's undeveloped land position is subject
to expiry in 2007, if not developed. Celtic holds an average working interest
of 73% in its undeveloped lands.
    In 2006, Celtic incurred $20.2 million at Alberta Crown land sales
acquiring 68,950 net acres of petroleum and natural gas rights at an average
cost of $293 per acre; compared to an industry average of $325 per acre. Of
major significance was Celtic's acquisition of highly prospective Montney
rights at Kaybob South. At December 31, 2006, Celtic owned a 100% interest in
25,280 acres (39.5 sections) of land at Kaybob South.
    Looking ahead to 2007, Celtic will continue its internally generated,
prospect-driven land acquisition strategy. This strategy will be complemented
by third party farm-in arrangements in core exploration areas. Celtic's land
acquisition strategy remains focused on building a significant base of high
working interest operated prospects, ensuring the Company is in a position to
control its capital expenditure program.

    DRILLING

    During the year ended December 31, 2006, Celtic drilled 83 (62.8 net)
wells compared to 100 (68.1 net) wells in the previous year, with an overall
success rate of 74% on net wells drilled. The Company's average working
interest in wells drilled during 2006 increased to 76% compared to an average
working interest of 68% in 2005. The split between development drilling and
exploratory drilling was 53% and 47%, respectively. The average depth of net
wells drilled was 2,311 metres, 17% deeper than the average drilling depth of
1,967 metres in 2005.

    RESERVES

    Celtic retains Sproule Associates Limited ("Sproule"), an independent
qualified reserve evaluator to prepare a report on 100% of its oil and gas
reserves. The Company has a Reserves Committee which oversees the selection,
qualifications and reporting procedures of the independent engineering
consultants. Reserves as at December 31, 2006 were determined using the
guidelines and definitions set out under National Instrument 51-101 ("NI
51-101"). At December 31, 2006, Celtic's proved plus probable reserves were
26.4 million BOE, up 43% from 18.5 million BOE at the end of 2005.
    The following table outlines the change in the Company's reserves
year-over-year:

    
    Reserves Reconciliation
                               Oil           Natural Gas        Combined
    -------------------------------------------------------------------------
                          Total  Proved +   Total  Proved +   Total  Proved +
                         Proved  Probable  Proved  Probable  Proved  Probable
                          mbbls    mbbls    mmcf     mmcf     mBOE     mBOE
    -------------------------------------------------------------------------

    Balance,
     December 31, 2005    6,267   10,527   29,012   47,992   11,103   18,526
    Technical revisions    (107)  (1,182)  (3,909)  (9,812)    (759)  (2,817)
    Discoveries             467      719    6,366    9,645    1,527    2,326
    Extensions            1,106    1,628   12,009   19,354    3,108    4,854
    Improved recoveries     393    1,393   13,509   30,229    2,645    6,431
    Economic factors        (99)    (168)    (452)    (754)    (174)    (294)
    Dispositions            (59)     (85)  (1,670)  (2,461)    (337)    (495)
    -------------------------------------------------------------------------
    Net additions         1,701    2,305   25,853   46,201    6,010   10,005
    -------------------------------------------------------------------------
    Production           (1,198)  (1,198)  (5,866)  (5,866)  (2,176)  (2,176)
    -------------------------------------------------------------------------
    Balance,
     December 31, 2006    6,770   11,634   48,999   88,327   14,937   26,355
    -------------------------------------------------------------------------
    Percentage increase
     in reserves             8%      11%      69%      84%      35%      42%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Company created value for its shareholders in 2006 increasing the net
present value of proved plus probable reserves, discounted at 10% before tax,
to $470.6 million, up 21% from $389.0 million at December 31, 2005. In
addition, the quality of reserves improved resulting in a reserve life index
of 11.5 years compared to 10.0 years at December 31, 2005. At December 31,
2006, proved plus probable reserves were 44% oil and 56% natural gas.
    The following table outlines a summary of the Company's reserves at
December 31, 2006:

    
    Summary of Reserves

                                                 Q4
                                                2006  Reserve   NPV     NPV
                                          Com-  Prod-   Life  10% BIT   per
    As at December 31,     Oil     Gas   bined  uction Index  $ thou-   BOE
     2006                 mbbls   mmcf    mBOE  BOE/d  Years   sands   $/BOE
    -------------------------------------------------------------------------

    Proved producing      6,174  29,099  11,024  6,290   4.8  254,471  23.08
    Total proved          6,770  48,999  14,937  6,290   6.5  309,602  20.73
    Total proved
     plus probable       11,634  88,327  26,355  6,290  11.5  470,559  17.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Oil and gas selling prices have steadily increased over the past five
years and current futures contracts indicate that prices will be higher in
future years compared to historical averages.
    Sproule is forecasting WTI oil prices to average US$62.11 per bbl over
the next five years, 40% higher than the average price of US$44.24 per bbl
over the past five years. Similarly for natural gas, Henry Hub NYMEX natural
gas prices are forecasted to average US$7.80 per mmbtu over the 2007 to 2011
period, an increase of 27% from the average price of US$6.12 per mmbtu during
the 2002 to 2006 period.
    During 2006, the Company's capital expenditures, net of dispositions,
resulted in proved plus probable reserve additions (before technical
revisions) of 12.8 million BOE, resulting in finding, development and
acquisition ("FD&A") costs of $12.79 per BOE ($15.27 per BOE including future
capital expenditures required to develop reserves). After technical revisions,
FD&A costs were $16.40 per BOE ($19.56 per BOE including future capital
expenditures required to develop reserves). The recycle ratio is a measure for
evaluating the effectiveness of a company's re-investment program. The ratio
measures the efficiency of capital investment. It accomplishes this by
comparing the operating netback per BOE to that years' reserve FD&A cost per
BOE. Since incorporation, Celtic has successfully achieved a recycle ratio of
2.3 times on a proved plus probable basis.
    The following table provides detailed calculations relating to FD&A costs
and recycle ratios for 2006 and 2005:

    
    Finding, Development and Acquisition Costs
                                                                  Cumulative
                                        Year ended   Year ended        since
                                       December 31, December 31,      incor-
                                              2006         2005     poration
    -------------------------------------------------------------------------

    Proved Reserves
    Capital expenditures ($ 000's)         164,050      119,230      424,608
    Change in future capital costs
     required to develop reserves
     ($ 000's)                              18,811        7,211       30,852
    -------------------------------------------------------------------------
    Total capital costs ($ 000's)          182,861      126,441      455,460
    -------------------------------------------------------------------------
    Reserve additions, before revisions
     (mBOE)                                  6,769        5,147       21,579
    -------------------------------------------------------------------------
    FD&A cost, before revisions and
     future capital ($/BOE)                  24.24        23.16        19.68
    -------------------------------------------------------------------------
    FD&A cost, before revisions,
     including future capital ($/BOE)        27.01        24.57        21.11
    -------------------------------------------------------------------------
    Reserve additions, including
     revisions (mBOE)                        6,010        5,631       20,792
    -------------------------------------------------------------------------
    FD&A cost, including revisions,
     before future capital ($/BOE)            27.3        21.17        20.42
    -------------------------------------------------------------------------
    FD&A cost, including revisions and
     future capital ($/BOE)                  30.43        22.45        21.91
    -------------------------------------------------------------------------
    Operating netback ($/BOE)                38.81         37.2        34.21
    -------------------------------------------------------------------------
    Recycle ratio - proved                     1.3          1.7          1.6
    -------------------------------------------------------------------------

    Proved plus Probable Reserves
    Capital expenditures ($ 000's)         164,050      119,230      424,608
    Change in future capital costs
     required to develop reserves
     ($ 000's)                              31,690       13,856       53,598
    -------------------------------------------------------------------------
    Total capital costs ($ 000's)          195,740      133,086      478,206
    -------------------------------------------------------------------------
    Reserve additions, before revisions
     (mBOE)                                 12,822        9,360       36,333
    -------------------------------------------------------------------------
    FD&A cost, before revisions and
     future capital ($/BOE)                  12.79        12.74        11.69
    -------------------------------------------------------------------------
    FD&A cost, before revisions,
     including future capital ($/BOE)        15.27        14.22        13.16
    -------------------------------------------------------------------------
    Reserve additions, including
     revisions (mBOE)                       10,005        9,089       32,210
    -------------------------------------------------------------------------
    FD&A cost, including revisions,
     before future capital ($/BOE)            16.4        13.12        13.18
    -------------------------------------------------------------------------
    FD&A cost, including revisions and
     future capital ($/BOE)                  19.56        14.64        14.85
    -------------------------------------------------------------------------
    Operating netback ($/BOE)                38.81         37.2        34.21
    -------------------------------------------------------------------------
    Recycle ratio - proved plus probable         2          2.5          2.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Celtic's 2006 capital investment program replaced 2006 production by a
factor of 2.8 times on a proved basis and 4.6 times on a proved plus probable
basis.

    NET ASSET VALUE

    Celtic's net asset value at December 31, 2006, discounting the present
value of reserves at 10% before tax, increased to $426.4 million
($465.5 million using an 8% discount rate, before tax), up 18% from $360.2
million at December 31, 2005. On a per share basis, net asset value increased
6% to $12.25 per share ($13.37 per share using an 8% discount rate, before
tax). The present value of petroleum and natural gas ("P&NG") reserves were
determined by Sproule in their year-end evaluation report. Undeveloped land at
December 31, 2006 was valued at an average price of $140 per acre.
    The components of net assets value are summarized in the following table:

    
    Net Asset Value
    At December 31                            2006         2006         2005
    -------------------------------------------------------------------------
                                          Forecast     Forecast     Forecast
                                         Prices 8%   Prices 10%   Prices 10%
                                          Discount     Discount     Discount
                                              Rate         Rate         Rate
                                       $ thousands  $ thousands  $ thousands
    -------------------------------------------------------------------------

    Present value of P&NG reserves,
     discounted, before tax                509,732      470,559      389,030
    Undeveloped land                        32,949       32,949       19,709
    Bank debt, net of working capital      (98,236)     (98,236)     (63,426)
    Proceeds from exercise
     of stock options                       21,097       21,097       14,849
    -------------------------------------------------------------------------
    Net asset value                        465,542      426,369      360,162
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Diluted common shares outstanding
     (thousands)                            34,810       34,810       31,229
    Net asset value per share ($/share)      13.37        12.25        11.53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    MARKET CAPITALIZATION

    The Company's total capitalization increased 30% to $586.9 million at
December 31, 2006. Market value of common shares represented 76% of total
capitalization, while debt and working capital represented 17% of total
capitalization.
    At December 31, 2006, the Company had $101.8 million outstanding on its
credit facility. Total debt, including working capital surplus was
$98.2 million, representing approximately 1.3 times 2006 funds from operations
and approximately 1.0 times forecasted 2007 funds from operations.

    

SOURCE OF FUNDS Investment funding for capital expenditures incurred in 2006 was provided by proceeds from equity financings, bank debt and cash provided by operating activities. In May 2006, Celtic completed the issuance of 2.0 million common shares by way of private placement, at a price of $13.15 per share and in September 2006, the Company issued 1.0 million common shares on a flow-through basis by way of private placement, at a price of $17.25 per share. These equity offerings resulted in gross proceeds of $43.5 million. The Company has in place a committed term credit facility with Canadian financial institutions. The maximum amount available to be drawn under this facility at December 31, 2006 was $115.0 million. At December 31, 2006, Celtic had drawn $101.8 million, leaving sufficient unused credit lines available to fund on-going capital expenditures. The maximum amount available under this credit facility may increase after the Company's lenders complete their annual review in April 2006. In order to fund all capital expenditures incurred in 2006, the Company augmented its equity financing and bank borrowings by generating $81.6 million in cash provided by operating activities for the year ended December 31, 2006. 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. SHARE INFORMATION The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares. As at December 31, 2006, there were 32.2 million common shares outstanding. There were no preferred shares outstanding. As at December 31, 2006, directors, employees and consultants have been granted options to purchase 2.6 million common shares of the Company at an average exercise price of $8.02 per share. Detailed information regarding the Company's stock options outstanding is contained in the notes to the financial statements. The Company's common shares trade on the Toronto Stock Exchange under the symbol "CLT". 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. 2007 FORECAST Celtic is optimistic about its future prospects. The Company was successful in establishing a production base during the early months since commencing operations that provides a cash flow stream that can be re-invested in Celtic's ongoing exploration and development activity. 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 for light gravity crude oil and liquids-rich natural gas. Celtic's Board of Directors has approved a capital expenditure budget in the amount of $140 million for 2007. This capital spending will be financed by funds from operations, bank credit lines and a flow-through share equity offering completed in February 2007. After forecasting risked production discoveries, timing of production on-stream dates resulting from the Company's planned capital expenditures for 2007 and estimated decline rates on existing volumes, Celtic expects production in 2007 to average between 8,300 and 8,700 BOE/d (46% oil and 54% gas). This represents a 39% to 46% increase from average production of 5,963 BOE/d in 2006. Political turmoil in major oil producing regions around the world continues to remain in the headlines and could potentially put a strain on stable world oil supply in the future. However, high oil prices recorded in 2006 may have affected world oil demand negatively and the move by nations around the world to curtail carbon emissions may lead to the development of other energy sources resulting in a slower growth for the demand for oil. As a result of these and other factors, Celtic expects oil prices to be lower in 2007 compared to 2006. Natural gas demand in North America was considerably lower in 2006 compared to the previous year, primarily due to milder weather causing lower heating demand and industrial demand destruction as a result of high prices realized towards the end of 2005. However, natural gas prices in 2007 should benefit from the reduced supply resulting from a slow down in natural gas drilling in Canada during the past few months. The Company's commodity price assumptions for 2007 are US$62.00 per barrel for WTI oil, US $7.50 per mmbtu for natural gas and a US/Canadian exchange rate of US$0.855. These prices compare to 2006 average prices of US $66.22 per barrel for WTI oil, US $7.26 per mmbtu for NYMEX natural gas and a US/Canadian exchange rate of US $0.882. After giving effect to the aforementioned production and commodity price assumptions and taking into effect commodity risk price management contracts in place (as outlined in detail in the notes to the financial statements), funds from operations for 2007 is forecasted to be approximately $100.2 million or $3.00 per share ($2.90 per share, diluted) and net earnings is forecasted to be approximately $10.7 million or $0.32 per share ($0.31 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 reach $123.7 million by the end of 2007 or approximately 1.2 times forecasted 2007 funds from operations. Celtic's capital expenditure budget for 2007 will see the Company participate at high working interests in the drilling of approximately 75 to 85 wells during the year. Celtic continues to pursue 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, funds from operations and earnings. Given the Company's strong inventory of drilling locations, we look forward to continued growth in 2007. NON-GAAP FINANCIAL MEASUREMENTS This document contains the terms "funds from operations" and "operating netbacks" 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. The reconciliation between net earnings and funds from operations can be found in the statement of cash flows included in the audited financial statements. Operating netbacks are determined by deducting royalties, production expenses and transportation and selling expenses from oil and gas sales 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. 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. CRITICAL ACCOUNTING ESTIMATES Management is required to make judgments, assumptions and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company. Capitalized costs relating to the exploration and development of oil and gas reserves, along with estimated future capital expenditures required in order to develop proved reserves, are depleted and depreciated on a unit-of-production basis using estimated proved reserves. The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved reserves, production rates, oil and gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Liability recognition for asset retirement obligations associated with oil and gas well sites and facilities are determined using estimated costs discounted based on the estimated life of the asset. These capitalized costs are amortized on a unit-of-production basis, consistent with depletion and depreciation. Over time, the liability is accreted up to the actual expected cash outlay to perform the abandonment and reclamation. In order to recognize stock based compensation expense, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, volatility of the underlying security and expected dividend yields. These assumptions may vary over time. The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded on Celtic's financial statements. 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. The Company expects to mail out its Annual Report to shareholders on March 27th, 2007. Celtic's Annual & Special Meeting of Shareholders is scheduled for April 24th, 2007, at 3:00 PM, to be held at the Metropolitan Centre, 333 Fourth Avenue S.W., Calgary, Alberta.

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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Celtic Exploration Ltd.

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