Celtic Exploration Ltd.
TSX : CLT

Celtic Exploration Ltd.

February 18, 2010 14:46 ET

Celtic Reports 2009 Operating Results Highlighted by Significant Increases in Production and Lower Finding Costs

CALGARY, ALBERTA--(Marketwire - Feb. 18, 2010) - Celtic Exploration Ltd. ("Celtic" or the "Company") (TSX:CLT) has released its operating results for the three months and twelve months ended December 31, 2009. Summary of results are as follows:

  Three months ended December 31,   Twelve months ended December 31,  
  2009   2008   Change   2009   2008   Change  
                         
Production                        
  Oil [BBLS/d] 4,384   3,554   23 % 3,687   3,404   8 %
  Gas [MCF/D] 77,339   51,029   52 % 63,028   46,000   37 %
  Combined [BOE/D] 17,274   12,059   43 % 14,192   11,071   28 %
                         
Production per million shares [BOE/D] 388   293   32 % 327   276   18 %
                         
Drilling activity                        
  Total wells 17   14   21 % 55   54   2 %
  Working interest wells 9.6   10.2   -6 % 43.0   41.1   5 %
  Success rate on working interest wells 100 % 100 % -   91 % 88 % 3 %
                         
Undeveloped land                        
  Gross acres             363,473   318,969   14 %
  Net acres             294,700   246,629   19 %
                         
Reserves                        
  Oil [MBBLs]             15,042   14,372   5 %
  Gas [MMCF]             272,236   235,353   16 %
  Combined [MBOE]             60,415   53,598   13 %
                         
Finding, development & acquisition cost *                        
  Proved [$/BOE]             $12.89   $19.43   -34 %
  Proved plus Probable [$/BOE]             $9.84   $12.24   -20 %
                         
  Recycle ratio [P+P] *             2.5 x   2.9 x   -14 %
                         

* Finding, development and acquisition ("FD&A") cost and recycle ratio relating to 2009 have been calculated using unaudited financial information. FD&A calculations include future development capital ("FDC") expenditures that are required to develop reserves.

Highlights

  • Drilled 55 (43.0 net working interest) wells during 2009 resulting in 50 (38.9 net) gas wells and 1 (0.3 net) oil well, for an overall success rate, based on net wells, of 91%;
  • Increased average daily production by 28% to 14,192 BOE per day, up from 11,071 BOE per day in 2008 and achieved daily average production per million shares of 327 BOE per day, up 18% in 2009 compared to 276 BOE per day in the previous year;
  • Increased proved plus probable reserves by 13% to 60.4 million BOE, up from 53.6 million BOE at December 31, 2008 and replaced 2009 production by a factor of 2.3 times;
  • Reported FD&A cost (including FDC) of $9.84 per BOE resulting in a recycle ratio of 2.5 times based on proved plus probable reserves; and
  • Accumulated additional undeveloped land in new resource play prospects targeting the Triassic Montney, Cretaceous Bluesky, Cretaceous Notikewin and Devonian Duvernay formations in west central Alberta;

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, 2009 were determined using the guidelines and definitions set out under National Instrument 51-101 ("NI 51-101"). At December 31, 2009, Celtic's proved plus probable reserves were 60.4 million BOE, up 13% from 53.6 million BOE at the end of 2008.

The Company increased the net present value of proved plus probable reserves, discounted at 10% before tax, to $1,011.9 million, up 14% from $891.0 million at December 31, 2008. The reserve life index was 9.6 years compared to 12.1 years at December 31, 2008. At December 31, 2009, the weighting of proved plus probable reserves was 25% oil and 75% gas.

The following table outlines a summary of the Company's reserves at December 31, 2009:

Summary of Reserves        
  Oil [MBBLs] Gas [MMCF] Combined [MBOE] FDC Costs [$000's]
Proved Developed Producing 6,426 101,854 23,402  
Proved Developed Non-producing 511 8,638 1,951  
Proved Undeveloped 1,919 49,100 10,102  
Total Proved 8,856 159,592 35,455 90,473
Probable Additional 6,186 112,644 24,960  
Total Proved plus Probable 15,042 272,236 60,415 145,017

FDC expenditures included in the reserve evaluation have been reduced by drilling royalty credits ("DRC's") earned and expected to be claimed in the respective future years. FDC included in the total proved reserve evaluation are expected to be spent as follows: $69.8 million in 2010, $19.8 million in 2011 and $0.9 million in 2012 and thereafter. FDC included in the proved plus probable reserve evaluation are expected to be spent as follows: $92.3 million in 2010, $42.9 million in 2011 and $9.8 million in 2012 and thereafter.

The following table outlines the change in the Company's reserves year-over-year:

Reserves Reconcilliation                        
  Oil
Total
Proved
[MBBLs]
  Oil
Proved +
Probable
[MBBLs]
  Gas
Total
Proved
[MMCF]
  Gas
Proved +
Probable
[MMCF]
  Combined
Total
Proved
[MBOE]
  Combined
Proved +
Probable
[MBOE]
 
                         
Balance, December 31, 2008 8,321   14,372   125,330   235,353   29,209   53,598  
                         
Technical Revisions 56   (78 ) 5,628   2,683   994   369  
Extensions 853   1,024   29,296   37,726   5,736   7,312  
Infill Drilling 900   972   20,415   16,817   4,303   3,775  
Economic Factors 39   55   1,032   1,502   211   305  
Acquisitions 33   43   896   1,160   182   236  
                         
Net Additions 1,881   2,016   57,267   59,888   11,426   11,997  
                         
Production (1,346 ) (1,346 ) (23,005 ) (23,005 ) (5,180 ) (5,180 )
                         
Balance, December 31, 2009 8,856   15,042   159,592   272,236   35,455   60,415  
                         
Percentage Increase in Reserves 6 % 5 % 27 % 16 % 21 % 13 %

The average price of oil steadily increased in each of the years from 2005 to 2008; however, in 2009 oil prices were considerably lower than the previous year. Average annual natural gas prices at AECO-C from 2005 to 2008 have traded in a narrower range of $6.31 to $8.14 per GJ; however, in 2009, AECO-C averaged a much lower price of $3.97 per GJ.

The following table outlines forecasted future prices that Sproule has used in their evaluation of the Company's reserves at December 31, 2009:

Future Commodity Price Forecast        
  WTI Cushing Crude Oil
[US$/BBL]
NYMEX HH Natural Gas
[US$/MMBTU]
AECO-C Natural Gas
[$/GJ]
USD/CAD Exchange
[US$]
2010 79.17 5.70 5.08 0.920
2011 84.46 6.48 5.89 0.920
2012 86.89 6.70 6.11 0.920
2013 90.20 7.43 6.86 0.920
2014 92.01 8.12 7.57 0.920
Five Year Average 86.55 6.89 6.30 0.920

Sproule is forecasting WTI oil prices to average US$86.55 per bbl over the next five years, 22% higher than the average price of US$71.21 per bbl over the past five years. For natural gas, AECO-C natural gas prices are forecasted to average $6.30 per GJ over the 2010 to 2014 period, a decrease of 4% from the average price of $6.59 per GJ during the 2005 to 2009 period.

The Company increased the net present value of proved plus probable reserves, discounted at 10% before tax, to $1,011.9 million, up 14% from $891.0 million at December 31, 2008.

The following table is a net present value summary (before tax) as at December 31, 2009:

Net Present Value Summary (before tax)        
  Undiscounted
[$000's]
NPV 5% BT
[$000's]
NPV 10% BT
[$000's]
NPV 15% BT
[$000's]
Proved Developed Producing 718,141 564,785 472,544 409,967
Proved Developed Non-producing 50,831 41,427 34,855 30,023
Proved Undeveloped 257,241 184,143 140,790 111,997
Total Proved 1,026,213 790,355 648,189 551,987
Probable Additional 838,906 514,053 363,750 278,546
Total Proved plus Probable 1,865,119 1,304,408 1,011,939 830,533

The following table is a net present value summary (after tax) as at December 31, 2009:

Net Present Value Summary (after tax)        
  Undiscounted
[$000's]
NPV 5% AT
[$000's]
NPV 10% AT
[$000's]
NPV 15% AT
[$000's]
Proved Developed Producing 640,524 508,759 429,060 374,694
Proved Developed Non-producing 37,734 30,476 25,418 21,705
Proved Undeveloped 191,377 134,055 99,840 77,037
Total Proved 869,635 673,290 554,318 473,436
Probable Additional 627,164 381,958 268,232 203,669
Total Proved plus Probable 1,496,799 1,055,248 822,550 677,105

During 2009, the Company's capital expenditures (unaudited), net of dispositions, resulted in proved plus probable reserve additions of 12.0 million (23.5 million in 2008) BOE, resulting in FD&A costs of $9.84 ($12.24 in 2008) per BOE, including FDC costs. Proved reserve additions in 2009 were 11.4 million (12.2 million in 2008) BOE, resulting in FD&A costs of $12.89 ($19.43 in 2008) per BOE, including FDC costs.

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. In 2009, the recycle ratio was 2.5 times.

The following table provides detailed calculations relating to FD&A costs and recycle ratios for 2009 and 2008:

FD&A Costs: Proved Reserves Year ended
December 31,
2009 (after DRC's
) Year ended
December 31,
2009 (before DRC's
) Year ended
December 31,
2008
Cumulative
since
incorporation
             
Capital expenditures [$000's] [unaudited] 148,761   169,380   183,478 936,635
Change in FDC costs required to develop reserves [$000's] (1,483 ) 11,270   54,106 90,473
Total capital costs [$000's] 147,278   180,650   237,584 1,027,108
Reserve additions, net [MBOE] 11,426   11,426   12,227 53,153
FD&A cost, before FDC [$/BOE] 13.02   14.82   15.01 17.62
FD&A cost, including FDC [$/BOE] 12.89   15.81   19.43 19.32
Operating netback [$/BOE] [unaudited] 25.00   25.00   34.95 31.40
Recycle ratio – proved 1.9 x   1.6 x   1.8 x 1.6 x
             
             
FD&A Costs: P+P Reserves Year ended
December 31,
2009 (after DRC's
) Year ended
December 31,
2009 (before DRC's
Year ended
December 31,
2008
Cumulative
since
incorporation
             
Capital expenditures [$000's] [unaudited] 148,761   169,380   183,478 936,635
Change in FDC costs required to develop reserves [$000's] (30,697 ) (9,016 ) 103,608 145,017
Total capital costs [$000's] 118,064   160,364   287,086 1,081,652
Reserve additions, net [MBOE] 11,997   11,997   23,457 77,956
FD&A cost, before FDC [$/BOE] 12.40   14.12   7.82 12.01
FD&A cost, including FDC [$/BOE] 9.84   13.37   12.24 13.88
Operating netback [$/BOE] [unaudited] 25.00   25.00   34.95 31.40
Recycle ratio – proved plus probable 2.5 x   1.9 x   2.9 x 2.3 x

Celtic's 2009 capital investment program resulted in net reserve additions that replaced 2009 production by a factor of 2.2 (3.0 in 2008) times on a proved basis and 2.3 (5.8 in 2008) times on a proved plus probable basis.

Common 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, 2009, there were 44.6 million common shares outstanding. There were no preferred shares outstanding. As at December 31, 2009, directors, employees and certain consultants have been granted options to purchase 3.3 million common shares of the Company at an average exercise price of $13.90 per share. The Company's common shares trade on the Toronto Stock Exchange ("TSX") 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.

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. Sulphur volumes have been converted to natural gas equivalence at one long ton per 10 thousand cubic feet.

Contact Information

  • Celtic Exploration Ltd.
    David J. Wilson
    President and Chief Executive Officer
    (403) 201-5340
    or
    Celtic Exploration Ltd.
    Sadiq H. Lalani
    Vice President, Finance and Chief Financial Officer
    (403) 215-5310
    or
    Celtic Exploration Ltd.
    Suite 500, 505 - 3rd Street SW
    Calgary, Alberta, Canada
    T2P 3E6
    www.celticex.com