Celtic Exploration Ltd.
TSX : CLT

Celtic Exploration Ltd.

January 17, 2011 18:30 ET

Celtic Provides Operations and Guidance Update

CALGARY, ALBERTA--(Marketwire - Jan. 17, 2011) - Celtic Exploration Ltd. ("Celtic" or the "Company") (TSX:CLT) is pleased to provide an update on exploration activity and operations and to update guidance expectations. Please refer to the advisory regarding forward-looking statements at the end of this news release.

Resthaven - Montney

On November 17, 2010, Celtic provided an exploration update relating to its activity at Resthaven, Lator and Karr (collectively, the "Resthaven area") in west central Alberta. Since that date, the Company has continued to add to its land position in the area. As at December 31, 2010, the Company holds an interest in 384,972 gross acres (602 sections) and 383,692 net acres (600 sections) with Triassic Montney rights in the Resthaven area.

Celtic's horizontal discovery well located at 02-07-061-02W6 (100% WI) has been on production since early November 2010 at 5.0 MMCF per day of natural gas and 240 barrels per day of condensate. Celtic has followed up with additional drilling to its horizontal discovery well as outlined below.

Approximately ten miles south of the discovery well, Celtic has drilled and is currently completing a horizontal well located at 08-36-059-02W6 (100% WI). Unlike the 02-07 well that was completed only in the middle Montney, this well was drilled and will be completed in both the upper and middle Montney formations. The Company has completed the upper Montney section of the horizontal lateral with a four-stage slick water/hybrid fracture technique. The well has flowed back at rates in excess of 5.0 MMCF per day on clean up. The Company is encouraged by these results and expects to complete the remainder of the well in the middle Montney using a slick water fracture technique, stimulating six more stages.

The Company drilled a vertical strat test in the northwest area of Celtic's acreage located at 02-33-062-04W6 (50% WI) and has cored and cased the well. The Company will re-enter the well and drill it horizontally in 2011.
In the north and northeast areas of Celtic's acreage, the Company has re-entered two vertical well bores located at 07-35-062-03W6 (100% WI) and at 10-19-062-01W6 (100% WI). Both wells have been drilled and will be completed and tested. In addition, the Company has identified several re-entry completions that are planned on wells that were previously drilled and cased through the Montney formation, but have since been abandoned.

Celtic is currently drilling a horizontal well located at 14-04-061-02W6 (100% WI) which is approximately three miles east of the 02-07 discovery well. The Company is also participating in the drilling of another horizontal well located at 16-27-061-02W6 on a five section farm-in land block where it will pay 30% of the costs to earn a 30% WI in the section subject to a non-convertible royalty and a 21 % WI in the remaining four sections of land. This well is located approximately four miles northeast of the 02-07 discovery well. At the end of January the Company plans to spud a horizontal well located at 14-31-060-02W6 which is approximately two miles south of the 02-07 discovery well.

The Company has designed the potential gas gathering pipeline system that it will begin construction on during the first quarter of 2011. As a result, the majority of new production from the Resthaven area is expected to commence in the third quarter of 2011.

Recent land sale activity offsetting Celtic's Resthaven lands has yielded significant bonus payments, both on a total bonus and on a per hectare basis. At the November 17, 2010 Crown land sale, the high bonus of the sale was $14.5 MM for a 3,584 hectare (8,960 acres or 14 sections) parcel ($4,054/ha or $1,622/acre) directly adjacent to Celtic's newly drilled 02-33-062-04W6 vertical Montney well. More recently, at the January 12, 2011 land sale the high bonus of the sale was $16.8 MM for a 2,560 hectare (6,400 acres or 10 sections) parcel ($6,567/ha or $2,627/acre) located proximal to Celtic's Resthaven holdings. An adjacent 2,048 hectare (5,120 acres or 8 sections) parcel was also acquired at the same sale for $13.4 MM ($6,527/ha or $2,611/acre).

Celtic is excited about this new resource play in the Triassic Montney formation and expects over 50% of its planned capital expenditures in 2011 to be in the Resthaven area.

Resthaven/Karr - Cretaceous

In addition to the Montney exploration and development program, Celtic has assembled a significant land position with Cretaceous rights in the Resthaven, Lator and Karr areas of west central Alberta. As at December 31, 2010, the Company holds an interest in 96,546 gross acres (150 sections) and 95,380 net acres (149 sections) with certain Cretaceous rights.

At Karr, in the northern area of the Company's land position, a Cretaceous horizontal test well located at 13-29-065-04W6 (100% WI) was drilled and completed. The well was completed in the horizontal section in the Bluesky formation and in the vertical section, it was completed in the Falher and Wilrich formations. This well is expected to be put on production at approximately 2.0 MMCF per day during February 2011. Celtic will continue to drill wells targeting high impact Bluesky, Falher, Dunvegan, Willrich, Gething and Cadomin formations on its existing 149 section land block.

Kaybob - Duvernay

At Kaybob, Celtic is active drilling wells targeting the Devonian Duvernay shale formation as a follow-up to its discovery well located at 15-33-060-20W5 (33.3% WI), results of which were contained in the Company's press release dated September 13, 2010. Current drilling activity will further test this exciting shale play and will also increase land acreage by drilling farm-in wells on third party lands that are near expiry.

Celtic is currently drilling a vertical well located at 14-15-061-21W5 (51.3% WI) which will be cored and logged in the Duvernay formation. The Company expects to run seven inch intermediate casing and set it above the Duvernay in preparation to drill the well horizontally at a later date. Celtic will pay 51.3% of the well costs to earn 3.3 net sections of land with Duvernay rights.

Celtic is also participating in the drilling of another vertical well located at 14-16-062-21W5 (50% WI) whereby the Company will pay 50% of the well costs to earn 4.0 net sections of land with Duvernay rights. This well will be cored and logged, after which a vertical completion is planned.

On the joint venture block of lands where Celtic owns a 33.3% interest, the Company is currently participating in the drilling of a horizontal well located at 03-13-060-20W5 which is expected to be completed using multi-stage cluster fracs with cemented liner and with a plug and perforate completion technique. It is anticipated that this completion will take place towards the end of the first quarter of 2011.

During the first quarter of 2011, Celtic expects to drill a vertical test well in what it believes is the oil-leg of the Duvernay play on Company owned lands.

Celtic has evaluated core samples from its 100% WI Duvernay well located at 13-25-059-19W5 and is very encouraged by the results. The well showed matrix permeability as high as 0.018 millidarcies, which is as good as or better than the leading shale plays in the United States in the Eagle Ford and Marcellus shale formations. These rock characteristics, high liquid yields (75 barrels per MMCF of raw gas), along with an extremely over-pressured reservoir in excess of 62,000 kilopascals (9,000 PSI), should make this one of the premier shale plays in North America. The Company expects to have production from the Duvernay come on stream in the third quarter of 2011.

Kaybob - Montney and Bluesky

Celtic continues to be very active on its Montney and Bluesky development programs at Kaybob. As the Company has continued to bring more production on over the last year causing higher line pressures, older wells that have been producing since 2005 to 2008, are backed out of the system. This can be avoided by adding field compression in specific areas along the infrastructure. This had originally been planned for mid 2010, however, with Celtic's new plays in the Montney at Resthaven and in the Duvernay at Kaybob, the Company elected to postpone adding field compression and instead directed its capital towards land acquisition and drilling in these new plays. In addition, with better information on the Kaybob Duvernay play, the Company believes that any new infrastructure additions will also be used for future Duvernay production. As a result, compression will have to be designed to accommodate these volumes as well, and therefore adding additional compression will likely be delayed until the second half of 2011, when Duvernay results are better known.

At Fir, Celtic has discovered a new Montney pool with its discovery horizontal well located at 04-32-059-22W5 (100% WI). Production at Fir is expected to come on stream by the end of February after the Company completes the construction of a pipeline which will be connected to infrastructure leading to the Kaybob K3 Gas Plant in which the Company owns an interest. The Company has commenced drilling its second horizontal well at Fir located at 04-05-060-22W5 (100% WI).

Inga - Doig

In its third quarter report, Celtic announced that it had acquired approximately 20 BOE per day of liquids-rich natural gas production and a 40% non-operated working interest in 16 sections of land. The operator has drilled and tested the first horizontal well in the Doig formation with the following results.

The Company participated in the drilling of its first horizontal Doig well (40% working interest) in the Inga area of British Columbia to a total measured depth of approximately 2,900 metres (including approximately a 1,100-metre horizontal lateral). The well was completed with a seven-stage fracture stimulation program. After a five-day cleanup, the well flowed on an in-line test over a 64-hour-test period at an average restricted rate of approximately 4.7 million cubic feet per day and 1,100 barrels per day of condensate or 1,895 BOE per day at an average flowing tubing pressure of 1,156 per square inch (7,965 kilopascals). The operator is satisfied with the positive results from the initial seven stages of the planned 11-stage fracture stimulation program, although it may elect to stimulate additional stages in the future. At a liquids ratio of over 200 barrels of condensate per MMCF of natural gas and an assumed oil price of $83.00 per barrel at the wellhead and a natural gas price of $3.85 per GJ AECO, the operator anticipates operating netbacks from the well of up to $41.00 per BOE. The test results from this well are encouraging and supportive of additional horizontal drilling. There are currently five vertical Doig producers on Company owned lands. The operational success at Inga establishes a new core area for the Company that has scale and repeatability and where the operator has control of facilities.

Non-core Asset Dispositions

During December 2010 and to date in January 2011, Celtic completed the disposition of certain non-core assets with production of approximately 240 BOE per day, resulting in aggregate proceeds of $17.4 million, prior to adjustments.

The Company continues to have discussions with other parties and expects to monetize additional non-core assets in 2011.

Production and Financial Guidance

Using field estimates for the month of December, Celtic estimates production for 2010 averaged approximately 17,300 BOE/d (previous forecast was 17,700 BOE/d). The production mix is expected to be 23% oil and 77% gas. This represents a 22% increase from the average production of 14,192 BOE/d achieved in 2009. Funds from operations for 2010 is forecasted to be approximately $129.0 million or $1.41 per share, diluted (previous forecast was $131.0 million or $1.43 per share, diluted). Bank debt, net of working capital, is estimated to be $201.0 million at the end of 2010.

After taking into account non-core asset dispositions, delayed timing of adding field compression at Kaybob and timing of production on-stream dates from the newer plays at Resthaven and the Kaybob Duvernay, Celtic expects production in 2011 to average between 20,400 and 20,800 BOE per day (previous forecast was between 20,800 and 21,200 BOE per day). The production mix is expected to be 22% oil and 78% gas. At the low end of the range of this production forecast, this represents an 18% increase from the average estimated production of 17,300 BOE/d forecasted for 2010.

Celtic expects to achieve continued improvement in its cost structure in 2011. Production expense is estimated to be $7.95 per BOE, transportation expense is estimated to be $0.48 per BOE, royalties are expected to average 11.0% and general and administrative expense is estimated to be at industry low levels of $0.71 per BOE.

The Company's average commodity price assumptions for 2011 are US$85.00 (previously US$75.00) per barrel for WTI oil, US$4.75 (previously US$4.50) per MMBTU for NYMEX natural gas, $3.95 (previously $3.90) per GJ for AECO natural gas and a US/Canadian dollar exchange rate of US$1.000 (previously US$0.980). These prices compare to forecasted average 2010 prices of US$79.55 per barrel for WTI oil, US$4.42 per MMBTU for NYMEX natural gas, $3.78 per GJ for AECO natural gas and a US/Canadian dollar exchange rate of US$0.970.

After giving effect to the aforementioned production and commodity price assumptions, funds from operations for 2011 is forecasted to be approximately $159.0 million or $1.70 per share, diluted (previous forecast was $150.0 million or $1.63 per share, diluted) and net earnings are forecasted to be approximately $12.0 million or $0.13 per share, diluted (previous forecast was $11.0 million or $0.12 per share, diluted).

Changes in forecasted commodity prices and variances in production estimates can have a significant impact on estimated funds from operations and net earnings. Please refer to the advisory regarding forward-looking statements below.

Sensitivities to changes in commodity prices would affect forecasted 2011 funds from operations and net earnings as follows:



i. Change in AECO natural gas price of $1.00 per GJ would affect funds from
operations by $33.4 million ($0.36 per share) and earnings by $23.7
million ($0.25 per share);
ii. Change in WTI oil price of US$10.00 per barrel would affect funds from
operations by $4.5 million ($0.05 per share) and earnings by $3.2
million ($0.03 per share); and
iii.Change in US/Canadian dollar exchange rate of US$0.05 per CAD would
affect funds from operations by $9.3 million ($0.10 per share) and
earnings by $6.6 million ($0.07 per share).


Bank debt, net of working capital, is estimated to be $178.5 million by the end of 2011 or approximately 1.1 times forecasted 2011 funds from operations.

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 and funds from operations. Given the Company's strong inventory of drilling locations, we look forward to continued growth in 2011 and beyond.

The information set out herein under the heading "Production and Financial 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 2011. Readers are cautioned that this financial outlook may not be appropriate for other purposes.

Advisory Regarding Forward-Looking Statements

This document contains expectations, beliefs, plans, goals, objectives, assumptions, information and statements about future events, conditions, results of operations or performance that constitute "forward-looking information" or "forward-looking statements" (collectively, "forward-looking statements") under applicable securities laws. Undue reliance should not be placed on forward-looking statements. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements. We caution that the foregoing list of risks and uncertainties is not exhaustive. Events or circumstances could cause actual results to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements. The forward-looking statements contained in this document are made as of the date hereof and the Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise unless expressly required by applicable securities laws.

Other Measurements and Abbreviations

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, pentane, propane, butane and ethane. References to gas in this discussion include natural gas and sulphur.

Working interest is abbreviated as "WI". Million cubic feet is abbreviated as "MMCF". Pounds per square inch is abbreviated as "PSI".

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, 2010, there were 90.9 million common shares outstanding. There are no preferred shares outstanding.

As at December 31, 2010, directors, employees and certain consultants have been granted options to purchase 6.5 million common shares of the Company at an average exercise price of $8.31 per share.

The Company's common shares trade on the TSX under the symbol "CLT".

For further information please refer to the latest corporate presentation that is available on the Company's website at www.celticex.com.

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