Celtic Exploration L : Celtic More than Doubles Its Oil and Gas Reserves at December 31, 2011 and Reports Lower than Historical Average Finding Costs

PRESS RELEASE

(Stock Symbol "CLT" - TSX) February 13, 2012
Calgary, Alberta

CELTIC MORE THAN DOUBLES ITS OIL AND GAS RESERVES AT DECEMBER 31, 2011 AND REPORTS LOWER THAN HISTORICAL AVERAGE FINDING COSTS

Celtic Exploration Ltd. ("Celtic" or the "Company") has released its operating results for the twelve months ended
December 31, 2011. Summary of results are as follows:

	Twelve months ended December 31,
	2011	2010	Change
Reserves
Oil [MBBLs]	32,803	16,806	95%
Gas [MMCF]	636,992	304,197	109%
Combined [MBOE]	138,968	67,506	106%
Finding, development & acquisition ("FD&A") costs
Proved, including FDC ($/BOE)	16.82	22.46	-25%
Proved plus probable, including FDC ($/BOE)	12.80	17.71	-28%
Drilling activity
Total wells	58	62	-6%
Working interest wells	40.1	41.9	-4%
Success rate on working interest wells	96%	90%	7%
Undeveloped land
Gross acres	794,137	685,993	16%
Net acres	689,893	621,199	11%

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, 2011 were determined using the guidelines and definitions set out under National Instrument 51-
101 ("NI 51-101").
At December 31, 2011, Celtic's proved plus probable reserves were 139.0 million BOE, up 106% from 67.5 million BOE at the end of 2010. The Company's net present value of proved plus probable reserves at December 31, 2011, discounted at 10% before tax, was $1,377.2 million, up 48% from $930.7 million at December 31, 2010. Despite lower forecasted natural gas prices, the net present value was higher compared to the previous year primarily due to the significant growth in reserves.
The reserve life index for proved plus probable reserves was 13.0 years compared to 10.5 years at December
31, 2010. At December 31, 2011, the weighting of proved plus probable reserves was 24% oil and 76% gas on a volume basis and 44% oil and 56% gas on a revenue basis.
The following table outlines a summary of the Company's reserves at December 31, 2011:

SUMMARY OF RESERVES
	Oil [MBBLs]	Gas [MMCF]	Combined [MBOE]	% of 2P
Proved Developed Producing	7,701	162,282	34,748	25%
Proved Developed Non-producing	1,324	24,337	5,380	4%
Proved Undeveloped	9,384	175,791	38,683	28%
Total Proved ("1P")	18,408	362,410	78,810	57%
Probable Additional	14,395	274,582	60,159	43%
Total Proved plus Probable ("2P")	32,803	636,992	138,968	100%

Future development capital ("FDC") expenditures included in the reserve evaluation for total proved reserves are expected to be spent as follows: $246.2 million in 2012, $162.4 million in 2013 and $77.8 million thereafter. FDC included for proved plus probable reserves are expected to be spent as follows: $309.7 million in 2012,
$341.7 million in 2013 and $128.8 million thereafter.
The following table outlines FDC expenditures by major prospect included in the December 31, 2011 reserve evaluation:

FDC EXPENDITURES
	1P FDC ($M)	2P FDC ($M)	2P Gross Drills	2P Net Drills
Resthaven Montney	209,830	364,530	40	39.0
Fir Montney	112,909	125,309	20	19.3
Kaybob Duvernay	34,630	95,043	15	8.8
Other Properties *	129,059	195,281
Total FDC Expenditures	486,428	780,163

* Other properties include Kaybob Montney, Cretaceous, Beaverhill Lake; Deep Basin Cretaceous and Inga Doig.

The following table outlines forecasted future prices that Sproule has used in their evaluation of the Company's reserves at December 31, 2011:

FUTURE COMMODITY PRICE FORECAST
	WTI Cushing Crude Oil [US$/BBL]	USD/CAD Exchange [US$]	AECO-C Natural Gas [$/GJ]
2012	98.07	1.012	3.00
2013	94.90	1.012	3.58
2014	92.00	1.012	3.92
Three Year Average	94.99	1.012	3.49

After a precipitous decline in the average price of oil in 2009, compared to the previous year, the price of oil steadily increased in 2010 and 2011. In 2011, WTI oil prices averaged US$95.00 per bbl, up from US$79.43 per bbl in 2010. Average annual natural gas prices at AECO-C have declined every year since 2009. In 2010,
AECO-C averaged $3.94 per GJ and continued lower, averaging $3.53 per GJ in 2011.
Sproule is forecasting WTI oil prices to average US$94.99 per bbl over the next three years, 21% higher than the average price of US$78.69 per bbl over the past three years. For natural gas, AECO-C natural gas prices are forecasted to average $3.49 per GJ over the 2012 to 2014 period, a decrease of 9% from the average price of $3.82 per GJ during the 2009 to 2011 period.
The following table is a net present value summary (before tax) as at December 31, 2011:

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	839,648	628,213	514,172	441,383
Proved Developed Non-producing	154,517	101,440	77,118	63,016
Proved Undeveloped	803,089	415,317	235,796	134,223
Total Proved	1,797,254	1,144,970	827,086	638,622
Probable Additional	1,945,718	916,798	550,126	370,360
Total Proved plus Probable	3,742,972	2,061,768	1,377,212	1,008,982

The following table is a net present value summary (after tax) as at December 31, 2011:

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	814,236	619,644	510,839	439,950
Proved Developed Non-producing	115,868	81,237	65,383	55,780
Proved Undeveloped	601,803	302,684	162,170	81,825
Total Proved	1,531,907	1,003,565	738,392	577,555
Probable Additional	1,458,142	681,258	402,487	265,255
Total Proved plus Probable	2,990,049	1,684,823	1,140,879	842,810

The Company's net present value of proved plus probable reserves, discounted at 10% before tax was $1,377.2 million, up 48% from $930.7 million at December 31, 2010. As mentioned above, lower forecasted natural gas prices negatively affected the value of reserves as at December 31, 2011. However, given the successful drilling results in the Resthaven Montney, Fir Montney and Kaybob Duvernay resource plays, Celtic was able to offset the effect of lower natural gas prices by increasing its liquids-rich natural gas reserves significantly.
The following table provides detailed calculations relating to finding, development and acquisition ("FD&A")
costs and recycle ratios for 2011 and 2010:

	Year ended December 31, 2011	Year ended December 31, 2010	Cumulative since Incorporation
1P RESERVES
Capital expenditures [$000's] [unaudited]	419,680	172,785	1,529,100
Change in FDC costs required to develop reserves [$000's]	255,111	40,844	486,428
Total capital costs [$000's]	774,791	213,629	2,015,528
Reserve additions, net [MBOE]	46,077	9,512	108,742
FD&A cost, before FDC [$/BOE]	9.11	18.16	14.06
FD&A cost, including FDC [$/BOE]	16.82	22.46	18.53
Operating netback [$/BOE] [unaudited]	24.71	23.38	28.41
Recycle ratio - proved	1.5 x	1.0 x	1.5 x
2P RESERVES
Capital expenditures [$000's] [unaudited]	419,680	172,785	1,529,100
Change in FDC costs required to develop reserves [$000's]	570,444	64,702	780,163
Total capital costs [$000's]	990,124	237,487	2,309,263
Reserve additions, net [MBOE]	77,380	13,407	168,743
FD&A cost, before FDC [$/BOE]	5.42	12.89	9.06
FD&A cost, including FDC [$/BOE]	12.80	17.71	13.69
Operating netback [$/BOE] [unaudited]	24.71	23.38	28.41
Recycle ratio - proved plus probable	1.9 x	1.3 x	2.1 x

During 2011, the Company's capital expenditures (unaudited), net of dispositions, resulted in proved plus probable reserve additions of 77.4 million BOE (13.4 million BOE in 2010), resulting in FD&A costs of $12.80 per BOE ($17.71 per BOE in 2010), including FDC costs. Proved reserve additions in 2011 were 46.1 million BOE (9.5 million BOE in 2010), resulting in FD&A costs of $16.82 per BOE ($22.46 per BOE in 2010), including FDC costs.
Lower FD&A costs in 2011 compared to the previous year were a result of the Company's successful exploration drilling programs at Resthaven and Fir in the Montney formation and at Kaybob in the Duvernay shale formation. At Resthaven (Montney) and Kaybob (Duvernay), the Company is at an early stage in the delineation and de-risking of two potentially large multi-year development resource plays.
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 2.1 times on a proved plus probable basis. In 2011, the recycle ratio was 1.9 times.
Celtic's 2011 capital investment program resulted in net reserve additions that replaced 2011 production by a factor of 7.8 (1.5 in 2010) times on a proved basis and 13.1 (2.1 in 2010) times on a proved plus probable basis.

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 dates 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.

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.
Net present value is abbreviated as "NPV". Working interest is abbreviated as "WI". Million cubic feet is abbreviated as "MMCF". Thousand cubic feet is abbreviated as "MCF". Barrels are abbreviated as "BBLS". Giga joules are abbreviated as "GJ".
For further information, please contact:

CELTIC EXPLORATION LTD., Suite 600, 321 - 6th Avenue SW, Calgary, Alberta, Canada T2P 3H3 David J. Wilson, President and Chief Executive Officer [phone], or

Sadiq H. Lalani, Vice President, Finance and Chief Financial Officer [phone]. Or visit our website site at www.celticex.com.