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Press release from Marketwire

Celtic Reports Financial Results for the Year Ended December 31, 2010

Monday, March 07, 2011

Celtic Reports Financial Results for the Year Ended December 31, 201009:00 EST Monday, March 07, 2011CALGARY, ALBERTA--(Marketwire - March 7, 2011) - Celtic Exploration Ltd. ("Celtic" or the "Company") (TSX:CLT) has released its financial results for the three months and twelve months ended December 31, 2010. Summary of results are as follows:Three months ended December 31,Twelve months ended December 31,($000's, unless otherwise specified)20102009Change20102009ChangeRevenue, before royalties and financial instruments53,04260,146-12%222,041172,61329%Funds from operations30,62542,003-27%130,793118,02511%Basic ($/share)0.340.47-28%1.461.367%Diluted ($/share)0.330.46-28%1.431.356%Net earnings (loss)(3,050)907-6,583(23,258)-Basic ($/share)(0.03)0.01-0.07(0.27)-Diluted ($/share)(0.03)0.01-0.07(0.27)-Capital expenditures, net of dispositions and drilling credits68,18641,51964%172,785148,76116%Total assets723,025678,7707%Bank debt, net of working capital202,683168,41720%Bank debt, net of working capital, excluding non-cash financial instruments200,748168,20919%Shareholder's equity408,095387,1905%Common shares outstanding (thousands)90,87689,1252%Stock options outstanding (thousands)6,5496,616-1%Weighted average common sharesBasic (thousands)90,39889,0801%89,87686,8284%Diluted (thousands)93,11890,6643%91,53787,5005%Celtic's operating results for the three months and twelve months ended December 31, 2010 are summarized in the table below:Three months ended December 31,Twelve months ended December 31,20102009Change20102009ChangeProductionOil [BBLS/d]4,0964,384-7%4,0703,68710%Gas [MCF/D]79,73177,3393%79,40463,02826%Combined [BOE/D]17,38517,2741%17,30414,19222%Production per million shares [BOE/D]192194-1%19316318%Drilling activityTotal wells1517-12%625513%Working interest wells8.29.6-15%41.943.0-3%Success rate on working interest wells88%100%-12%90%91%-1%Undeveloped landGross acres685,993363,47389%Net acres621,199294,700111%ReservesOil & NGLs [MBBLs]16,80615,04212%Natural gas [MMCF]304,197272,23612%Combined [MBOE]67,50660,41512%Celtic is pleased to report to shareholders on the Company's activities. The Company reported growth in production, reserves and funds from operations for the year and at the same time successfully assembled significant land positions in resource plays in the Triassic Montney at Resthaven, Alberta and in the Devonian Duvernay at Kaybob, Alberta.Highlights for 2010 include year-over-year increases in funds from operations of $130.8 million ($1.43 per share, diluted), net capital expenditures of $172.8 million, increased production of 17,304 BOE per day, increased reserves of 67.5 million BOE, more than doubled undeveloped land holdings of 621,199 net acres and a prudent financial position with debt, net of working capital of $202.7 million or 1.5 times 2010 funds from operations. These results were achieved despite the disposition of non-core assets during the year whereby the Company sold 2.3 million BOE of proved plus probable reserves representing approximately 650 BOE per day of production for net proceeds of $64.6 million.The year 2010 proved to be a very important year for Celtic as the company set out to establish an opportunity base that will allow it to grow over the next decade. Although the Company was able to tie-up several play types throughout the deep basin of Alberta and British Columbia, two of these growth opportunities can be classified as resource plays that will be the engine for the Company's future growth.Kaybob Devonian Duvernay Resource PlayThe Duvernay play in the Kaybob area gained notoriety after an Alberta Crown sale in December 2009, followed by a subsequent Crown sale in July 2010. At these two land sales, $670 million was spent to acquire 388,480 acres at an average price of $1,725 per acre or $1.1 million per section. Sixteen sections adjacent to Celtic lands sold for $2.6 million per section. At December 31, 2010, Celtic owned approximately 88,000 net acres or 138 net sections with Duvernay rights in this area. After drilling and testing the first Duvernay horizontal well in the area during 2010, the Company has continued to accumulate lands in 2011 through farm-in agreements on expiring acreage.During 2010, Celtic drilled a 33.3% working interest well on an expiring block that was pooled with two other industry partners. Given that this was the first horizontal well into the play, the Company believed it would be financially prudent to jointly test the play. After evaluating the results from this well, the Company drilled a 100% working interest well which was logged and cored through the Duvernay zone with intermediate casing being set above the Duvernay formation, allowing for a horizontal to be drilled in 2011. Celtic has had an opportunity to evaluate the core results from this well and is very encouraged by the permeability and porosity results.Celtic continues to actively de-risk the play and during the first quarter of 2011 will do so by drilling vertical wells where the Company cores and logs and either vertically completes the well or sets intermediate casing with the intention to drill the well horizontally, after the preferred method of completion has been chosen. It is anticipated that the Company will participate in four drilling operations during the first quarter. One horizontal well which will be completed using the perforate and plug method; two vertical wells which will allow the Company to earn additional acreage; and a fourth vertical well at 100% working interest which will test the oilier part of the play, while at the same time earning additional acreage. After evaluating the results from these wells, Celtic will be in a position to establish a go forward capital expenditure and development plan on this exciting liquids-rich shale play.Resthaven Triassic Montney Resource PlayThe second play, which Celtic has been working on for several years but only recently disclosed to the public, is the Resthaven Montney play. The Company first tested a well in this area in 2007, but did not aggressively start pursuing it until 2008, after experiencing positive results from horizontally drilling the same horizon (Montney) on its Kaybob property. With the Company's knowledge in the Kaybob area, it started to acquire a significant acreage position in the Resthaven area prior to drilling a horizontal test in the Montney zone in early 2010. After a favorable flow test, the Company continued to aggressively acquire acreage on the play. The Company currently has 383,692 net acres (600 sections) tied up on the play. An aggressive drilling program is being carried out in 2011, allowing the Company to evaluate this large liquids rich resource play.Celtic plans to prove up its Resthaven acreage through three approaches. One method will be to drill a vertical strat test, followed by a horizontal well if the results from the strat test are favourable. In some cases, a horizontal well can be drilled adjacent to an existing vertical wellbore, eliminating the need for the initial strat test. Another method is to re-enter existing vertical wellbores that were drilled into a Cretaceous zone and drill down into the Montney formation. In most cases, these are slim hole operations whereby a valid open hole log can be obtained and the liner can be cemented in place allowing a vertical completion test. The third method that is being used is to re-enter an existing vertical wellbore that was drilled through the Montney formation, exploring for deeper horizons. Most of these type of wells will have intermediate casing into the Montney formation, providing Celtic with the opportunity to complete and test the previously cased Montney zone.As Celtic continues to de-risk the Resthaven play, construction of pipeline infrastructure is currently underway, with plans to commence production by mid-year. At present, Celtic plans to produce into existing gas plants in the area until the scope of the development program is fully understood. In the future, the Company could construct its own gas processing facility.With on-going success, the Resthaven area could provide the Company with drilling inventory that would provide production growth over the next decade at favourable rates of return using current commodity prices. Other ProspectsThe Company is also excited about two other plays that are smaller in size in terms of land holdings, however, may also provide significant near term growth and appear to have high liquids potential.At Inga, British Columbia, Celtic bought a 40% working interest in a 16 section block of land, along with pipeline infrastructure and a 10.0 million cubic feet (gross) per day gas plant. The acreage had been delineated with five vertical wells. After acquiring the property, Celtic participated in the first horizontal well which tested at a rate of 4.7 million cubic feet per day and 1,100 barrels per day of condensate. A follow-up horizontal well will be drilled in the first quarter of 2011 and an additional horizontal well will be drilled on an adjacent three section farm-in block during the summer.At Fir, Alberta, the Company owns a 100% working interest in 26 sections (16,800 acres) of land with Triassic Montney rights. Celtic discovered a Montney pool at Fir in 2010. This pool which is about 15 miles south west of the Kaybob South Montney pool has similar reservoir characteristics but has higher bottom-hole pressure and a higher liquids yield. Celtic plans to drill three to four wells in this pool in 2011 and plans to tie-in production from the pool prior to break-up.At Kaybob, Alberta, Celtic continues to be very active on its Montney and Bluesky development programs. 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-year 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.Looking ahead to 2011, Celtic will use its knowledge and experience with horizontal multi-stage fracture drilling and completion technologies to move its new prospects forward. ProductionOil and gas production in 2010 increased 22% to average 17,304 BOE per day compared to 14,192 BOE per day in 2009. Average production in the fourth quarter of 2010 was 17,385 BOE per day, up 1% from 17,274 BOE per day in the fourth quarter of 2009. Production per million shares outstanding in 2010 averaged 193 BOE per day, up 18% from 163 BOE per day in 2009.Oil OperationsOil production for the year ended December 31, 2010 averaged 4,070 bbls per day, an increase of 10% compared to the previous year. For the three months ended December 31, 2010, average oil production was 4,096 bbls per day, down 7% from the fourth quarter of 2009. Increased oil production in 2010 reflects the addition of NGLs from the increased liquids-rich natural gas production at Kaybob, Alberta, which more than offset oil asset dispositions during the year.The average price received for oil sales, after realized financial instruments, for the year ended December 31, 2010 was $67.80 ($67.38 before financial instruments) per barrel, down 16% (up 19% before financial instruments) from the average price of $81.00 ($56.45 before financial instruments) per barrel received in 2009. The Company recorded a realized gain of $0.6 million on financial instruments relating to oil price transactions in 2010 compared to a realized gain of $33.0 million in the previous year. The average price received for oil sales, after realized financial instruments, for the fourth quarter ended December 31, 2010 was $68.56 ($66.92 before financial instruments) per barrel, down 15% (up 4% before financial instruments) from the average price of $80.22 ($64.46 before financial instruments) per barrel received in the fourth quarter of 2009. For the twelve months ended December 31, 2010, average oil royalties were 18.0% of revenue, after financial instruments (18.1% of revenue, before financial instruments). In the previous year, average oil royalties were 13.3% of revenue, after financial instruments (19.0% of revenue, before financial instruments). Lower royalty rates, before financial instruments, in 2010 were a result of lower rates on NGLs as the Company took advantage of Alberta's incentives on new liquids-rich gas horizontal wells drilled and brought on-stream during the year. For the quarter ended December 31, 2010, average oil royalties were 19.1% of revenue, after financial instruments (19.5% of revenue, before financial instruments). In the fourth quarter of the previous year, average oil royalties were 11.1% of revenue, after financial instruments (13.9% of revenue, before financial instruments). Fourth quarter royalty rates, before financial instruments, were lower in 2009 due to gas cost allowance credit adjustments recognized in the quarter. Transportation expenses for oil production in 2010 averaged $0.18 per barrel compared to $0.27 per barrel in 2009. Lower per unit transportation expenses in 2010 reflect the larger portion of newer NGL production which is mostly pipeline connected and therefore less expensive to transport compared to trucking crude oil. Transportation expenses for oil production in the fourth quarter of 2010 averaged $0.09 per barrel compared to $0.25 per barrel in the fourth quarter of 2009.For the year ended December 31, 2010, production expenses were $9.94 per barrel, a 24% reduction from the previous year's $13.11 per barrel. During the fourth quarter of 2010, production expenses averaged $7.61 per barrel compared to $12.37 per barrel in the fourth quarter of 2009. Lower per barrel production expenses in 2010 compared to the previous year are a result of the larger component of newly added NGLs included in oil production which are less costly to produce than Celtic's 2009 oil production mix. In addition, oil dispositions in 2010 were in areas that had higher per unit expenses than the rest of Celtic's oil production base.Gas OperationsGas production for the year ended December 31, 2010 averaged 79,404 mcf per day, an increase of 26% compared to 63,028 mcf per day in the previous year. Increases in gas production in 2010 were primarily a result of Celtic's successful drilling results in its resource development prospect located at Kaybob, Alberta. Gas production for the fourth quarter ended December 31, 2010 averaged 79,731 mcf per day, an increase of 3% compared to the corresponding period of the previous year. The average price received for gas sales, after realized financial instruments, for the year ended December 31, 2010 was $4.37 ($4.21 before financial instruments) per mcf, relatively unchanged from the average price of $4.36 ($4.20 before financial instruments) per mcf received in 2009. The Company recorded a realized gain of $4.7 million on financial instruments relating to gas price transactions in 2010 compared to a realized gain of $3.7 million in the previous year. The average price received for gas sales, after realized financial instruments, for the fourth quarter ended December 31, 2010 was $3.93 ($3.79 before financial instruments) per mcf, down 19% (down 21% before financial instruments) from the average price of $4.86 ($4.79 before financial instruments) per mcf received in the fourth quarter of 2009. For the year ended December 31, 2010, average gas royalties were 5.9% of revenue, after financial instruments (6.2% of sales, before financial instruments). In the previous year, average natural gas royalties were 8.5% of revenue, after financial instruments (8.8% of sales, before financial instruments). Actual Crown natural gas royalties payable are determined based on an Alberta reference price and not on actual corporate realized prices. For the quarter ended December 31, 2010, average natural gas royalties were 1.8% of revenue, after financial instruments (2.0% of sales, before financial instruments). In the fourth quarter of the previous year, average natural gas royalties were 4.3% of revenue, after financial instruments (4.4% of sales, before financial instruments). Lower royalties in 2010 compared to the previous year reflect Alberta's royalty incentives of which the majority of Celtic's wells drilled in 2010 qualified for. In addition, royalties are reduced further as the Company continues to receive gas cost allowance credits which do not fluctuate with gas prices.Transportation expenses for the year ended December 31, 2010 were $0.09 per mcf, a decrease of 40% compared to $0.15 per mcf for the previous year. Transportation expenses for the fourth quarter ended December 31, 2010 were $0.07 per mcf, a decrease of 56% compared to $0.16 per mcf for the same period in the previous year. Lower transportation expenses in 2010 reflect the increase in gas production that is transported on Company owned pipeline infrastructure.For the twelve months ended December 31, 2010, production expenses of $1.26 per mcf were 18% lower than $1.54 per mcf in the previous year. Higher production expenses in 2009 reflect the additional expenses incurred at Kaybob where a significant amount of the Company's production is processed through the KA Gas Plant. This plant was down for approximately five weeks in the second quarter of 2009 for turnaround operations that occur every four years. For the fourth quarter ended December 31, 2010, production expenses were $1.02 per mcf compared to $1.48 per mcf in the fourth quarter of 2009. Lower production expenses in the fourth quarter of 2010 compared to the same period in the previous year reflect operating and facility the improvements at the KA Gas Plant where a significant portion of the Company's gas production is processed. Funds from Operations and Cash Provided by Operating ActivitiesFunds from operations is a non-GAAP measure defined as cash provided by operating activities before changes in non-cash operating working capital and settlement of asset retirement obligations. Despite being a non-GAAP measure, funds from operations is commonly used in the oil and gas industry and by Celtic to assist in measuring the Company's ability to finance capital programs and meet financial obligations.Funds from operations for the year ended December 31, 2010 was $130.8 million ($1.46 per share, basic and $1.43 per share, diluted). In 2009, funds from operations were $118.0 million ($1.36 per share, basic and $1.35 per share, diluted). Funds from operations for the three months ended December 31, 2010 was $30.6 million ($0.34 per share, basic and $0.33 per share, diluted). In the fourth quarter of 2009, funds from operations were $42.0 million ($0.47 per share, basic and $0.46 per share, diluted).On a barrel of oil equivalent basis, funds from operations in 2010 were $20.73 per BOE, down 9% from $22.78 per BOE in 2009. Despite improvements in per unit expenses, funds from operations per BOE were lower in 2010 due to the significant gain on financial instruments recorded in 2009. On a barrel of oil equivalent basis, funds from operations in the fourth quarter of 2010 were $19.15 per BOE, down 28% from $26.44 per BOE in the fourth quarter of 2009. The decrease in the fourth quarter of 2010 compared to the same period in 2009 was attributable to lower commodity prices, lower gains on financial instruments and a loss on disputed processing fees that was recorded in the fourth quarter of 2010. The following table provides a reconciliation of funds from operations for the past two years:FUNDS FROM OPERATIONS($ thousands)Year ended December 31, 2010Year ended December 31, 2009Percent ChangeCash provided by operating activities154,993103,72149%Settlement of asset retirement obligations1,8971,04382%Change in non-cash operating working capital(26,097)13,261-Funds from operations130,793118,02511%Cash provided by operating activities for the year ended December 31, 2010 was $155.0 million, up 49% from $103.7 million in 2009. Cash provided by operating activities for the three months ended December 31, 2010 was $38.2 million, up 9% from $33.9 million in the fourth quarter of 2009.Net EarningsNet earnings for the year ended December 31, 2010 was $6.6 million ($0.07 per share, basic and diluted). Net loss for the year ended December 31, 2009 was $23.3 million ($0.27 per share, basic and diluted). Net loss for the three months ended December 31, 2010 was $3.0 million ($0.03 per share, basic and diluted). Net earnings for the fourth quarter of 2009 was $0.9 million ($0.01 per share, basic and diluted).Capital ExpendituresCeltic is committed to future growth through its strategy to implement a full cycle exploration and development program, augmented by strategic acquisitions with exploitation upside.During the year ended December 31, 2010, Celtic incurred $229.7 million on exploration and development activity, $7.7 million on property acquisitions and recorded net proceeds of $64.6 million from property dispositions. Drilling and completion operations accounted for $155.7 million and the Company earned $1.3 million in drilling royalty credits that are eligible to be claimed against corporate crown royalties payable. Equipment and facility expenditures were $37.9 million. The balance of $37.4 million was spent on land and seismic, thereby building the Company's inventory of prospects for future drilling opportunities. Approximately 86% of net wells drilled were categorized as development and 14% were exploratory.During the year ended December 31, 2009, Celtic incurred $147.0 million on exploration and development activity, $2.2 million on property acquisitions and recorded net proceeds of $0.4 million from property dispositions. Drilling and completion operations accounted for $125.3 million and the Company earned $20.6 million in drilling royalty credits that are eligible to be claimed against corporate crown royalties payable. Equipment and facility expenditures were $32.1 million. The balance of $10.2 million was spent on land and seismic, building the Company's inventory of prospects for future drilling opportunities. Approximately 96% of net wells drilled were categorized as development and 4% were exploratory.Share InformationThe Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares. The Company's shareholders approved a two-for-one stock split effective May 6, 2010. All references to common shares and stock options in this document are on a post stock split basis. As at December 31, 2010, there were 90.9 million common shares outstanding (as at March 6, 2010, there were 91.5 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. 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 ("TSX") under the symbol "CLT". During 2010, 85.5 million shares traded on the TSX at a weighted average price of $12.25 per share. These volumes were 6% higher than the 80.7 million shares traded in 2009 at a weighted average price of $7.96 per share.Advisory Regarding Forward-Looking StatementsCertain 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.2011 GuidanceCeltic continues to remain optimistic about its future prospects. Celtic is opportunity driven and is confident that it can continue to grow the Company's production base by building on its current inventory of development prospects and by adding new exploration prospects. Celtic will endeavour to maintain a high quality product stream that on an 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 hydrocarbon potential.Celtic's Board of Directors has approved a capital expenditure budget in the amount of $180.0 million for 2011. Capital spending for 2011 is expected to be financed by funds from operations, with access to available bank credit lines and common share issuances, if necessary.Celtic expects production in 2011 to average between 20,400 and 20,800 BOE per day. 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 growth in 2011 to be weighted towards the second half of the year, as production during the first half of 2011 is expected to remain relatively flat. Production in the fourth quarter of 2010 was 17,385 BOE per day. Production during the first quarter of 2011 will be negatively affected by 300 to 500 BOE per day as a result of plant outages to date at the KA and K3 gas plants at Kaybob.The production mix for 2011 is expected to be 22% oil and 78% gas. At the low end of the range of 2011's production forecast, this represents an 18% increase from the average production of 17,304 BOE/d 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 per barrel for WTI oil, US$4.75 per MMBTU for NYMEX natural gas, $3.95 per GJ for AECO natural gas and a US/Canadian dollar exchange rate of US$1.000. These prices compare to average 2010 prices of US$79.43 per barrel for WTI oil, US$4.39 per MMBTU for NYMEX natural gas, $3.94 per GJ for AECO natural gas and a US/Canadian dollar exchange rate of US$0.971.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 and net earnings are forecasted to be approximately $12.0 million or $0.13 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 above.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 "2011 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.Non-GAAP Financial MeasurementsThis document contains the terms "funds from operations", "operating netback" and "production per share" which do not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures by other companies. Funds from operations and operating netbacks are used by Celtic as key measures of performance. Funds from operations and operating netbacks are not intended to represent operating profits nor should they be viewed as an alternative to cash provided by operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Operating netbacks are determined by deducting royalties, production expenses and transportation expenses from oil and gas revenue. Funds from operations are determined by adding back settlement of asset retirement obligations and change in non-cash operating working capital to cash provided by operating activities. 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 MeasurementsAll 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.Critical Accounting EstimatesManagement 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 annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The impairment loss is limited to the amount by which the carrying amount exceeds: (i) the sum of the fair value of proved plus probable reserves; and (ii) the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves. The cost recovery ceiling test is based on estimates of proved reserves, production rates, future 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 using a credit adjusted risk free rate. 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 the Black-Scholes model and incorporating 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. Financial StatementsCeltic's audited financial statements and related notes for the year ended December 31, 2010 will be available to the public on SEDAR at www.sedar.com and will also be posted on the Company's website at www.celticex.com on March 7, 2011.FOR FURTHER INFORMATION PLEASE CONTACT: David J. WilsonCeltic Exploration Ltd.President and Chief Executive Officer(403) 201-5340ORSadiq H. LalaniCeltic Exploration Ltd.Vice President, Finance and Chief Financial Officer(403) 215-5310ORSuite 500, 505 - 3rd Street SWCeltic Exploration Ltd.Calgary, Alberta, Canada T2P 3E6www.celticex.com