Celtic Exploration Ltd.
TSX : CLT

Celtic Exploration Ltd.

November 10, 2010 08:00 ET

Celtic Reports Financial and Operating Results for the Third Quarter of 2010

CALGARY, ALBERTA--(Marketwire - Nov. 10, 2010) - Celtic Exploration Ltd. (TSX:CLT) ("Celtic" or the "Company") has released its financial and operating results for the three and nine months ended September 30, 2010.

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 press release 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.

Non-GAAP Financial Measurements

This 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 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.

Highlights - Third Quarter 2010

- Drilled 18 (12.7 net working interest) wells during the quarter resulting in an overall success rate of 100%;

- Increased average daily production by 8% to 16,506 BOE per day, up from 15,307 BOE per day in the third quarter of 2009;

- Received an average price of $33.73 ($31.60 before hedging) per BOE, down 4% from $35.11 ($28.67 before hedging) per BOE in the third quarter of 2009 and recorded an operating netback of $22.08 per BOE, up 1% from $21.94 per BOE in the corresponding quarter of 2009; and

- Generated $31.0 million in funds from operations for the three month period ended September 30, 2010, up 11% from $27.9 million in the same quarter of the previous year. Reported funds from operations per share, diluted, of $0.34, an increase of 10% from $0.31 per share in the third quarter of the previous year.

SUMMARY OF RESULTS



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Three months ended Nine months ended
September 30, September 30,
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($ thousands, unless
otherwise indicated) 2010 2009 Change 2010 2009 Change
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FINANCIAL
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Revenue, before
royalties and
financial instruments 47,989 40,365 19% 169,000 112,467 50%
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Funds from operations 30,963 27,874 11% 100,168 76,022 32%
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Basic ($/share) 0.34 0.32 8% 1.12 0.89 27%
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Diluted ($/share) 0.34 0.31 10% 1.10 0.88 25%
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Net earnings (loss) (799) (13,667) - 9,633 (24,165) -
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Basic ($/share) (0.01) (0.16) - 0.11 (0.28) -
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Diluted ($/share) (0.01) (0.16) - 0.11 (0.28) -
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Capital expenditures,
net of dispositions
and drilling credits 72,456 29,041 149% 104,600 107,242 -2%
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Total assets 687,866 657,919 5%
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Bank debt, net of
working capital 168,218 159,319 6%
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Bank debt, net of
working capital,
excluding non-cash
financial instruments 168,734 167,279 1%
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Shareholders' equity 405,729 384,690 5%
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Weighted average
common shares
outstanding
(thousands)
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Basic 90,089 88,556 2% 89,701 86,069 4%
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Diluted 92,110 89,308 3% 91,139 86,520 5%
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OPERATIONS
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Production
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Oil (bbls/d) 3,747 3,813 -2% 4,061 3,452 18%
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Gas (mcf/d) 76,555 68,964 11% 79,294 58,205 36%
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Combined (BOE/d) 16,506 15,307 8% 17,277 13,153 31%
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Production per million
shares (BOE/d) 183 173 6% 193 153 26%
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Realized sales prices,
after financial
instruments
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Oil ($/bbl) 62.29 79.71 -22% 67.53 81.35 -17%
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Gas ($/mcf) 4.22 3.39 24% 4.52 4.13 9%
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Operating netbacks
($/BOE)
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Oil and gas revenue 31.60 28.67 10% 35.83 31.33 14%
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Realized gain on
financial
instruments 2.13 6.44 0.78 8.32
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Realized sales
price, after
financial
instruments 33.73 35.11 -4% 36.61 39.65 -8%
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Royalties (3.14) (2.60) 21% (4.27) (4.97) -14%
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Production expense (8.11) (9.54) -15% (8.70) (10.48) -17%
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Transportation
expense (0.40) (1.03) -61% (0.47) (0.72) -35%
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Operating netback 22.08 21.94 1% 23.17 23.48 -1%
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Drilling activity
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Total wells 18 14 29% 47 38 24%
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Working interest
wells 12.7 11.8 8% 33.7 33.4 1%
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Success rate on
working interest
wells 100% 93% 8% 94% 89% 6%
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Undeveloped land
(acres)
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Gross 494,587 343,890 44%
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Net 432,777 273,713 58%
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MESSAGE TO SHAREHOLDERS

Celtic Exploration Ltd. ("Celtic" or the "Company") is pleased to report to shareholders the Company's activities in the third quarter of 2010. During the quarter, Celtic drilled 18 (12.7 net) wells with an overall success rate of 100%. Production during the quarter averaged 16,506 BOE per day, an increase of 8% from 15,307 BOE per day in the third quarter of 2009. During the quarter, the Company experienced delays in pipeline construction and new well tie-ins due to wet weather conditions. With the majority of new development wells drilled in the second and third quarters now on-stream, current production is approximately 19,000 BOE per day, based on field estimates. In addition, the Company has additional production behind pipe from wells drilled in several new exploration prospects. These exploration wells are expected to be tied-in in 2011.

In the third quarter of 2010, Celtic recorded funds from operations of $31.0 million ($0.34 per share, diluted), up from $27.9 million ($0.31 per share, diluted) reported in the same quarter of the previous year. Net capital expenditures during the quarter were $72.5 million, up 149% from $29.0 million in the third quarter of 2009. Bank debt, net of working capital, at September 30, 2010 was $168.2 million, up 6% from $159.3 million at September 30, 2009.

Operations Update

During the third quarter of 2010, the Company drilled 12 (7.1 net) wells in the Greater Kaybob area of Alberta, targeting the Triassic Montney, Devonian Beaverhill Lake and Devonian Duvernay formations, with a 100% success rate. Natural gas production at Kaybob is liquids-rich with NGLs ranging from 26 to 80 barrels per MMCF of raw gas. In the Kaybob area, Celtic drilled 5 gross (4.7 net) development wells in the Triassic Montney formation. Three of these wells have now been completed and were put on production in early October. The remaining two wells are expected to be completed and put on production in November. At the Kaybob South BHL Unit #2, where Celtic has a 77.9% unit interest, a Devonian Beaverhill Lake in-fill vertical well was drilled and completed. This well was put on production in late October and is currently producing at a gross rate of 4.0 MMCF per day and associated liquids of approximately 80 barrels per MMCF of raw gas.

Also in the Greater Kaybob area, where Celtic owns 130 net sections of Devonian Duvernay rights, the Company drilled, completed and tested its first exploration horizontal well in the Duvernay shale formation. During the completion, the Company was only able to fracture six of the planned 13-stages prior to a rupture in the casing that occurred at the heel portion of the horizontal leg, preventing the fracture of the remaining stages. After the initial clean-up and a follow-up three day test, the well was producing natural gas at a rate of 2.1 MMCF per day and is expected to yield liquids of approximately 75 barrels per MMCF of raw gas, including 56 degrees API condensate. The confirmation of commerciality from this first horizontal well is significant to Celtic as it establishes a potentially large resource located in the gas-condensate fairway of the Duvernay Shale. During the third quarter, Celtic drilled a second well (100% WI) and the Duvernay was cored, logged and cased. Intermediate casing was set above the zone in preparation to drill a horizontal well at a later date. The Company is currently evaluating core data from this well. Celtic and its partners expect to spud a third well (33% WI) in the fourth quarter that will be drilled horizontally and is currently planned to be completed using multi-stage cluster fracs with cemented liner and with a plug and perforate completion methodology.

Wet weather conditions in Alberta during the summer affected the Company's operations. Although drilling rigs were able to be moved during the wet summer, delays in completion operations were experienced as equipment was held up on other operator's leases. As a result, many of Celtic's completion and pipeline tie-ins were postponed leading to production delays.

Towards the end of the third quarter, Celtic moved three rigs from Kaybob to the Company's new exploration areas. Celtic has increased its capital expenditure budget for 2010 by $35.0 million, primarily for land acquisitions and additional drilling on its new exploration prospects. At September 30, 2010, Celtic's net undeveloped land holdings were 432,777 acres, a 58% increase from 273,713 acres at September 30, 2009. This significant increase occurred despite the disposition of approximately 41,000 net undeveloped acres at Swan Hills in March 2010.

In the Company's new exploration areas, three horizontal wells (100% WI) were drilled during the third quarter testing three different exploration prospects. At Fir, where Celtic owns a 100% interest in 23.5 sections of land with Montney rights, the Company's first horizontal well in the prospect tested at a final rate of 3.5 MMCF per day of natural gas and 250 barrels per day of light oil, although all of the frac oil had not been fully recovered at that point. Celtic is unable to provide detailed drilling test results for certain other exploration prospects as the Company is actively pursuing land acquisitions that are in a competitive environment. The Company does expect to provide more details in terms of land locations and further drilling results from its exploration program prior to year-end.

Acquisitions and Dispositions

During the third quarter, the Company completed the disposition of an oil property in northern Alberta with production of approximately 20 BOE per day for proceeds of $3.2 million, prior to adjustments.

Also in the third quarter, the Company completed a tuck-in acquisition at Kaybob South. For consideration of $7.5 million, prior to adjustments, Celtic acquired approximately 250 BOE per day of liquids-rich natural gas production plus minor facility interests in the KA Gas Plant and the Kaybob South Sulphur and Loading Facility.

In September, the Company completed an acquisition at Inga in northeastern British Columbia. For consideration of $1.2 million, prior to adjustments, Celtic 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 first horizontal well into this play was spud on October 28th, 2010 and is targeting a high liquids Triassic Doig reservoir.

The Company expects to continue to monetize non-core assets and is actively pursuing bids on potential asset divestments representing approximately 1,500 BOE per day of production.

Outlook

In spite of low natural gas prices, Celtic is able to generate profitable returns on its investments due to the nature of its asset base that is primarily made up of predictable and repeatable resource type development in liquids-rich natural gas formations. Celtic expects to exit 2010 with production of approximately 20,000 BOE per day. The Company is excited about its active exploration program and looks forward to updating shareholders with further results in the near future. Celtic expects to provide financial and production guidance for 2011 by late November 2010.

Production

Oil and gas production in the third quarter of 2010 increased 8% to average 16,506 BOE per day compared to 15,307 BOE per day in the same quarter of 2009. Production per million shares outstanding for the three months ended September 30, 2010 averaged 183 BOE per day, up 6% from 173 BOE per day in the corresponding quarter of the previous year.

Oil and gas production for the nine months ended September 30, 2010 increased 31% to average 17,277 BOE per day compared to 13,153 BOE per day in the same nine month period of 2009. Production per million shares outstanding for the nine months ended September 30, 2010 averaged 193 BOE per day, up 26% from 153 BOE per day in the corresponding nine months of the previous year.

Revenue

Revenue, before royalties, and before realized and unrealized gains or losses on financial instruments, for the three months ended September 30, 2010, was $48.0 million, an increase of 19% compared to $40.4 million in the same quarter of the previous year. Revenue, before royalties, and before realized and unrealized gains or losses on financial instruments, for the nine months ended September 30, 2010, was $169.0 million, an increase of 50% compared to $112.5 million in the same period of the previous year.

Increase in revenue for 2010 was due to significantly higher production volumes that more than offset lower realized oil prices.

The combined average product price received for oil and gas sales, adjusted for realized gains or losses on financial instruments for the three months ended September 30, 2010 was $33.73 per BOE, a decrease of 4% compared to the corresponding three month period of the previous year. The combined average product price received for oil and gas sales, adjusted for realized gains or losses on financial instruments for the nine months ended September 30, 2010 was $36.61 per BOE, a decrease of 8% compared to $39.65 per BOE in the corresponding nine month period of the previous year.

Oil Operations

Oil production for the third quarter ended September 30, 2010 averaged 3,747 barrels per day, a decrease of 2% compared to 3,813 barrels per day in the same quarter of the previous year. Oil production for the nine months ended September 30, 2010 averaged 4,061 barrels per day, an increase of 18% compared to 3,452 barrels per day in the same period of the previous year.

The average price received for oil sales, after realized financial instruments, for the third quarter ended September 30, 2010 was $62.29 ($62.29 before financial instruments) per barrel, down 22% from the average price of $79.71 ($58.70 before financial instruments) per barrel received in the third quarter of 2009. The average price received for oil sales, after realized financial instruments, for the nine months ended September 30, 2010 was $67.53 ($67.53 before financial instruments) per barrel, down 17% from the average price of $81.35 ($53.03 before financial instruments) per barrel received in the first nine months of 2009.

During the nine month period ended September 30, 2010, the average differential between WTI and the Company's realized wellhead oil price, before financial instruments, narrowed to 16.1% compared to 20.5% in the same period of 2009, as Celtic received a premium for its condensate and butane production.

For the quarter ended September 30, 2010, average oil royalties were 16.0% of revenue, after realized financial instruments (16.0% of revenue, before financial instruments). In the third quarter of the previous year, average oil royalties were 11.4% of revenue, after financial instruments (15.4% of revenue, before financial instruments). For the nine months ended September 30, 2010, average oil royalties were 17.6% of revenue, after realized financial instruments (17.6% of revenue, before financial instruments). In the first nine months of the previous year, average oil royalties were 14.2% of revenue, after financial instruments (21.7% of revenue, before financial instruments).

Lower oil royalty rates in 2010, before financial instruments, reflect the benefit of the royalty incentive programs offered by the Alberta government.

Transportation expenses for oil production in the third quarter of 2010 averaged $0.11 per barrel compared to $0.18 per barrel in the third quarter of 2009. Transportation expenses for oil production during the nine months ended September 30, 2010 averaged $0.21 per barrel compared to $0.29 per barrel in the first nine months of 2009.

Lower per unit transportation expenses in 2010 reflect the larger portion of newer NGL production from Kaybob which is mostly pipeline connected and therefore less expensive to transport compared to trucking oil.

For the third quarter ended September 30, 2010, oil production expenses were $9.46 per barrel. In the same quarter of the previous year, oil production expenses were $12.60 per barrel. For the nine months ended September 30, 2010, oil production expenses were $10.73 per barrel. In the same period of the previous year, oil production expenses were $13.42 per barrel.

Lower per unit production expenses in 2010 reflect the larger portion of newer NGL production from Kaybob which is less expensive to produce compared to the Company's older oil production.

Gas Operations

Gas production for the third quarter ended September 30, 2010 averaged 76,555 MCF per day, an increase of 11% compared to 68,964 MCF per day in the corresponding quarter of the previous year. Gas production for the nine months ended September 30, 2010 averaged 79,294 MCF per day, an increase of 36% compared to 58,205 MCF per day in the corresponding period of 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 in the Greater Kaybob area of Alberta.

The average price received for gas sales, after realized financial instruments, for the third quarter ended September 30, 2010 was $4.22 ($3.76 before financial instruments) per MCF, up 24% from the average price of $3.39 ($3.12 before financial instruments) per MCF received in the third quarter of 2009. The average price received for gas sales, after realized financial instruments, for the nine months ended September 30, 2010 was $4.52 ($4.35 before financial instruments) per MCF, compared to $4.13 ($3.93 before financial instruments) per MCF received in the first nine months of 2009.

For the quarter ended September 30, 2010, average gas royalties were 4.5% of revenue, after financial instruments (5.0% of revenue, before financial instruments). In the third quarter of the previous year, average gas royalties were 2.4% of revenue, after financial instruments (2.6% of sales, before financial instruments). For the nine months ended September 30, 2010, average gas royalties were 7.1% of revenue, after financial instruments (7.4% of revenue, before financial instruments). In the first nine months of the previous year, average gas royalties were 10.7% of revenue, after financial instruments (11.2% of sales, before financial instruments).

Lower gas royalty rates in 2010, before financial instruments, are a result of the benefits of longer depth horizontal wells which receive favourable treatment under the Alberta royalty framework and new production qualifying for various incentive programs. 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 third quarter ended September 30, 2010 were $0.08 per MCF, down from $0.22 per MCF for the same quarter in the previous year. Transportation expenses for the nine months ended September 30, 2010 were $0.09 per MCF, down from $0.14 per MCF for the same period in the previous year.

For the third quarter ended September 30, 2010, production expenses of $1.29 per MCF were 9% lower than $1.42 per MCF in the corresponding quarter of the previous year. For the nine months ended September 30, 2010, production expenses of $1.35 per MCF were 14% lower than $1.57 per MCF in the corresponding period of the previous year.

Production expenses in 2010 are lower as 2009 reflects certain one time expenses that were incurred at Kaybob as a result of turnaround operations at the KA Gas Plant in 2009 where the majority of Celtic's gas is processed. The turnaround operations occur every four years.

Other Expenses

For the quarter ended September 30, 2010, general and administrative ("G&A") expenses were $1.0 million ($0.67 per BOE); interest expense was $1.2 million; and depletion, depreciation and accretion ("DD&A") expenses were $28.2 million ($18.60 per BOE). In the previous year, for the quarter ended September 30, 2009, G&A expenses were $1.0 million ($0.73 per BOE); interest expense was $1.3 million; and DD&A expenses were $27.8 million ($19.72 per BOE).

During the nine months ended September 30, 2010, G&A expenses were $3.4 million ($0.72 per BOE); interest expense was $4.3 million; and DD&A expenses were $84.4 million ($17.90 per BOE). In the previous year, for the nine month period ended September 30, 2009, G&A expenses were $2.9 million ($0.81 per BOE); interest expense was $3.6 million; and DD&A expenses were $72.3 million ($20.15 per BOE).

Higher aggregate G&A expenses in 2010 reflect the Company's increased activities and growth year over year. However, with production growth out pacing the increase in G&A expenses, on a BOE basis, G&A expenses are lower year over year. Increase in interest expense in 2010 reflects higher bank spreads. Lower DD&A expense per BOE reflects the addition of proven reserves at lower than historic average costs.

Taxes

For the quarter ended September 30, 2010, Celtic provided for a provision for future income taxes in the amount of $9,000, compared to a recovery of $5.3 million in the third quarter of 2009. For the nine months ended September 30, 2010, Celtic provided for a provision for future income taxes in the amount of $4.7 million, compared to a recovery of $9.2 million in the first nine months of 2009.

For the nine month period ended September 30, 2010, Celtic is not required to pay current income taxes as it has sufficient income tax deductions available to shelter taxable income for the period. Estimated income tax deductions available at September 30, 2010 are $416.6 million and are comprised of $79.7 million of COGPE, $190.6 million of CDE, $44.5 million of CEE, $98.7 million of UCC and $3.1 million of share issue costs.

Earnings

Net loss for the third quarter ended September 30, 2010 was $799,000 ($0.01 per share basic and diluted) compared to a net loss of $13.7 million ($0.16 per share basic and diluted) in the third quarter of 2009. On a barrel of oil equivalent basis, net loss in the third quarter of 2010 was $0.53 per BOE, compared to a net loss of $9.71 per BOE in the third quarter of 2009. During the third quarter of 2010, funds from operations were $31.0 million ($0.34 per share basic and diluted). On a barrel of oil equivalent basis, funds from operations in the third quarter of 2010 were $20.39 per BOE, up 3% from $19.80 per BOE in the same quarter of 2009.

Net earnings for the nine months ended September 30, 2010 were $9.6 million ($0.11 per share basic and diluted) compared to a net loss of $24.2 million ($0.28 per share basic and diluted) in the corresponding nine month period of 2009. On a barrel of oil equivalent basis, net earnings in the first nine months of 2010 were $2.04 per BOE, compared to a net loss of $6.72 per BOE in the first nine months of 2009. During the nine month period ended September 30, 2010, funds from operations were $100.2 million ($1.12 per share basic and $1.10 per share diluted). On a barrel of oil equivalent basis, funds from operations in the first nine months of 2010 were $21.24 per BOE, relatively unchanged from $21.19 per BOE in the first nine months of 2009.

Higher net earnings and higher funds from operations in 2010 reflect the increase in production compared to 2009, which more than offset lower realized per BOE combined oil and gas prices in 2010.

Capital Expenditures

During the quarter ended September 30, 2010, Celtic spent $64.0 million on capital projects. Drilling and completion operations accounted for $33.3 million, equipment and facility expenditures were $10.0 million and $20.7 million was spent on land and seismic. Net capital expenditures, after drilling royalty credits, acquisitions and dispositions were $72.5 million, up 149% from $29.0 million in the third quarter of 2009.

During the nine months ended September 30, 2010, Celtic spent $160.6 million on capital projects. Drilling and completion operations accounted for $111.8 million, equipment and facility expenditures were $23.3 million and $25.5 million was spent on land and seismic. Recovery of drilling costs through drilling royalty credits earned and deemed collectible in the future were $7.7 million. Proceeds from property dispositions were $56.0 million and $7.7 million was incurred on property acquisitions. As a result, net capital expenditures for the six months were $104.6 million, down 2% from $107.2 million in the first nine months of 2009.

At September 30, 2010, the Company had 494,587 gross (432,777 net) acres of undeveloped land. The Company continues to acquire land and build on its inventory of prospects for future drilling.

Drilling Activity

During the third quarter of 2010, the Company drilled 18 (12.7 net) natural gas wells, for an overall success rate of 100%. During the third quarter of 2009, Celtic drilled 14 (11.8 net) wells, with an overall success rate of 93%. The average measured depth of net wells drilled in the third quarter of 2010 was 3,250 metres, an decrease of 7% compared to the average drilling measured depth of 3,512 metres in the third quarter of 2009.

During the nine months ended September 30, 2010, the Company drilled 47 (33.7 net) wells resulting in 42 (29.1 net) natural gas wells, 2 (1.6 net) coal bed methane wells, 1 (1.0 net) oil well and 2 (2.0 net) unsuccessful wells, for an overall success rate of 94%. During the same period in 2009, Celtic drilled 38 (33.4 net) wells, with an overall success rate of 89%. The average measured depth of net wells drilled in the first nine months of 2010 was 3,486 metres, an increase of 9% compared to the average drilling measured depth of 3,187 metres in the first nine months of 2009.

Share Information

The 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 these financial statements are on a post stock split basis. As at September 30, 2010, there were 90.2 million common shares outstanding (as at November 8, 2010, there were 90.3 million common shares outstanding). There are no preferred shares outstanding.

As at September 30, 2010, directors, employees and certain consultants have been granted options to purchase 7.3 million common shares of the Company at an average exercise price of $8.03 per share.

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

2010 Guidance

Celtic 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 endeavor 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 hydrocarbon potential.

Celtic's Board of Directors has approved an increased capital expenditure budget in the amount of $218.0 million (previously $187.0 million) for 2010. Capital expenditures will be reduced by drilling royalty credits earned and deemed claimable in the amount of $8.0 million. Capital spending for 2010 is expected to be financed by property dispositions, funds from operations, with access to available bank credit lines and common share issuances, if necessary.

After forecasting risked production discoveries, timing of production on-stream dates resulting from the Company's planned capital expenditures for 2010, estimated decline rates on existing and new volumes, Celtic expects production in 2010 to average between 17,700 and 18,000 BOE/d (previously 18,200 to 18,500 BOE/d). The production mix is expected to be 23% oil and 77% gas. At the low end of the range of this production forecast, this represents an estimated 25% increase from the average production of 14,192 BOE/d achieved in 2009. Celtic expects to exit 2010 with production of approximately 20,000 BOE/d.

The Company's average commodity price assumptions for 2010 are US$78.00 per barrel for WTI oil, US$4.40 (previously US$4.50) per MMBTU for NYMEX natural gas, $3.77 (previously $3.95) per GJ for AECO natural gas and a US/Canadian dollar exchange rate of US$0.964 (previously US$0.963). These prices compare to average 2009 prices of US$61.63 per barrel for WTI oil, US$4.01 per MMBTU for NYMEX natural gas, $3.97 per GJ for AECO natural gas and a US/Canadian dollar exchange rate of US$0.880.

After giving effect to the aforementioned production and commodity price assumptions and taking into effect risk management contracts in place (as outlined under Future Commitments above), funds from operations for 2010 is forecasted to be approximately $131.0 million (previously $139.0 million) or $1.46 per share ($1.44 per share, diluted) and net earnings are forecasted to be approximately $7.8 million (previously $8.0 million) or $0.09 per share ($0.09 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 shown above.

Bank debt, net of working capital, is estimated to be $195.0 million by the end of 2010 or approximately 1.5 times forecasted 2010 funds from operations.

Celtic's capital expenditure budget for 2010 will see the Company participate at high working interests in the drilling of approximately 67 to 70 (previously 60 to 65) wells during the year, of which over 85% will be horizontal wells. Celtic continues to evaluate and pursue potential 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, reserves, net asset value and funds from operations. Given the Company's strong inventory of drilling locations, we look forward to continued growth in 2010 and beyond.

The information set out herein under the heading "2010 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 2010. Readers are cautioned that this financial outlook may not be appropriate for other purposes.

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