Celtic Reports Another Quarter of Record Production and Funds From Operations in the Three Months Ended June 30, 2008
Fri Aug 8, 7:02 AM(Stock Symbol "CLT" - TSX)
CALGARY, Aug. 8 /CNW/ -
Second Quarter 2008 Highlights
The three months ended June 30, 2008 was another successful quarter in the execution of the Company's growth strategy. Highlights for the second quarter of 2008 are as follows:
- Drilled 10 (8.6 net working interest) wells during the quarter
resulting in 10 (8.6 net) natural gas wells, for an overall success
rate, based on net wells, of 100%;
- Increased average daily production by 55% to a Company quarterly
record 10,842 BOE per day, up from 7,013 BOE per day in the second
quarter of 2007 and achieved daily average production per million
shares outstanding of 270 BOE per day, up 27% in 2008 compared to
213 BOE per day in the corresponding period of the previous year;
- Generated a record high $36.8 million in funds from operations for
the three month period ended June 30, 2008, up 91% from $19.2 million
in the same period of the previous year. Reported funds from
operations per share, diluted, of $0.90, an increase of 64% from
$0.55 per share in the second quarter of the previous year;
- Received an average operating netback of $39.94 per BOE, up 18% from
$33.72 per BOE in the same period of 2007;
- Completed an equity financing by way of a short form prospectus, on a
bought deal basis, by issuing 2.9 million common shares at a price of
$15.00 per share, for gross proceeds of $43.1 million;
- Entered into a term credit agreement on a syndicated basis with
four financial institutions whereby the amount available under this
new credit facility is $200.0 million, up from $165.0 million
available under the previous facility. In addition, Celtic entered
into a two-year interest rate swap transaction whereby $80.0 million
of borrowings under its credit facility has been fixed at an all-in
cost of approximately 4.4% until maturity on April 22, 2010; and
- Completed the acquisition of certain natural gas assets located in
the Company's core operating and producing area at Kaybob South,
Alberta, for a price of $45.2 million. The acquired assets included
interests in certain facilities and proved plus probable reserves of
4.4 million BOE, as evaluated by Celtic's independent engineers,
Sproule Associates Limited. As a result, these long-life reserves
(10.5 year RLI) were acquired at a very competitive price of
$10.35 per BOE.
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Three months ended Six months ended
June 30, June 30,
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($ thousands, unless
otherwise indicated) 2008 2007 Change 2008 2007 Change
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FINANCIAL
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Revenue, before
royalties and
financial
derivatives 80,220 34,556 132% 137,591 65,354 111%
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Funds from
operations 36,787 19,244 91% 65,085 41,290 58%
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Per share,
basic ($) 0.92 0.56 64% 1.67 1.23 36%
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Per share,
diluted ($) 0.90 0.55 64% 1.65 1.21 36%
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Net earnings (loss) (9,116) 2,957 - (16,491) 107 -
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Per share,
basic ($) (0.23) 0.09 - (0.42) 0.00 -
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Per share,
diluted ($) (0.23) 0.09 - (0.42) 0.00 -
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Capital expenditures,
net of
dispositions 67,736 66,431 2% 100,345 122,997 -18%
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Total assets 572,691 465,151 23%
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Bank debt, net of
working capital,
excluding non-cash
financial
instruments 124,179 119,362 4%
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Shareholders' equity 304,523 271,912 12%
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Common shares issued
and outstanding
(thousands)
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Basic 41,059 37,402 10%
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Diluted 43,535 40,155 8%
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OPERATIONS
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Production
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Oil (bbls/d) 3,367 2,947 14% 3,338 3,046 10%
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Natural gas
(mcf/d) 44,852 24,398 84% 41,785 21,702 93%
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Combined
(BOE/d) 10,842 7,013 55% 10,302 6,663 55%
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Production per
million shares
(BOE/d) 270 213 27% 265 199 33%
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Realized sales
prices, after
financial
derivatives
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Oil ($/bbl) 90.48 66.54 36% 85.87 66.14 30%
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Natural gas
($/mcf) 9.52 7.96 20% 9.05 9.42 -4%
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Operating
netbacks ($/BOE)
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Oil and gas
revenue,
before hedging 81.31 53.43 52% 73.39 53.82 36%
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Increased price
from physical
fixed price
contracts 0.00 0.70 0.00 0.37
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Realized gain (loss)
on financial
instruments (13.82) 1.51 (8.85) 6.72
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Realized sales
price, after
hedging 67.49 55.64 21% 64.54 60.91 6%
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Royalties (17.39) (10.36) 68% (16.30) (10.96) 49%
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Production
expense (9.59) (10.73) -11% (9.98) (11.20) -11%
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Transportation
and selling
expense (0.57) (0.83) -31% (0.65) (0.85) -24%
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Operating netback 39.94 33.72 18% 37.61 37.90 -1%
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Drilling activity
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Total wells 10 10 0% 25 39 -36%
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Working interest
wells 8.6 8.3 4% 20.9 35.4 -41%
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Success rate on
working interest
wells 100% 70% 43% 86% 79% 9%
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Undeveloped land (acres)
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Gross 319,882 304,715 5%
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Net 250,113 234,095 7%
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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 second quarter of 2008. During the quarter, Celtic drilled 10 (8.6 net) wells with an overall success rate of 100%. Production during the quarter averaged a record high 10,842 BOE per day, an increase of 55% from the second quarter of 2007. In the second quarter of 2008, Celtic also reported record funds from operations of $36.8 million ($0.90 per share, diluted), an increase of 91% from $19.2 million ($0.55 per share, diluted) reported in the same period of the previous year.
In Southern Alberta, the Company participated in the drilling of two successful Viking natural gas wells in the Drumheller area. Celtic's working interest in these wells is 37.5% and 25.0%.
The remainder of Celtic's drilling activity in the second quarter of 2008 took place in the Greater Kaybob area of West Central Alberta, where eight 100% owned wells were drilled with an overall success rate of 100%. Seven of these wells were horizontals with multi-frac completions.
At Kaybob South, Celtic drilled four horizontal wells, continuing its successful development program in the Montney Triassic natural gas pool. Three horizontal wells were drilled from a single pad right through spring break-up with successful completion results. Further delineation of the Kaybob South pool will continue throughout 2008 and 2009, where the Company will make an application to down-space to five wells per section. Currently, Celtic has approval to drill three wells per section in this liquids-rich natural gas pool.
At KayFox, Celtic continued to have success delineating and extending the size of this Montney Triassic natural gas pool. During the second quarter, the Company drilled three horizontal wells and one directional vertical well. Celtic is very encouraged with the completion results to date. During the quarter, the Company received approval to down-space this Montney pool to three wells per section. In addition, Celtic has discovered a Jurassic Nordegg natural gas pool that overlays a significant portion of the Montney pool. The Company is confident it will be able to dually produce both zones from certain wells and is currently in the process of preparing a co-mingling application. Development of the KayFox Montney and Nordegg gas pools will continue in 2008 and beyond.
Celtic expects to resume drilling operations at Chickadee and Lower Kaybob South during the remainder of 2008, where it has discovered additional Montney natural gas pools. In addition, as initially reported on July 25, 2008, the Company has expanded its Montney land holdings in the Greater Kaybob area as follows:
(1) Celtic has entered into a farm-in agreement with a major petroleum
company on 7,040 (11 sections) gross and 5,133 net (8 sections) acres
of land with Montney rights in the Kaybob South/Pine Creek area of
Alberta. The Company has committed to drill two horizontal wells
targeting the Montney formation, earning a 50% farm-in interest
(36.5% working interest) in three sections per well. The Company will
continue to have an option to drill additional horizontal wells
(earning in three sections per well) or vertical wells (earning
two sections per well). This transaction is subject to third party
preferential rights of first refusal, expiring in 30 days;
(2) In addition, through various tuck-in acquisitions, Celtic has
recently purchased approximately 55 BOE per day of Montney
production, facility interests, and 12,032 (18.8 sections) gross and
11,859 (18.5 sections) net acres of land with Montney/Nordegg rights
in the Greater Kaybob area. Celtic expects to spud its first
horizontal well on these lands within the next 30 to 40 days.
At June 30, 2008, the Company had 319,882 (250,113 net) acres of
undeveloped land. With this inventory of land and with plans to apply for
additional well down-spacing in the Kaybob development prospect, Celtic
continues to generate numerous drilling locations that will provide continued
growth over the next few years.
During the second quarter, Celtic completed the following transactions:
(1) On April 22, 2008, the Company completed an equity financing by way
of a short form prospectus, on a bought deal basis, by issuing
2.9 million common shares at a price of $15.00 per share, for gross
proceeds of $43.1 million;
(2) On April 29, 2008, the Company entered into a term credit agreement
on a syndicated basis with four financial institutions whereby the
amount available under this new credit facility is $200.0 million, up
from $165.0 million available under the previous facility. This
agreement has a maturity date of June 30, 2009. In addition, Celtic
entered into a two-year interest rate swap transaction whereby
$80.0 million of borrowings under its credit facility has been fixed
at an all-in cost of approximately 4.4% until maturity on
April 22, 2010; and
(3) On April 29, 2008, Celtic completed the acquisition of certain
natural gas assets located in the Company's core operating and
producing area at Kaybob South, Alberta, for a price of
$45.2 million. The acquired assets included interests in certain
facilities and proved plus probable reserves of 4.4 million BOE, as
evaluated by Celtic's independent engineers, Sproule Associates
Limited. As a result, these long-life reserves (10.5 year RLI) were
acquired at a very competitive price of $10.35 per BOE.
Oil and gas producers, like Celtic, are continually exposed to fluctuations in commodity prices that are beyond the control of the companies that produce hydrocarbons. In order to mitigate this risk and provide certainty to a portion of its cash flow supporting its capital investment program, Celtic employs an active risk management program.
The Company's outstanding financial derivative contracts relating to its hedged oil and gas production is disclosed in detail in the accompanying notes to the financial statements. At June 30, 2008, the Company recorded an unrealized loss of $46.2 million on its balance sheet based on mark-to-market fair value calculations. After the dramatic decrease in both oil and gas prices during the month of July, the Company's mark-to-market fair value calculations as at July 31, 2008 results in a significantly lower unrealized loss amount of $15.8 million.
On August 5, 2008, Celtic settled the following financial derivative contracts:
(a) 6,500 mmbtu/d NYMEX based natural gas contract for the period from
September 1 to December 31, 2008 in respect of a collar with a floor
price of US$8.00/mmbtu and a ceiling price of US$9.05/mmbtu; and
(b) 25,000 GJ/d AECO based natural gas contract for the period from
October 1 to October 31, 2008 with an average fixed price of
$7.10/GJ.
The effect of settling both transactions requires the Company to make a net payment of $632,000 and will be reflected in Celtic's third quarter results. The Company currently has no natural gas hedges in place after September 30, 2008.
Production
Oil and gas production in the second quarter of 2008 increased 55% to average 10,842 BOE per day compared to 7,013 BOE per day in the same period of 2007. Production per million shares outstanding for the three months ended June 30, 2008 averaged 270 BOE per day, up 27% from 213 BOE per day in the corresponding period of the previous year.
Oil and gas production for the six months ended June 30, 2008 increased 55% to average 10,302 BOE per day compared to 6,663 BOE per day in the same period of 2007. Production per million shares outstanding for the six months ended June 30, 2008 averaged 265 BOE per day, up 33% from 199 BOE per day in the corresponding period of the previous year.
Celtic's production is entirely based in Alberta and is divided into four core areas. In Southern Alberta, the Company's primary natural gas producing properties are located at Drumheller, Michichi and Richdale and its primary oil producing properties are located at Princess and Bantry. In East Central Alberta, the principal producing asset is a shallow natural gas property at Ashmont and Figure Lake. In Northern Alberta, the Company produces mainly light oil from Ogston, Otter and Utikuma Lake. In West Central Alberta, Celtic has both natural gas and light oil production at Kaybob South, Fox Creek and Swan Hills. West Central Alberta will be the Company's most active drilling area in 2008.
Revenue
Revenue, before royalties, and before realized and unrealized gains or losses on financial derivatives, for the three months ended June 30, 2008 was $80.2 million, an increase of 132% compared to $34.6 million in the same period of the previous year. Revenue, before royalties, and before realized and unrealized gains or losses on financial derivatives, for the six months ended June 30, 2008 was $137.6 million, an increase of 111% compared to $65.4 million in the same period of the previous year.
The combined average product price received for oil and gas sales, adjusted for realized gains or losses on financial derivatives for the three months ended June 30, 2008 was $67.49 per BOE, an increase of 21% 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 derivatives for the six months ended June 30, 2008 was $64.54 per BOE, an increase of 6% compared to the corresponding six month period of the previous year.
Oil Operations
Oil production for the quarter ended June 30, 2008 averaged 3,367 barrels per day, an increase of 14% compared to the same three month period of the previous year. Oil production for the six months ended June 30, 2008 averaged 3,338 barrels per day, an increase of 10% compared to the same six month period of the previous year.
The average price received for oil sales, after realized financial derivatives, for the quarter ended June 30, 2008 was $90.48 ($112.43 before financial derivatives) per barrel, up 36% from the average price of $66.54 ($63.72 before financial derivatives) per barrel received in the second quarter of 2007. The average price received for oil sales, after realized financial derivatives, for the six months ended June 30, 2008 was $85.87 ($100.63 before financial derivatives) per barrel, up 30% from the average price of $66.14 ($62.12 before financial derivatives) per barrel received in the first six months of 2007.
For the quarter ended June 30, 2008, average oil royalties were 31.4% of revenue, after financial derivatives (25.3% of sales, before financial derivatives). In the second quarter of the previous year, average oil royalties were 19.5% of revenue, after financial derivatives (20.4% of sales, before financial derivatives). For the six months ended June 30, 2008, average oil royalties were 29.4% of revenue, after financial derivatives (25.1% of sales, before financial derivatives). In the corresponding six month period of the previous year, average oil royalties were 20.1% of revenue, after financial derivatives (21.4% of sales, before financial derivatives). Higher royalty rates, before financial derivatives, in 2008 were primarily a result of higher oil prices received, compared to the previous year.
Transportation expenses for oil production in the second quarter of 2008 averaged $0.55 per barrel compared to $0.54 per barrel in the second quarter of 2007. Transportation expenses for oil production in the first six months of 2008 averaged $0.61 per barrel compared to $0.66 per barrel in the same period of 2007.
For the quarter ended June 30, 2008, production expenses were $12.54 per barrel. In the same period of the previous year, production expenses were $12.47 per barrel. For the six months ended June 30, 2008, production expenses were $13.53 per barrel. In the same period of the previous year, production expenses were $13.14 per barrel.
Natural Gas Operations
Natural gas production for the quarter ended June 30, 2008 averaged 44,852 mcf per day, an increase of 84% compared to the corresponding period of the previous year. Natural gas production for the six months ended June 30, 2008 averaged 41,785 mcf per day, an increase of 93% compared to the corresponding period of the previous year. Increases in natural gas production in 2008 were primarily a result of Celtic's successful drilling results in its resource development prospect located at Kaybob, Alberta.
The average price received for natural gas sales, after realized financial derivatives, for the quarter ended June 30, 2008 was $9.52 ($11.21 before financial derivatives) per mcf, up 20% from the average price of $7.96 ($7.67 before financial derivatives and physical fixed price contracts) per mcf received in the second quarter of 2007. The average price received for natural gas sales, after realized financial derivatives, for the six months ended June 30, 2008 was $9.05 ($10.05 before financial derivatives) per mcf, down 4% from the average price of $9.42 ($7.80 before financial derivatives and physical fixed price contracts) per mcf received in the same period of 2007.
For the quarter ended June 30, 2008, average natural gas royalties were 21.7% of revenue, after financial derivatives (18.6% of sales, before financial derivatives). In the first quarter of the previous year, average natural gas royalties were 17.7% of revenue, after financial derivatives (18.0% of sales, before financial derivatives). For the six month period ended June 30, 2008, average natural gas royalties were 22.1% of revenue, after financial derivatives (20.2% of sales, before financial derivatives). In the first six months of the previous year, average natural gas royalties were 15.9% of revenue, after financial derivatives (19.0% of sales, before financial derivatives). Lower royalty rates, after financial derivatives, in 2007 were primarily a result of significant increases in revenue resulting from physical fixed price contracts and realized gains on financial derivatives. Actual Crown natural gas royalties payable are based on an Alberta reference price and not on actual corporate realized prices.
Transportation expenses for the quarter ended June 30, 2008 were $0.10 per mcf, a decrease of 41% compared to $0.17 per mcf for the same period in the previous year. Transportation expenses for the six months ended June 30, 2008 were $0.11 per mcf, a decrease of 35% compared to $0.17 per mcf for the same period in the previous year.
For the quarter ended June 30, 2008, production expenses of $1.38 per mcf were 13% lower than $1.58 per mcf in the corresponding period of the previous year. For the six months ended June 30, 2008, production expenses of $1.38 per mcf were 13% lower than $1.59 per mcf in the corresponding period of the previous year. Lower production expenses in 2008 reflect the increasing portion of Kaybob production as a percentage of the Company's total production base, where costs are lower than the corporate average.
Other Expenses
For the quarter ended June 30, 2008, general and administrative expenses were $1.0 million ($1.02 per BOE), interest expense was $1.6 million, and depletion, depreciation and accretion expenses were $20.4 million ($20.70 per BOE). In the previous year, for the quarter ended June 30, 2007, general and administrative expenses were $0.7 million ($1.12 per BOE), interest expense was $1.6 million, and depletion, depreciation and accretion expenses were $13.8 million ($21.56 per BOE).
For the six month period ended June 30, 2008, general and administrative expenses were $2.1 million ($1.10 per BOE), interest expense was $3.4 million, and depletion, depreciation and accretion expenses were $40.6 million ($21.65 per BOE). In the previous year, for the six month period ended June 30, 2007, general and administrative expenses were $1.6 million ($1.33 per BOE), interest expense was $2.8 million, and depletion, depreciation and accretion expenses were $26.8 million ($22.23 per BOE).
Taxes
For the quarter ended June 30, 2008, Celtic provided for a recovery of future income taxes in the amount of $3.6 million, compared to a provision of $1.3 million in the second quarter of 2007. For the six months ended June 30, 2008, Celtic provided for a recovery of future income taxes in the amount of $6.5 million, compared to a provision of $46,000 in the first six months of 2007. For the six months ended June 30, 2008, Celtic is not required to pay current income taxes as it has sufficient income tax deductions available to shelter taxable income for the period. The Company does not anticipate paying current income taxes in 2008.
Earnings and Funds from Operations
Net loss for the quarter ended June 30, 2008 was $9.1 million ($0.23 per share, basic and diluted). During the same period, funds from operations were $36.8 million ($0.92 per share, basic and $0.90 per share, diluted). On a barrel of oil equivalent basis, funds from operations in the second quarter of 2008 were $37.29 per BOE, up 24% from $30.15 per BOE in the same period of 2007. The main reasons for the increase in 2008 were higher commodity prices and lower production expenses during the period.
Net loss for the six months ended June 30, 2008 was $16.5 million ($0.42 per share, basic and diluted). During the same period, funds from operations were $65.1 million ($1.67 per share, basic and $1.65 per share, diluted). On a barrel of oil equivalent basis, funds from operations in the first six months of 2008 were $34.71 per BOE, relatively unchanged from $34.24 per BOE in the same period of 2007.
Capital Expenditures
During the quarter ended June 30, 2008, Celtic spent $25.7 million on capital projects. Drilling and completion operations accounted for $17.5 million, equipment and facility expenditures were $6.4 million and $1.8 million was spent on land and seismic. In addition, the Company spent $45.8 million on acquisitions and received proceeds of $3.7 million from dispositions. In the second quarter of the previous year, capital expenditures were $20.6 million and acquisitions were $45.8 million.
During the six months ended June 30, 2008, Celtic spent $58.3 million on capital projects. Drilling and completion operations accounted for $41.8 million, equipment and facility expenditures were $14.4 million and $2.1 million was spent on land and seismic. In addition, the Company spent $45.8 million on acquisitions and received proceeds of $3.7 million from dispositions. In the first six months of the previous year, capital expenditures were $77.2 million and acquisitions were $45.8 million. The Company continues to build on its inventory of prospects for future drilling.
Drilling Activity
During the second quarter of 2008, the Company drilled 10 (8.6 net) wells resulting in 10 (8.6 net) natural gas wells, for an overall success rate, based on net wells, of 100%. During the quarter ended June 30, 2007, Celtic drilled 10 (8.3 net) wells, with an overall success rate of 70%. The average measured depth of net wells drilled in the second quarter of 2008 was 3,061 metres, an increase of 65% compared to the average drilling depth of 1,850 metres in the second quarter of 2007.
During the six month period ended June 30, 2008, the Company drilled 25 (20.9 net) wells resulting in 17 (15.4 net) natural gas wells, 4 (2.6 net) oil wells and 1 (0.1 net) coal bed methane wells, for an overall success rate, based on net wells, of 86%. During the first six months of 2007, Celtic drilled 39 (35.4 net) wells, with an overall success rate of 79%. The average measured depth of net wells drilled in the six month period ended June 30, 2008 was 2,820 metres, an increase of 38%, compared to the average drilling depth of 2,047 metres in the first six months of 2007.
Source of Funds
Investment funding for capital expenditures incurred in the first six months of 2008 was provided by proceeds from issuance of common shares and cash provided by operating activities.
On April 29, 2008, the Company entered into a term credit agreement on a syndicated basis with four financial institutions whereby the amount available under this new credit facility is $200.0 million, up from $165.0 million available under the previous facility. This agreement has a maturity date of June 30, 2009.
At June 30, 2008, Celtic had drawn $116.1 million on its bank credit facility, leaving sufficient unused credit lines available to fund on-going capital expenditures and working capital deficiencies. Repayments of principal are not required provided that the borrowings under the facility do not exceed the authorized borrowing amount and the Company is in compliance with all covenants, representations and warranties.
On April 22, 2008, the Company completed an equity financing by way of a short-form prospectus, on a bought deal basis, by issuing 2.9 million common shares at a price of $15.00 per share, for gross proceeds of $43.1 million. In addition, during the six month period ended June 30, 2008, Celtic received proceeds of $4.1 million from the exercise of stock options.
Celtic expects to fund future capital expenditures through the use of a combination of cash provided by operating activities and bank debt, supplemented by new equity share offerings, as required.
Working Capital
The capital intensive nature of Celtic's activities may create a working capital deficiency position during periods with high levels of capital investment. However, during such periods, the Company maintains sufficient unused bank credit lines to satisfy such working capital deficiencies. At June 30, 2008, the working capital (excluding non-cash financial instruments) amount plus outstanding bank debt represented 62% of the Company's maximum authorized bank borrowing credit limit.
On July 25, 2008, Celtic reported that it has a potential financial exposure of approximately $30.0 million relating to natural gas and associated by-product sales, net of processing costs. The amount receivable at June 30, 2008 was approximately $18.0 million. The exposure relates to the announcement by SemCAMS ULC ("SemCAMS"), a Canadian subsidiary of U.S. based SemGroup LP ("SemGroup"), whereby SemGroup filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code and SemCAMS filed an application to obtain an order under the Companies' Creditors Arrangement Act (Canada) in the Court of Queen's Bench of Alberta Judicial District of Calgary. The full amount of the potential financial exposure relates to the marketing of a portion of the Company's natural gas and associated by-products production. Effective July 22, 2008, the Company is marketing its natural gas through an alternative purchaser, with the agreement of SemCAMS. At this time, Celtic cannot determine the period within which or the amount of the financial exposure that will ultimately be collected. Celtic has sufficient available bank credit lines to finance the potential financial exposure, without affecting the planned 2008 capital expenditure budget of $180.0 million.
Share Information
The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares. As at June 30, 2008, there were 41.1 million common shares outstanding (as at August 5, 2008, there were 41.1 million common shares outstanding). There are no preferred shares outstanding.
As at June 30, 2008, directors, employees and consultants have been granted options to purchase 2.5 million common shares of the Company at an average exercise price of $11.52 per share.
The Company's common shares trade on the Toronto Stock Exchange ("TSX") under the symbol "CLT".
Advisory Regarding Forward-Looking Statements
Certain information with respect to Celtic contained herein, including management's assessment of future plans and operations, contains forward-looking statements. These forward-looking statements are based on assumptions and are subject to numerous risks and uncertainties, certain of which are beyond Celtic's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency exchange rate fluctuations, imprecision of reserve estimates, environmental risks, competition from other explorers, stock market volatility and ability to access sufficient capital. As a result, Celtic's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur. In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. Celtic does not intend, and does not assume any obligation, to update or revise these forward-looking statements except as required pursuant to applicable securities laws.
Outlook
Celtic plans to spend $180.0 million (net) in 2008 on capital investment activities. The Company expects production in 2008 to average in a range from 11,300 to 11,500 BOE per day. Celtic expects to exit 2008 with production of approximately 13,000 BOE per day.
Celtic's forecasted commodity price assumptions for 2008 include oil prices that are estimated to average US$96.00 per barrel for WTI and natural gas prices are forecasted to average US$9.75 per MMBTU for NYMEX and $8.76 per MCF for AECO. The Company's forecasted 2008 average US/Canadian exchange rate is US$1.000.
After giving effect to the production and commodity price assumptions, funds from operations for 2008 is estimated to be approximately $138.0 million or $3.48 per share ($3.40 per share, diluted). Net earnings for 2008 are estimated to be approximately $29.0 million or $0.73 per share. Changes in forecasted commodity prices and variances in production estimates can have a significant impact to estimated funds from operations and net earnings. Please refer to the advisory regarding forward-looking statements shown above.
Celtic's capital expenditure budget for 2008 will see the Company participate at high working interests in the drilling of approximately 64 to 67 wells during the year, of which approximately 40 wells will be horizontals. Celtic continues to pursue property acquisitions that would complement its existing asset base and completion of any future 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, earnings and funds from operations. Given the Company's strong inventory of drilling locations, we look forward to continued growth in 2008 and beyond.
Non-GAAP Financial Measurements
This document contains the terms "funds from operations", "operating netbacks" 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 flow provided by operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. The reconciliation between net earnings and funds from operations can be found in the statement of cash flows included in the audited financial statements. Operating netbacks are determined by deducting royalties, production expenses and transportation and selling expenses from oil and gas sales revenue. 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.
ContactsCELTIC EXPLORATION LTD.
Suite 500
505 - 3rd Street SW
Calgary
Alberta
Canada
T2P 3E6 David J. Wilson
President and Chief Executive Officer
(403) 201-5340 or Sadiq H. Lalani
Vice President
Finance and Chief Financial Officer
(403) 215-5310 or visit our website at www.celticex.com
765.80 (9.02%)
