CALGARY, March 20 /CNW/ - Compton Petroleum Corporation (TSX - CMT, NYSE -
CMZ) is pleased to announce its financial and operating results for the year
and quarter ended December 31, 2005. 2005 was a very successful year for
Compton, the Company completed its planned 390 well drilling program with
excellent results.
2005 HIGHLIGHTS
- Reserve additions 62 million boe, 43% increase
- Reserve value $2.8 billion, 8% DCF
- FD&A costs, $/boe
Excluding future capital $7.05 proved plus probable
$12.84 proved
Including future capital $13.02 proved plus probable
$15.42 proved
- Production replacement 360%
- Record cash flow $278 million, $2.11/share F.D.
Strong Reserve Growth
Total proved plus probable reserves rose 43% from the prior year to 207
million boe and were valued at $2.8 billion, 8% DCF. Total proved reserves at
year end were 126 million boe, an increase of 30% from 2004. Proved producing
reserves comprise 74% of total proved reserves. Total proved reserves account
for 61% of the proved plus probable reserves. On a proved basis, the Company
replaced 360% of its 2005 production and extended its reserve life index from
9 to 12 years.
Record Revenue and Cash Flow
Revenue in 2005 reached record levels of $558 million, up 42% from 2004,
due to a combination of increased production volumes and higher realized
prices. Cash flow increased 57% to $278 million, also benefiting from
increased production and prices. Production for the year averaged 29,424
boe/d, a 9.5% increase from the prior year.
Operating earnings, excluding non-operational amounts, was $94 million
for the year, up 100% over 2004 operating earnings of $47 million. Net
earnings in 2005 increased $18 million, or 28%, from 2004 and were reduced by
non-recurring after tax costs of $14.4 million relating to the repurchase of
U.S.$158.25 million of the Company's 9.90% Senior Notes.
Drilling Results
Compton drilled 392 gross (334 net) wells in 2005 with a 96% success
rate, compared with 186 gross (146 net) wells drilled in 2004. Of the 392
wells drilled in 2005, 80% were classified as development wells and 20% were
classified as exploratory wells, compared to 77% and 23% respectively in 2004.
The higher percentage of development wells in the current year reflects the
increasing maturity of the Company's oil and gas plays.
<<
FINANCIAL SUMMARY
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Three Months Ended Dec. 31 Year Ended Dec. 31
($000's, except % %
per share amounts) 2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
Gross revenue $184,428 $101,189 82% $557,879 $391,659 42%
Cash flow (1) $ 89,640 $ 41,729 115% $278,112 $177,131 57%
Per share - basic $ 0.71 $ 0.36 97% $ 2.21 $ 1.51 46%
- diluted $ 0.67 $ 0.33 103% $ 2.11 $ 1.43 48%
Net earnings $ 38,106 $ 16,377 133% $ 81,326 $ 63,633 28%
Per share - basic $ 0.30 $ 0.14 114% $ 0.65 $ 0.54 20%
- diluted $ 0.28 $ 0.13 115% $ 0.62 $ 0.51 22%
Operating earnings $ 33,413 $ 6,359 425% $ 93,664 $ 46,885 100%
Capital expenditures $513,536 $316,401 62%
Corporate debt, net $601,121 $417,212 44%
Shareholders' equity $596,336 $424,078 41%
Weighted averages
shares (000s)
- basic 125,627 117,244 7%
- diluted 131,667 124,033 6%
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(1) The term "cash flow" should not be considered an alternative to, or
more meaningful than "cash flow from operating activities" as
determined in accordance with Canadian GAAP as an indicator of the
Company's financial performance. Compton's determination of cash
flow may not be comparable to that reported by other companies. The
other items required to arrive at cash flow from operating
activities are considered to be corporate charges.
OPERATING SUMMARY
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Three Months Ended Dec. 31 Year Ended Dec. 31
% %
(6:1 boe conversion) 2005 2004 Change 2005 2004 Change
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Average daily production
Natural gas (MMcf/d) 133 127 5% 131 123 7%
Liquids (light oil
& ngl's) (bbls/d) 8,879 6,963 28% 7,646 6,330 21%
Total oil equivalent
(boe/d) 31,042 28,204 10% 29,424 26,876 9%
Average realized prices
Natural gas ($/Mcf) $11.20 $ 6.29 78% $ 8.42 $ 6.46 30%
Liquids ($/bbl) $57.99 $42.88 35% $56.04 $43.21 30%
Total oil equivalent
($/boe) $64.58 $39.00 66% $51.95 $39.82 30%
Field operating netback
($/boe) $41.62 $22.15 88% $32.36 $23.79 36%
Cash flow netback
($/boe) $20.92 $16.85 24% $26.66 $18.53 44%
Undeveloped land
Gross acres 971,317 1,019,854 -5%
Net acres 738,954 729,429 1%
Average working interest 76% 72% 6%
Reserves (Mboe)
Proved oil equivalent 125,960 96,805 30%
Proved plus probable oil equivalent 206,671 144,777 43%
Reserve life index (years)
Total proved 12 10 20%
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2005 OPERATIONS REVIEW
The Company had a successful drilling program in 2005, with progress made
on all five resource plays. Compton was one of the top 10 most active
operators in Canada throughout the year, drilling 392 wells with a 96% success
rate. The Company completed its planned drilling program, resulting in
62 million boe of reserve adds, despite flooding and abnormally high levels of
rain throughout the summer in Southern Alberta. In 2006, Compton plans to
drill 480 wells, continuing to focus on maximizing production and reserve
growth in all core areas.
Southern Alberta
Southern Alberta remains the primary focus of Compton's activities. The
Company holds 804,007 (699,751 net) acres of land in the South, which are
prospective for multiple zones including Basal Quartz at Hooker, thrusted
Belly River at Callum, Wabamun/Crossfield, Plains Belly River, and
Edmonton/CBM. In 2005, Compton drilled 195 (183 net) wells in Southern Alberta
with a 99% success rate. The Company anticipates spending $361 million and
drilling 277 wells in the area in 2006.
Hooker Basal Quartz
During the past year, Compton continued the development of its Lower
Cretaceous Basal Quartz resource play at Hooker. The play covers an extensive
area of 260,270 (195,200 net) acres. In 2005, the Company drilled 27 wells,
extending the productive limits and optimizing reserve recovery in the heart
of the pool.
In 2005, Compton designed and completed several advanced core and log
analysis studies to gain a better understanding of the petrophysical
characteristics of the play. As a result of this work, the Company now
estimates that the Hooker pool contains at least 1.5 Tcf of gas-in-place.
Compton is currently conducting further engineering and geological studies to
confirm its expectations that the gas-in-place may be greater than initially
determined. It has also become evident that the edges of the Hooker pool are
not yet clearly identified and as such, Compton has designed its 2006 drilling
program to infill and extend the productive limits of the pool.
The Hooker play is currently drilled on one to two wells per section,
however, engineering models and geological studies indicate that at least
three wells per section will be required to maximize reserve recovery from
this low permeability gas pool. Compton has made an application to the EUB to
conduct a pilot drilling program on two sections in the pool to evaluate the
effectiveness of reduced spacing.
Plains Belly River and Horseshoe Canyon Coalbed Methane
In 2005, the Company drilled 170 Belly River wells in the Centron,
Gladys, and Brant areas, with all wells encountering multiple pay sections and
uphole producible Edmonton/Horseshoe Canyon Coals. The Belly River drilling
program continues to exceed expectations.
Compton further refined its Belly River seismic and geological models
during the year. The use of the Company's extensive 3D and 2D seismic database
was critical to identifying the best producible sands. The models were tested
and confirmed through drilling.
Compton currently has approval to drill two wells per section on seven
townships of land. The Alberta Energy and Utilities Board recently announced a
phased modification to spacing for the Belly River in Southern Alberta that is
intended to see the standard spacing change from one well per section to four
wells per section. This initiative would effectively double the number of
Belly River drilling locations in the Company's inventory. In anticipation of
reduced spacing approval, Compton initiated three 3D seismic programs to
assist in the identification of downspace locations. Drilling in select areas
on reduced spacing is expected to start during the third quarter of 2006. This
will allow Compton to dramatically ramp up its Belly River/Edmonton drilling
program, commencing in 2007.
Compton will also define the optimum development of the vertical section
of Belly River and Edmonton Horseshoe Canyon zones. The Company plans to drill
250 wells in 2006 that will have the potential to be completed in both zones.
In addition, Compton has drilled over 400 wells through the Edmonton Horseshoe
Canyon formation into the Belly River sands and the Company is planning to re-
complete 70 of these wells in the Edmonton in 2006.
Compton holds 664,175 (597,760 net) acres of land in Southern Alberta
that is prospective for dry Edmonton Horseshoe Canyon coalbed methane and the
underlying Plains Belly River sands. During 2005, Compton drilled and cored
four CBM pilots across its Southern Alberta acreage to gather the necessary
geological evidence to better quantify its CBM resource potential. Each pilot
consisted of four to six wells, for a total of 19 wells drilled. In-line flow
testing on the initial pilots commenced in the first quarter of 2006 and two
additional pilots are in various stages of well licensing.
The pilots assessed the potential of 483,560 (435,200 net) acres of the
Company's lands in the South. Compton worked closely with Netherland, Sewell &
Associates, Inc., ("Netherland Sewell") independent reserve evaluators,
throughout the pilot programs to quantify the resource potential associated
with the Horseshoe Canyon coals. Netherland Sewell has determined the original
unrisked gas-in-place in the Horseshoe Canyon coals to be 3.05 Tcf and Compton
estimates the net original unrisked gas-in-place on the Company's acreage to
be 2.7 Tcf. This gas-in-place number is restricted to the coals only, with no
interbedded Edmonton sands, silts, or shales included. Additionally, the pilot
evaluations excluded any potential gas that may be present in the overlying
Scollard Formation.
As confirmed by well logs, the remaining 177,780 (160,000 net) acres of
Compton's acreage contain Edmonton sands, silts, and Horseshoe Canyon coals,
and will require further core confirmation of the gas content. In 2006,
Compton will evaluate and quantify the potential of the Edmonton sands and
silts across the Company's acreage in 2006.
The Company has production from the Edmonton Horseshoe Canyon coals at
Centron, Gladys, Brant, and Ghost Pine. Currently Belly River production
extends across Compton's Southern Alberta lands.
Callum Thrusted Belly River
The Callum property consists of a series of low permeability,
overpressured, thrusted Upper Cretaceous Belly River sands in the foothills of
Southern Alberta. Subsequent to year end, the Company acquired its partner's
working interest in the play and now holds a 100% interest in 70,400 acres of
land.
In the second quarter of 2005, the Company drilled a 100% working
interest natural gas well at Callum. Specialized core analysis techniques were
used to assist in identifying more prospective intervals and to optimize
completion fluids and frac design parameters. The lowermost sand in the
stacked Belly River sequence was completed in this well and Compton plans to
monitor and analyze this single zone performance before completing prospective
uphole zones. The well was placed on continuous production in December 2005.
The first two weeks of initial production averaged approximately 1,525 boe per
day from a single sand and the well is continuing to produce approximately 300
boe per day as at the end of February 2006. This well has significantly
improved the Company's geological, geophysical, and engineering models of the
play. The resultant advances in the understanding of this complex reservoir
are a major step forward in the development of the Callum play.
The play is technically complex and the key to successfully developing
the Callum prospect rests with rock characterization and completion
optimization. In the eight Compton wells drilled to date, various completion
techniques have been evaluated. All wells have produced gas and initial
production ranged from 300 Mcfe/d to 8 MMcfe/d.
A second well was drilled in December 2005, encountering multiple sands.
The well has since been cased and Compton is currently testing. The second
well will be completed using methods pioneered by Compton on its previous
well. In 2006, 10 wells are planned at Callum.
Based on Compton's initial detailed geological, geophysical, and
engineering analysis of seismic, cores, well logs, test and production data,
Callum appears to exhibit many similarities to the deep unconventional gas
pools of the Rocky Mountain region of the United States, specifically in the
Greater Green River Basin in Wyoming.
Central Alberta
Central Alberta provides Compton with excellent exploration and
development drilling opportunities using analogous techniques gained through
its years of experience in Southern Alberta unconventional gas development.
Compton has an average 55% working interest in 541,643 (297,475 net) acres of
land. In 2005, the Company drilled 73 (38 net) wells with a 97% success rate
and plans to drill 90 wells in the area in 2006.
Niton
The Niton area, where the majority of Compton's Central Alberta acreage
lies, is characterized by multi-zone, deep basin targets analogous to the
Hooker pool in Southern Alberta. The Company has an interest in 137,390
(103,040 net) acres of land in the play targeting the Gething and Rock Creek
formations. In 2005, 33 wells were drilled and results have continued to
exceed expectations.
As a result of the Company's successful drilling program at Niton, the
Compton owned McLeod River gas plant will be operating at maximum capacity of
20 MMcf/d in the first half of 2006. The Company is currently evaluating plant
expansion alternatives, as well as the option of routing a portion of its
production to adjacent non-operated plants, in which the Company holds minor
working interests.
Peace River Arch
The Peace River Arch area, located north of Grande Prairie, contains
multi-zone exploration and development opportunities. This area includes both
light oil production at Cecil/Worsley and natural gas exploration at Howard
and Pouce Coupe. The Company averages a 61% working interest in 199,040
(121,634 net) acres of land in the area. In 2005, Compton drilled 124 (114
net) wells in the Arch with an 89% success rate and plans to drill 106 wells
in 2006.
Cecil/Worsley
Compton's 2005 drilling program at Worsley was extremely successful,
significantly increasing the reserve value and production from the area. The
Company drilled 80 Charlie Lake oil wells, more than twice the original number
budgeted, which resulted in pool boundary extensions in all directions.
Approval for a pool wide waterflood on the Charlie Lake H and J pool at
Worsley was received in February 2005 and a total of eight wells have been
converted to injectors thus far. The waterflood is projected to increase the
ultimate recovery factor for the pool to 25% from 15% on primary depletion.
The Company will continue its program at Worsley in 2006 and anticipates
drilling 90 wells in the upcoming year.
At Cecil, 23 100% working interest and 9 non-operated 40% working
interest horizontal Charlie Lake oil wells were drilled in 2005. All wells
encountered excellent pay zones and have been systematically brought on
production throughout 2005 and into the first quarter of 2006. Compton is
undertaking geological and engineering work to evaluate additional waterflood
potential in the Cecil area. The Company plans to drill 17 wells in 2006 and
to focus on optimizing production from its previously drilled horizontal
wells.
Reserves
In 2005, Compton added 62 million boe to its proved reserves through
drilling successes, acquisitions, and extensions. Total proved plus probable
reserves increased 43% from the prior year to 207 MMboe.
Compton's total proved reserve base consists of 73% natural gas and 27%
liquids. Proved producing reserves comprise 74% of total proved reserves,
while total proved reserves account for 61% of the proved plus probable
reserves. The Company has a 12 year reserve life index on a proved basis.
Netherland, Sewell Associates, Inc. independently evaluated 100% of Compton's
reserves.
Summary of Estimated Reserve Volumes - Forecast Prices and Costs(1)
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Crude Oil Natural Gas NGL's
Gross Net Gross Net Gross Net
As at December 31, 2005 (Mbbl) (Mbbl) (Bcf) (Bcf) (Mbbl) (Mbbl)
-------------------------------------------------------------------------
Proved
Developed producing 13,537 12,533 424 344 7,837 5,591
Developed non-producing 3,131 2,888 44 35 828 568
Undeveloped 5,019 4,304 84 70 1,731 1,283
-------------------------------------------------------------------------
Total proved 21,688 19,725 553 450 10,396 7,441
Probable 6,805 5,762 401 338 6,232 4,629
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Total proved
plus probable 28,493 25,488 954 788 16,628 12,070
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2004 total proved
plus probable 20,267 17,687 650 528 13,577 9,776
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---------------------------------------------------------
Sulphur Total
Gross Net Gross Net
As at December 31, 2005 (Mlt) (Mlt) (Mboe) (Mboe)
---------------------------------------------------------
Proved
Developed producing 1,603 1,426 93,637 76,937
Developed non-producing 52 41 11,400 9,394
Undeveloped 118 98 20,923 17,366
---------------------------------------------------------
Total proved 1,773 1,565 125,960 103,697
Probable 772 656 80,712 67,334
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Total proved
plus probable 2,545 2,221 206,672 171,031
---------------------------------------------------------
---------------------------------------------------------
2004 total proved
plus probable 2,540 2,236 144,777 117,672
---------------------------------------------------------
(1) Number may not add due to rounding.
Net Present Value of Reserves, Forecast Prices and Costs
-------------------------------------------------------------------------
Future net revenue before income taxes(1)
discounted at a rate of
------------------------------------------
($000s) 0% 8% 10%
-------------------------------------------------------------------------
Proved
Producing $2,809 $1,502 $1,367
Non-producing 407 231 209
Undeveloped 674 278 235
-------------------------------------------------------------------------
Total proved 3,890 2,012 1,811
Probable 2,308 830 681
-------------------------------------------------------------------------
Total proved plus probable $6,199 $2,842 $2,493
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(1) Pricing assumptions are the average of four major Canadian oil and
gas evaluation firms. Numbers may not add due to rounding.
Reserve Reconciliation (net after royalties) - Forecast Prices and Costs
-------------------------------------------------------------------------
Crude Oil, NGLs, and Sulphur Natural Gas
-------------------------------------------------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
(Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf)
-------------------------------------------------------------------------
December 31, 2004 18,719 10,980 29,699 359,029 168,808 527,837
Extensions 1,972 2,633 4,605 33,694 118,596 152,290
Improved recovery 3,816 2,050 5,866 10,555 83,259 93,814
Technical revisions 4,862 (4,882) (20) 61,554 (45,976) 15,568
Discoveries 669 87 756 16,310 12,362 28,672
Acquisitions 722 179 901 5,564 670 6,234
Dispositions (2) - (2) (56) - (56)
Production (2,027) - (2,027) (36,850) - (36,850)
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December 31, 2005 28,731 11,047 39,778 449,790 337,719 787,509
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Capital Expenditures
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Years ended December 31, 2005 2004 2003
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($000s) % ($000s) % ($000s) %
-------------------------------------------------------------------------
Drilling and completions $318,502 62 $175,003 57 $126,308 57
Land and seismic 55,469 11 38,326 12 37,128 17
Facilities 109,729 21 68,861 23 46,068 21
Acquisitions, net 28,575 6 22,825 8 11,224 5
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Sub-total 512,275 100 305,015 100 220,728 100
MPP 1,261 11,386 64,755
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Total capital expenditures $513,536 $316,401 $285,483
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In 2005, Compton significantly increased its drilling program over that
of previous years with the express objective of realizing on its unbooked
resource potential. The Company drilled 334 net wells (392 gross) in 2005 as
compared to 146 net wells (186 gross) in 2004. The number of net wells drilled
in 2005 increased 129% over the number of net wells drilled in 2004.
Reflecting this growth in activity, total 2005 capital expenditures, excluding
MPP related expenditures, increased $207 million, or 68%, from $305 million in
2004 to $512 million in 2005.
As would be expected with the increased well count, 70% of the increase
in capital expenditures relates to drilling and completion costs which
increased $143 million from $175 million in 2004 to $319 million in 2005. On a
per well basis, drilling and completion costs actually decreased 21% to an
average of $0.95 million per net well in 2005 from an average of $1.2 million
per net well in 2004. The decrease in the average cost per well reflects the
Company's drilling focus during 2005. The Company's 2005 drill program
included an additional 80 wells targeting Charlie Lake oil at Cecil and
Worsley and an additional 110 wells targeting shallower Belly River gas in
Southern Alberta as compared to 2004. These wells, and particularly the Belly
River wells, are lower cost as compared to the deeper targets that comprise a
greater percentage of the 2004 drill count.
Facility expenditures, which included processing facilities, gathering
systems, compression and well equipment, comprised 21% of total capital
expenditures and increased in relation to the Company's increased level of
activity.
Strong commodity prices have accelerated capital programs and competition
throughout the oil and gas industry, raising the demand and costs of land,
drilling rigs, completion services, and supplies. During 2005, Compton
experienced cost increases ranging as high as 20% for certain services over
2004 levels. In addition to the increased level of activity in 2005, capital
expenditures for the year reflect this overall increase in the cost of goods
and services.
Finding & Development Costs
Finding, development, and acquisition ("FD&A") costs associated with the
2005 exploration and development program, including revisions and changes in
future capital, were $15.42/boe on a proved basis and $13.02/boe on a proved
plus probable basis. Excluding acquisitions, finding and development ("F&D")
costs were $15.48/boe proved and $13.05/boe proved plus probable.
It should be noted that the aggregate of the exploration and development
costs incurred in 2005 and the change during the year in estimated future
development costs, generally will not reflect total F&D costs related to
reserves additions for the year.
-------------------------------------------------------------------------
FD&A costs ($/boe) 2005 2004 2003 3 Year Average
-------------------------------------------------------------------------
Excluding future capital
Proved $12.84 $13.87 $18.71 $14.09
Proved plus probable $ 7.05 $ 8.51 $ 8.95 $ 7.80
Including future capital
Proved $15.42 $14.91 $20.91 $16.26
Proved plus probable $13.02 $13.19 $14.11 $13.35
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Undeveloped Land
In 2005, Compton continued to expand its land base to maintain a dominant
land position in its core areas. The Company's total net land inventory
increased 6% in 2005, with acquisitions occurring primarily in the Company's
Southern and Central Alberta core areas, while net undeveloped land increased
1% from the prior year. The Company has an average 76% working interest in its
undeveloped land base, reflecting Compton's strategy to establish high
ownership levels and control of operations.
Summary of Land Holdings
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Undeveloped Acres Total Acres
Area Gross Net Gross Net
-------------------------------------------------------------------------
Southern Alberta 464,730 409,678 804,007 699,751
Central Alberta 273,614 186,069 541,643 297,475
Peace River Arch 108,560 75,772 199,040 121,634
Northern Alberta 60,578 32,629 76,418 39,758
Other 63,835 34,806 88,874 37,174
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December 31, 2005 total 971,317 738,954 1,709,982 1,195,792
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December 31, 2004 total 1,019,854 729,429 1,670,048 1,122,860
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FINANCIAL REVIEW
Cash Flow and Net Earnings
-------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------
Cash flow from operations(1) ($000s) $278,112 $177,131 $154,893
Per share: basic $ 2.21 $ 1.51 $ 1.33
diluted $ 2.11 $ 1.43 $ 1.27
Net earnings ($000s) $ 81,326 $ 63,633 $118,880
Per share: basic $ 0.65 $ 0.54 $ 1.02
diluted $ 0.62 $ 0.51 $ 0.97
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(1) Cash flow from operations represents net earnings before depletion
and depreciation, future income taxes, and other non-cash expenses.
Cash flow from operations in 2005 reached a new high as a result of
strong commodity prices and increasing production levels.
Net earnings in 2005 increased $18 million, or 28%, from 2004 and were
reduced by non-recurring one-time costs of $14.4 million ($20.8 million before
taxes) relating to the repurchase of U.S.$158.25 million of 9.90% Senior
Notes. See discussion on Tender Costs.
The following table reconciles cash flow from operating activities to
cash flow from operations.
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Years ended December 31, ($000s) 2005 2004 2003
-------------------------------------------------------------------------
Cash flow from operating activities,
as reported $286,553 $164,537 $156,211
Changes in non-cash operating working
capital items (8,441) 12,594 (1,318)
-------------------------------------------------------------------------
Cash flow from operations $278,112 $177,131 $154,893
-------------------------------------------------------------------------
Operating Earnings
Operating earnings is a non-GAAP measure that adjusts net earnings by non-
operating items that Management believes reduce the comparability of the
Company's underlying financial performance between periods. The following
reconciliation of operating earnings has been prepared to provide investors
with information that is more comparable between years.
Summary of Operating Earnings
-------------------------------------------------------------------------
Years ended December 31,
($000s, except per share amounts) 2005 2004 2003
-------------------------------------------------------------------------
Net earnings, as reported $ 81,326 $ 63,633 $118,880
Non-operational items, after tax
Unrealized foreign exchange (gain) (6,339) (11,821) (37,761)
Unrealized risk management loss 6,345 1,338 -
Stock-based compensation 3,682 2,094 451
Tender costs on repurchase of 9.90% notes 14,414 - -
Future tax recovery due to
tax rate reductions (5,764) (8,359) (37,130)
-------------------------------------------------------------------------
Operating earnings $ 93,664 $ 46,885 $ 44,440
Per share: basic $ 0.75 $ 0.40 $ 0.38
diluted $ 0.71 $ 0.38 $ 0.36
-------------------------------------------------------------------------
The same factors that drove the increase in cash flow from operations -
strong commodity prices and higher production volumes - resulted in 2005
operating earnings almost doubling the prior year level.
Operating Summary
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Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------
Average production
Natural gas (MMcf/d) 131 123 118
Liquids (bbls/d) 7,646 6,330 5,924
-------------------------------------------------------------------------
Total (boe/d) 29,424 26,876 25,552
Benchmark prices
NYMEX (U.S.$/mmbtu) $ 8.55 $ 6.09 $ 5.60
AECO ($/Mcf) $ 8.04 $ 6.44 $ 6.35
WTI (U.S.$/bbl) $ 56.56 $ 41.40 $ 31.04
Edmonton par ($/bbl) $ 68.72 $ 52.37 $ 43.14
Realized prices
Natural gas ($/Mcf) $ 8.42 $ 6.46 $ 6.27
Liquids ($/bbl) 56.04 43.21 35.59
-------------------------------------------------------------------------
Total ($/boe) $ 51.95 $ 39.82 $ 37.16
-------------------------------------------------------------------------
Revenue ($000s)
Natural gas $401,468 $291,565 $269,622
Liquids 156,411 100,094 76,943
-------------------------------------------------------------------------
Total $557,879 $391,659 $346,565
-------------------------------------------------------------------------
Revenue in 2005 increased from the comparable period due to a combination
of increased production volumes and higher realized prices.
Summary of Revenue Increases from Production and Pricing
-------------------------------------------------------------------------
($000s) Natural Gas Liquids Total
Revenue Revenue Revenue
-------------------------------------------------------------------------
Reported 2004 revenue $291,565 $100,094 $391,659
Increase in production volumes 21,659 26,579 48,238
Increase in prices 88,244 29,738 117,982
-------------------------------------------------------------------------
Reported 2005 revenue $401,468 $156,411 $557,879
-------------------------------------------------------------------------
Production volumes in 2005 increased 9% from 2004 as a result of the
Company's 2005 drilling program. Production growth in Southern Alberta, which
accounts for 60% of Compton's total volumes, was hampered by abnormally wet
weather conditions during the summer months. Well completions, pipeline
constructions, and tie-ins scheduled for the second and third quarters were
delayed by field conditions, partially offsetting Compton's aggressive efforts
to increase annual production volumes.
Royalties
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2005 2004 2003
-------------------------------------------------------------------------
Crown royalties $106,253 $ 75,859 $ 68,360
Other royalties 26,890 17,939 14,706
-------------------------------------------------------------------------
Total royalties 133,143 93,798 83,066
Alberta royalty tax credit (426) (382) (500)
-------------------------------------------------------------------------
Net royalties $132,717 $ 93,416 $82,566
Percentage of revenues 23.8% 23.9% 23.8%
-------------------------------------------------------------------------
The Alberta royalty structure is based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. In 2005, the increase in the rate associated with increased
prices is offset by increased oil production and an increase in the number of
lower productivity gas wells, both which attract lower royalty rates.
Operating expense
-------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------
Operating expenses ($000s) $ 66,802 $ 55,655 $ 49,916
Operating expenses per boe ($/boe) $ 6.22 $ 5.66 $ 5.35
-------------------------------------------------------------------------
Operating costs per boe increased year over year due to an overall rise
in industry costs and the additional lifting costs associated with increased
oil production. High commodity prices in 2005 accelerated activity throughout
the oil and gas industry, increasing the demand for and cost of goods and
services. Particular increases of note include salaries for additional field
staff and contract operators, rising electricity prices in the latter half of
2005, salt water disposal, and emulsion processing.
Transportation
-------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------
Transportation costs ($000s) $ 10,858 $ 8,595 $ 8,447
Transportation costs per boe ($/boe) $ 1.01 $ 0.87 $ 0.91
-------------------------------------------------------------------------
Higher transportation costs in 2005 result from a combination of trucking
costs associated with increased crude oil production and surcharges associated
with rising fuel costs.
General & Administrative Expense
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2005 2004 2003
-------------------------------------------------------------------------
General and administrative expenses $ 31,451 $ 24,663 $ 20,355
Capitalized general and
administrative expenses (3,647) (2,683) (3,321)
Operator recoveries (6,581) (6,765) (4,828)
-------------------------------------------------------------------------
Total general and administrative expenses $ 21,223 $ 15,215 $ 12,206
General and administrative per boe ($/boe) $ 1.98 $ 1.55 $ 1.31
-------------------------------------------------------------------------
As budgeted, general and administrative costs increased 39% in the last
year. The major component in this year over year increase, contributing 32%,
was additional employee costs associated with increased personnel levels and a
general increase in salaries necessary to attract and retain qualified
personnel in a very competitive industry. Other increases occurred from the
current regulatory environment including Sarbanes Oxley compliance and the
resulting increase in legal, audit, and reserve evaluation costs.
Interest Expense
-------------------------------------------------------------------------
Years ended December 31, ($000s) 2005 2004 2003
-------------------------------------------------------------------------
Interest on bank debt, net $ 11,520 $ 9,662 $ 6,611
Interest on Senior Notes 20,912 21,281 21,711
-------------------------------------------------------------------------
Interest expense 32,432 30,943 28,322
Finance charges 2,519 2,790 2,273
-------------------------------------------------------------------------
Total interest and finance charges $ 34,951 $ 33,733 $ 30,595
-------------------------------------------------------------------------
Interest costs in 2005 increased from the prior period due to higher debt
levels, precipitated by capital expenditures exceeding cash flow throughout
2005. Interest costs have also been affected by rising interest rates. The
impact on interest expense of issuing U.S.$300 million of 7 5/8% Senior Notes
late in the year was minimal.
Tender Costs
-------------------------------------------------------------------------
Years ended December 31, ($000s) 2005
-------------------------------------------------------------------------
Premium payment $ 7,814
Consent solicitation fee 5,883
Pro-forma reduction of deferred financing
charges on repayment of 9.90% Senior Notes 7,053
-------------------------------------------------------------------------
Total tender costs $ 20,750
-------------------------------------------------------------------------
In November 2005, the Company and a wholly owned subsidiary of the
Company completed a tender offer and consent solicitation to purchase
Compton's 9.90% Senior Notes due in 2009. Holders of U.S.$158.25 million
(approximately 96%) of the outstanding 9.90% Notes tendered the notes and
delivered consents to amend the Indenture. The premium payment for notes
tendered was 104.195% plus accrued and unpaid interest, and the note holders
that delivered consents received 103% for a total consideration of 107.195%.
The unamortized portion of deferred debt financing charges related to the
tendered portion of the 9.90% Senior Notes of $7.1 million was also charged to
tender costs.
Netbacks
-------------------------------------------------------------------------
Years ended December 31, ($/boe) 2005 2004 2003
-------------------------------------------------------------------------
Realized price $51.95 $39.82 $37.16
Royalties, net (12.36) (9.50) (8.85)
Operating expenses (6.22) (5.66) (5.35)
Transportation (1.01) (0.87) (0.91)
-------------------------------------------------------------------------
Field operating netback $32.36 $23.79 $22.05
-------------------------------------------------------------------------
General and administrative (1.98) (1.55) (1.31)
Interest (3.25) (3.43) (3.28)
Current taxes (0.47) (0.28) (0.35)
-------------------------------------------------------------------------
Cash flow netback $26.66 $18.53 $17.11
-------------------------------------------------------------------------
Depletion and Depreciation
-------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
-------------------------------------------------------------------------
Total depletion and depreciation ($000s) $105,504 $82,554 $ 61,749
Depletion and depreciation per boe ($/boe) $ 9.82 $ 8.39 $ 6.62
-------------------------------------------------------------------------
The Company's 2005 provision for depletion and depreciation increased
$23 million or 28% over 2004. Approximately one third of this increase was due
to the increase in 2005 production over that of 2004 with the balance being
the result of an overall increase in the depletion and depreciation rate as
determined on a boe basis. The depletion and depreciation rate on a boe basis
reflects increased costs relating to exploration and development activities as
discussed in capital expenditures.
Foreign Exchange
The foreign exchange gain recognized on the consolidated statements of
earnings results primarily from the translation of the Company's U.S. dollar
denominated Senior Notes into Canadian dollars. The Senior Notes are
translated and recorded in the financial statements at the year end exchange
rate, with any differences from prior measurements recorded as unrealized
foreign exchange gain or loss.
The Canadian/U.S. exchange rate increased to one Canadian Dollar being
equal to U.S.$0.8577 on December 31, 2005 from one Canadian Dollar being equal
to U.S.$0.8308 at December 31, 2004, resulting in the Company recording a
$7 million foreign exchange gain in 2005.
On November 22, 2005, pursuant to a tender offer, the Company repurchased
U.S.$158.25 million of the 9.90% Senior Notes issued in 2002. As a result of
the repurchase, the Company crystallized $62.2 million of the accumulated
unrealized foreign exchange gains that had been previously recognized with the
strengthening of the Canadian dollar subsequent to the note issuance.
Liquidity and Capital Resources
-------------------------------------------------------------------------
As at December 31,
($000s, except where noted) 2005 2004 2003
-------------------------------------------------------------------------
Working capital(1) $ 62,431 $ 603 $(21,843)
Bank debt 177,900 220,000 164,500
Senior term notes 357,640 198,594 213,246
-------------------------------------------------------------------------
Total indebtedness $597,971 $419,197 $355,903
Capital stock $226,444 $135,526 $131,577
Contributed surplus 9,173 3,840 760
Retained earnings 360,719 284,712 224,569
-------------------------------------------------------------------------
Shareholders' equity $596,336 $424,078 $356,906
Debt to cash flow from operations(2)(3) 1.93 2.36 2.44
Debt to book capitalization(2) 47% 50% 51%
Debt to market capitalization(2) 20% 25% 35%
-------------------------------------------------------------------------
(1) Working capital excludes unrealized risk management items.
(2) Debt includes current and long term portion and excludes unrealized
risk management items.
(3) Based on trailing 12 month cash flow from operations.
Working capital at December 31, 2005 decreased from the prior year due to
the Company's extremely active fourth quarter and the resulting increase in
trade payables. At year end, Compton had drawn $178 million on its available
$289 million syndicated credit facility.
In November 2005, a wholly owned subsidiary of the Company issued
U.S.$300 million of 7 5/8% Senior Notes due in 2013. The proceeds were used to
repay a portion of the Company's debt under its senior secured credit
facilities and to fund the purchase of a portion of the 9.90% Senior Notes due
in 2009, by a wholly owned subsidiary of the Company. At December 31, 2005,
U.S.$6.75 million of the 9.90% Notes remain outstanding but can be called, at
a premium, anytime after May 15, 2006. The purchase of the 9.90% Notes
eliminated the restrictive covenants of the Indenture agreement and have
provided the Company with greater financial flexibility.
The principal amount of the Senior Notes remains fixed at
U.S. $300 million. The value of the notes shown on the consolidated balance
sheets varies in response to movement in the Canadian/U.S. dollar exchange
rate. Standards & Poor's Rating Services ("S&P") and Moody's Corporation
("Moody's") have rated the U.S. $300 million 7 5/8% Senior Notes as B stable
and B2 stable respectively, as at December 31, 2005.
The Company expects internally generated operating cash flow together
with other available financing options, including debt financing, readily
accessible equity markets, and potential minor non-core property dispositions,
will fund its planned 2006 capital program while maintaining fiscal
responsibility.
Guidance For 2006
Compton's 2006 budget was prepared in December 2005, and reflected
commodity price forecasts at that time. With the recent decline in natural gas
prices, the Company has reassessed its budget in relation to current prices.
Current lower prices will reduce cash flow by $80 million from that originally
projected if sustained over the remainder of the year. At this juncture, the
Company has not revised its drilling and capital programs.
In 2006, Compton will continue to focus on the development of its five
natural gas resource plays and conventional crude oil property to maximize
reserve recognition and production growth.
Summary of 2006 Guidance
-------------------------------------------------------------------------
2006 Budget Range
-------------------------------------------------------------------------
Capital expenditures ($millions) $575
Gross wells 480
Average production
Natural gas (mmcf/d) 155 to 160
Liquids (bbls/d) 11,000 to 11,300
-------------------------------------------------------------------------
Total (boe/d) 37,000 to 38,000
Cash flow from operations ($millions) $375 to $390
-------------------------------------------------------------------------
The Company's revised 2006 projected cash flow from operations projection
is based upon the following pricing assumptions:
-------------------------------------------------------------------------
Benchmark Realized
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural gas AECO Cdn $7.90/GJ Cdn $8.15/mcf
Crude oil ($/bbl) WTI U.S. $62.00 Cdn $65.00
-------------------------------------------------------------------------
The average Canadian/U.S. exchange rate is budgeted at
$0.85 U.S. (equal sign) $1.00 Cdn.
Cash Flow Sensitivities for 2006
-------------------------------------------------------------------------
($millions)
-------------------------------------------------------------------------
Change of Cdn $0.10/mcf in the benchmark AECO natural gas price $4.5
Change of U.S. $1.00/barrel in the benchmark WTI oil price $3.0
-------------------------------------------------------------------------
In the event of significant decreases in commodity prices, increases in
exploration costs, or an overall economic downturn, the Company's capital
expenditure program can be readily modified.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Balance Sheets
(thousands of dollars)
-------------------------------------------------------------------------
December 31, December 31,
2005 2004
------------- ------------
(unaudited)
Assets
Current
Cash $ 8,954 $ 10,068
Accounts receivable and other 132,484 115,113
Unrealized risk management gain (Note
16a (i)) - 1,985
------------- ------------
141,438 127,166
Property and equipment (Note 4) 1,587,371 1,178,550
Goodwill (Note 2) 7,914 7,914
Deferred financing charges and other (Note 8) 13,156 9,729
Deferred risk management loss (Note 16a (ii)) 5,610 7,252
------------- ------------
$ 1,755,489 $ 1,330,611
------------- ------------
------------- ------------
Liabilities
Current
Bank debt (Note 5) $ - $ 220,000
Accounts payable 203,869 125,483
Unrealized risk management loss (Note
16a (i)) 3,150 -
Income taxes payable - 301
------------- ------------
207,019 345,784
Bank debt (Note 5) 177,900 -
Senior term notes (Note 6) 357,640 198,594
Asset retirement obligations (Note 10) 20,770 18,006
Unrealized risk management loss (Note
16a (iii)) 14,809 11,416
Future income taxes (Note 15b) 312,117 261,196
Non-controlling interest (Note 3) 68,898 71,537
------------- ------------
1,159,153 906,533
------------- ------------
Shareholders' equity
Capital stock (Note 11b) 226,444 135,526
Contributed surplus (Note 12a) 9,173 3,840
Retained earnings 360,719 284,712
------------- ------------
596,336 424,078
------------- ------------
$ 1,755,489 $ 1,330,611
------------- ------------
------------- ------------
Commitments and contingent liabilities (Note 18)
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Earnings
(unaudited) (thousands of dollars, except per share data)
-------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
---------------------- ---------------------
2005 2004 2005 2004
----------- ---------- ---------- ----------
Revenue
Oil and natural gas
revenues $ 184,428 $ 101,189 $ 557,879 $ 391,659
Royalties (43,524) (25,487) (132,717) (93,416)
----------- ---------- ---------- ----------
140,904 75,702 425,162 298,243
----------- ---------- ---------- ----------
Expenses
Operating 18,929 15,691 66,802 55,655
Transportation 3,118 2,536 10,858 8,595
General and administrative 6,864 4,880 21,223 15,215
Interest and finance charges
(Note 7) 10,741 8,808 34,951 33,733
Tender costs (Note 8) 20,750 - 20,750 -
Depletion and depreciation 31,005 24,308 105,504 82,554
Foreign exchange gain
(Note 9) (347) (9,959) (7,353) (14,631)
Accretion of asset retirement
obligations (Note 10) 559 409 1,975 1,670
Stock-based compensation
(Note 12a) 1,649 711 5,903 3,410
Risk management (gain) loss
(Note 16a (iv)) (16,808) (1,779) 19,302 8,808
----------- ---------- ---------- ----------
76,460 45,605 279,915 195,009
----------- ---------- ---------- ----------
Earnings before taxes
and non-controlling
interest 64,444 30,097 145,247 103,234
----------- ---------- ---------- ----------
Income taxes (Note 15a)
Current 3,597 71 5,071 2,751
Future 21,261 11,637 52,317 33,432
----------- ---------- ---------- ----------
24,858 11,708 57,388 36,183
----------- ---------- ---------- ----------
Earnings before non-
controlling interest 39,586 18,389 87,859 67,051
Non-controlling interest
(Note 3) 1,480 2,012 6,533 3,418
----------- ---------- ---------- ----------
Net earnings $ 38,106 $ 16,377 $ 81,326 $ 63,633
----------- ---------- ---------- ----------
----------- ---------- ---------- ----------
Net earnings per share
(Note 13)
Basic $ 0.30 $ 0.14 $ 0.65 $ 0.54
----------- ---------- ---------- ----------
----------- ---------- ---------- ----------
Diluted $ 0.28 $ 0.13 $ 0.62 $ 0.51
----------- ---------- ---------- ----------
----------- ---------- ---------- ----------
-------------------------------------------------------------------------
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
---------------------- ---------------------
2005 2004 2005 2004
----------- ---------- ---------- ----------
Retained earnings, beginning
of year $ 323,311 $ 270,473 $ 284,712 $ 224,569
Net earnings 38,106 16,377 81,326 63,633
Premium on redemption of
shares (Note 11b) (698) (2,138) (5,319) (3,490)
----------- ---------- ---------- ----------
Retained earnings,
end of year $ 360,719 $ 284,712 $ 360,719 $ 284,712
----------- ---------- ---------- ----------
----------- ---------- ---------- ----------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
---------------------- ---------------------
2005 2004 2005 2004
----------- ---------- ---------- ----------
Operating activities
Net earnings $ 38,106 $ 16,377 $ 81,326 $ 63,633
Amortization of deferred
charges and other 743 652 2,190 2,101
Tender costs 20,750 - 20,750 -
Depletion and depreciation 31,005 24,308 105,504 82,554
Accretion of asset
retirement obligations 559 409 1,975 1,670
Unrealized foreign
exchange gain (796) (9,949) (7,808) (14,652)
Future income taxes 21,261 11,637 52,317 33,432
Unrealized risk management
(gain) loss (24,759) (3,905) 10,171 2,179
Stock-based compensation 1,649 711 5,903 3,410
Asset retirement
expenditures (358) (523) (749) (614)
Non-controlling interest 1,480 2,012 6,533 3,418
----------- ---------- ---------- ----------
89,640 41,729 278,112 177,131
Change in non-cash working
capital (Note 17) 11,809 (9,861) 8,441 (12,594)
----------- ---------- ---------- ----------
101,449 31,868 286,553 164,537
----------- ---------- ---------- ----------
Financing activities
Issuance (repayment)
of bank debt (82,100) 35,050 (42,100) 43,373
Issuance of senior notes 353,130 - 353,130 -
Issue costs on senior notes (12,670) - (12,670) -
Redemption of senior notes (199,973) - (199,973) -
Proceeds from share
issuances, net 331 486 89,752 3,258
Proceeds from partnership
unit issuance - 300 - 74,343
Distributions to partner (2,293) (2,292) (9,172) (6,114)
Redemption of common shares (790) (2,405) (6,118) (4,005)
Change in non-cash working
capital (Note 17) (6,679) (3,711) (1,829) 324
----------- ---------- ---------- ----------
48,956 27,428 171,020 111,179
----------- ---------- ---------- ----------
Investing activities
Property and equipment
additions (161,186) (91,194) (484,213) (296,676)
Corporate acquisitions
(Note 2) - (5,691) - (12,132)
Property acquisitions (11,376) (16,278) (28,575) (20,830)
Property dispositions - 19,276 - 19,276
Change in non-cash working
capital (Note 17) 14,211 30,942 54,101 29,166
----------- ---------- ---------- ----------
(158,351) (62,945) (458,687) (281,196)
----------- ---------- ---------- ----------
Change in cash (7,946) (3,649) (1,114) (5,480)
Cash, beginning of year 16,900 13,717 10,068 15,548
----------- ---------- ---------- ----------
Cash, end of year $ 8,954 $ 10,068 $ 8,954 $ 10,068
----------- ---------- ---------- ----------
----------- ---------- ---------- ----------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Notes to the Consolidated Financial Statements
December 31, 2005
(unaudited)
(Tabular amounts in thousands of dollars, unless otherwise stated)
-------------------------------------------------------------------------
1. Significant accounting policies
Compton Petroleum Corporation (the "Company" or "Compton") is in the
business of the exploration for and production of petroleum and
natural gas reserves in the Western Canada Sedimentary Basin.
a) Basis of presentation
The consolidated financial statements of the Company have been
prepared in accordance with accounting principles generally accepted
in Canada within the framework of the accounting policies summarized
below.
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. The consolidated financial
statements also include the accounts of Mazeppa Processing
Partnership in accordance with Accounting Guideline 15 ("AcG-15")
"Consolidation of Variable Interest Entities", as outlined in Note 3.
All amounts are presented in Canadian dollars unless otherwise
stated.
b) Measurement uncertainty
The timely preparation of financial statements requires that
Management make estimates and assumptions and use judgment regarding
assets, liabilities, revenues, and expenses. Such estimates relate
primarily to transactions and events that have not settled as of the
date of the financial statements. Accordingly, actual results may
differ from estimated amounts as future confirming events occur.
Amounts recorded for depletion and depreciation, and amounts used in
impairment test calculations are based upon estimates of petroleum
and natural gas reserves and future costs to develop those reserves.
By their nature, these estimates of reserves, costs, and related
future cash flows are subject to uncertainty, and the impact on the
consolidated financial statements of future periods could be
material.
The calculation of asset retirement obligations include estimates of
the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, and timing of settlement. The impact of future
revisions to these assumptions on the consolidated financial
statements of future periods could be material.
The values of pension assets and obligations and the amount of
pension costs charged to net earnings depend on certain actuarial and
economic assumptions which by their nature are subject to measurement
uncertainty.
c) Property and equipment
i) Capitalized costs
The Company follows the full cost method of accounting for its
petroleum and natural gas operations. Under this method all
costs related to the exploration for and development of
petroleum and natural gas reserves are capitalized. Costs
include lease acquisition costs, geological and geophysical
expenses, costs of drilling both producing and non-producing
wells, production facilities, asset retirement costs, and
certain general and administrative expenses directly related to
exploration and development activities.
Proceeds from the sale of properties are applied against
capitalized costs, without any gain or loss being realized,
unless such sale would significantly alter the rate of depletion
and depreciation.
Expenditures related to renewals or betterments that improve the
productive capacity or extend the life of an asset are
capitalized. Maintenance and repairs, other than major
turnaround costs, are expensed as incurred. Major turnaround
costs are included in property and equipment when incurred and
charged to depletion and depreciation in the consolidated
statement of earnings over the estimated period of time to the
next scheduled turnaround.
ii) Depletion and depreciation
Depletion and depreciation of property and equipment is provided
using the unit-of-production method based upon estimated proved
petroleum and natural gas reserves. The costs of significant
undeveloped properties are excluded from costs subject to
depletion until it is determined whether or not proved reserves
are attributable to the properties or impairment has occurred.
Estimated future costs to be incurred in developing proved
reserves are included in costs subject to depletion. For
depletion and depreciation purposes, relative volumes of natural
gas production and reserves are converted at the energy
equivalent conversion rate of six thousand cubic feet of natural
gas to one barrel of crude oil.
Depreciation of certain midstream facilities is provided for on
a straight line basis over 30 years and depreciation of office
equipment is provided for on a declining balance basis at 20%
per year.
iii) Impairment test
At each reporting period the Company performs an impairment test
to determine the recoverability of capitalized costs associated
with reserves. An impairment loss is recognized when the
carrying amount of a cost centre exceeds its fair value. The
carrying amount of the cost centre is not recoverable if the
carrying amount exceeds the sum of the undiscounted cash flows
from proved reserves plus the costs of unproved properties. If
the sum of the cash flows is less than the carrying amount, the
impairment loss is limited to the amount by which the carrying
amount exceeds the sum of the fair value of proved and probable
reserves and the costs of unproved properties that have been
subject to a separate impairment test and contain no probable
reserves.
iv) Asset retirement obligations
The Company recognizes the fair value of estimated asset
retirement obligations on the consolidated balance sheet when a
reasonable estimate of fair value can be made. Asset retirement
obligations include those legal obligations where the Company
will be required to retire tangible long-lived assets such as
well sites, pipelines, and facilities. The asset retirement
cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the
related long-lived asset. Changes in the estimated obligation
resulting from revisions to estimated timing or amount of
undiscounted cash flows are recognized as a change in the asset
retirement obligation and the related asset retirement cost.
Asset retirement costs are amortized using the
unit-of-production method and are included in depletion and
depreciation in the consolidated statement of earnings.
Increases in the asset retirement obligations resulting from the
passage of time are recorded as accretion of asset retirement
obligations in the consolidated statement of earnings.
Actual expenditures incurred are charged against the accumulated
obligation.
v) Inventories
Physical inventory held for exploration, development, and
operating activities is included in property and equipment and
is valued at cost.
d) Goodwill
Goodwill is recorded on a corporate acquisition when the purchase
price is in excess of the fair values assigned to assets acquired and
liabilities assumed. Goodwill is not amortized and an impairment test
is performed at least annually to evaluate the carrying value. To
assess impairment the fair value of the consolidated entity,
excluding the Mazeppa Processing Partnership, is determined and
compared to the carrying value. If fair value is less than the
carrying value then a second test is performed to determine the
amount of the impairment. Any loss recognized is equal to the
difference between the implied fair value and the carrying value of
the goodwill.
e) Financial instruments
Financial instruments consist mainly of accounts receivable and
other, accounts payable, and long-term debt. The Company uses
financial instruments for non-trading purposes to manage fluctuations
in commodity prices, foreign currency exchange rates, and interest
rates as described in Note 16. The Company has elected not to
designate any of its current risk management activities as accounting
hedges and accounts for all derivative financial instruments using
the mark-to-market accounting method.
f) Joint operations
Certain petroleum and natural gas activities are conducted jointly
with others. These consolidated financial statements reflect only the
Company's proportionate interest in such activities.
g) Flow-through shares
Resource expenditure deductions for income tax purposes related to
exploration and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. The liability for future income taxes is increased and
capital stock is reduced by the estimated tax benefits transferred to
shareholders at the time the resource expenditure deductions are
renounced.
h) Earnings per share amounts
The Company uses the treasury stock method to determine the dilutive
effect of stock options. This method assumes that proceeds received
from the exercise of in-the-money stock options are used to
repurchase common shares at the average market price for the period.
Basic net earnings per common share are determined by dividing net
earnings by the weighted average number of common shares outstanding
during the period. Diluted earnings per share are computed by giving
effect to the potential dilution that would occur if stock options
were exercised.
i) Income taxes
Income taxes are recorded using the liability method of accounting.
Future income taxes are calculated based on the difference between
the accounting and income tax basis of an asset or liability, using
the substantively enacted income tax rates. Changes in income tax
rates that are substantively enacted are reflected in the accumulated
future income tax balances in the period the change occurs.
j) Revenue recognition
Revenue associated with the production and sale of crude oil, natural
gas, and natural gas liquids owned by the Company is recognized when
the purchaser takes possession of the commodity product. Other
revenue is recognized in the period that the service is provided to
the customer.
k) Stock-based compensation plan
The Company records compensation expense in the consolidated
statements of earnings for stock options granted to Directors,
Officers, and employees using the fair-value method. Compensation
costs are recognized over the vesting period and the fair values are
determined using the Black-Scholes option pricing model.
The Company also has an employee stock savings plan. The
contributions are recorded as compensation expense as incurred.
l) Deferred financing charges
Financing costs related to the issuance of senior term notes are
deferred and are amortized over the term of the notes on a
straight-line basis. If the notes are retired, in whole or in part,
prior to maturity, a pro-rata share of the unamortized balance is
expensed in the consolidated statement of earnings.
m) Foreign currency translation
Monetary assets and liabilities of the Company that are denominated
in foreign currencies are translated into Canadian dollars at the
period-end exchange rate, with any resulting gain or loss recorded in
the consolidated statement of earnings.
n) Dividend policy
The Company has neither declared nor paid any dividends on its common
shares. The Company intends to retain its earnings to finance growth
and expand its operations and does not anticipate paying any
dividends on its common shares in the foreseeable future.
o) Defined benefit pension plan
The Company accrues for obligations under a defined benefit pension
plan and the related costs, net of plan assets. The cost of the
pension is actuarially determined using the projected benefit method
based on length of service and reflects Management's best estimate of
expected plan investment performance, salary escalation, and
retirement age of employees.
2. Business combinations
On April 12, 2004 and November 15, 2004, respectively, the Company
acquired 100% of the issued and outstanding shares of Redwood Energy,
Ltd. and Mayfair Energy Ltd. for total cash consideration of
$12.1 million plus the assumption of $12.1 million of debt. Both entities
were independent exploration and production companies with operations in
the Company's core areas.
The business combinations have been accounted for using the purchase
method with results of operations included in the consolidated financial
statements from the date of acquisition. Goodwill recognized on these
transactions amounted to $7.9 million.
During the year ended December 31, 2004, both companies were wound up
into Compton Petroleum Corporation and dissolved.
3. Non-controlling interest
Mazeppa Processing Partnership ("MPP" or "the Partnership") is a limited
partnership organized under the laws of the province of Alberta and owns
certain midstream facilities, including gas plants and pipelines in
Southern Alberta. The Company processes a significant portion of its
production from the area through these facilities pursuant to a
processing agreement with MPP. The Company does not have an ownership
position in MPP, however, the Company, through a management agreement,
manages the activities of MPP and is considered to be the primary
beneficiary of MPP's operations. Pursuant to AcG-15, these consolidated
financial statements include the assets, liabilities, and operations of
the Partnership. Equity in the Partnership, attributable to the partners
of MPP, is recorded on consolidation as a non-controlling interest and is
comprised of the following:
As at December 31, 2005 2004
------------ ------------
Non-controlling interest, beginning of year $ 71,537 $ (110)
Proceeds from issue of Partnership units, net - 74,343
Earnings attributable to non-controlling
interest 6,533 3,418
Distributions to limited partner (9,172) (6,114)
------------ ------------
Non-controlling interest, end of year $ 68,898 $ 71,537
------------ ------------
------------ ------------
Commencing May 1, 2004, pursuant to the terms of a processing agreement
between Compton and MPP, Compton pays a monthly fee to MPP for the
transportation and processing of natural gas through the MPP owned
facilities. The fee is comprised of a fixed base fee of $764 thousand per
month plus MPP operating costs, net of third party revenues. These
amounts are eliminated from revenues and expenses on consolidation.
The processing agreement has a five year term ending April 1, 2009, at
which time Compton may renew the agreement under terms determined at that
time or purchase the Partnership units for the predetermined amount of
$55 million, deemed to be fair value. In the event that the Company does
not renew the processing agreement nor exercise the purchase option, the
Limited Partner may dispose of the Partnership units to an independent
third party.
MPP has guaranteed payment of certain obligations of its limited partner
under a credit agreement between the limited partner and a syndicate of
lenders. The maximum liability of the Partnership under the guarantee is
limited to amounts due and payable to MPP by the Company pursuant to the
processing agreement. The maximum liability at December 31, 2005 was
$30.6 million (2004 - $39.7 million) payable over the remaining term of
the processing agreement. The Company has determined that its exposure to
loss under these arrangements is minimal, if any.
4. Property and equipment
Accumulated
depletion and
As at December 31, 2005 Cost depreciation Net
------------ ------------ ------------
Exploration and
development costs $ 1,553,543 $ (366,902) $ 1,186,641
Production equipment and
processing facilities 436,948 (52,771) 384,177
Inventory 6,469 - 6,469
Future asset retirement costs 10,365 (3,771) 6,594
Office equipment 7,641 (4,151) 3,490
------------ ------------ ------------
$ 2,014,966 $ (427,595) $ 1,587,371
------------ ------------ ------------
------------ ------------ ------------
Accumulated
depletion and
As at December 31, 2004 Cost depreciation Net
------------ ------------ ------------
Exploration and
development costs $ 1,161,396 $ (281,614) $ 879,782
Production equipment and
processing facilities 317,477 (34,150) 283,327
Inventory 6,187 - 6,187
Future asset retirement costs 9,576 (3,111) 6,465
Office equipment 6,005 (3,216) 2,789
------------ ------------ ------------
$ 1,500,641 $ (322,091) $ 1,178,550
------------ ------------ ------------
------------ ------------ ------------
Employee salaries and insurance costs of $4.7 million at December 31,
2005 (2004 - $4.6 million) directly related to exploration and
development activities were capitalized. No other general and
administrative costs are capitalized.
As at December 31, 2005 future capital expenditures of $192.9 million
(2004 - $89.1 million, 2003 - $62.4 million), as estimated by independent
reserve engineers, relating to the development of proved reserves have
been included in costs subject to depletion. Undeveloped properties with
a cost at December 31, 2005 of $251.3 million (2004 - $187.8 million,
2003 - $161.9 million) included in exploration and development costs,
have not been subject to depletion.
The prices used in the evaluation of the carrying value of the Company's
reserves for the purposes of the impairment test are:
Natural
As at December 31, 2005 gas Oil NGL
------------ ------------ ------------
$ per mcf $ per bbl $ per bbl
2006 $11.86 $61.58 $61.87
2007 $10.76 $60.97 $61.64
2008 $9.16 $57.38 $58.19
2009 $8.33 $54.11 $55.05
2010 $8.09 $51.85 $52.58
Approximate % increase thereafter 2% 2% 2%
5. Credit facilities
As at December 31, 2005 2004
------------ ------------
Authorized $ 289,000 $ 240,000
------------ ------------
------------ ------------
Prime rate $ 22,900 $ 3,000
Bankers' Acceptance 155,000 217,000
------------ ------------
Utilized $ 177,900 $ 220,000
------------ ------------
------------ ------------
As at December 31, 2005, the Company had arranged authorized senior
credit facilities with a syndicate of Canadian banks in the amount of
$289 million. Advances under the facilities can be drawn and currently
bear interest as follows:
Prime rate plus 0.15%
Bankers' Acceptance rate plus 1.15%
LIBOR rate plus 1.15%
Margins are determined based on the ratio of total consolidated debt to
consolidated cash flow. The facilities reach term on July 5, 2006 and, if
not renewed, will mature 366 days later on July 6, 2007. Accordingly, the
2005 facilities have been classified as a non-current liability.
The senior credit facilities are secured by a first fixed and floating
charge debenture in the amount of $600 million covering all the Company's
assets and undertakings.
6. Senior term notes
As at December 31, 2005 2004
------------ ------------
Senior term notes
US$300 million, 7.625% due December 1, 2013 $ 349,770 $ -
US$6.75 million, 9.90% due May 15, 2009
(2004 - US$165 million) 7,870 198,594
------------ ------------
$ 357,640 $ 198,594
------------ ------------
------------ ------------
In November 2005, a wholly owned subsidiary of the Company issued
US$300 million senior term notes maturing December 1, 2013. The notes
bear interest at 7.625% and are subordinate to the Company's bank credit
facilities.
The 7.625% notes are not redeemable prior to December 1, 2009, except in
limited circumstances. After that time, they can be redeemed in whole or
part, at the rates indicated below:
December 1, 2009 103.813%
December 1, 2010 101.906%
December 1, 2011 and thereafter 100.000%
In November 2005, the Company and a wholly owned subsidiary of the
Company completed a tender offer and consent solicitation to amend the
Indenture relating to the 9.90% notes. The Company and a wholly owned
subsidiary of the Company paid 107.195% plus accrued and unpaid interest
for the US$158.25 million 9.90% notes tendered by the note holders.
Information related to the tender costs is included in Note 8.
The remaining US$6.75 million of 9.90% notes are not redeemable prior to
May 15, 2006. After that time, they can be redeemed in whole or part, at
the rates indicated below:
May 15, 2006 104.950%
May 15, 2007 102.475%
May 15, 2008 and thereafter 100.000%
7. Interest and finance charges
Amounts charged to expense during the year ended are as follows:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Interest on bank debt, net $ 11,520 $ 9,662 $ 6,611
Interest on senior term notes 20,912 21,281 21,711
Finance charges 2,519 2,790 2,273
------------ ------------ ------------
Total $ 34,951 $ 33,733 $ 30,595
------------ ------------ ------------
------------ ------------ ------------
Finance charges include the amortization of deferred charges and other
current year expenses.
8. Deferred financing charges and other
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of deferred financing charges associated
with the issue of senior term notes:
Years ended December 31, 2005 2004
------------ ------------
Deferred financing charges and other,
beginning of year $ 9,729 $ 11,532
Issue costs on 7.625% Senior Notes 12,670 -
Pro-rata reduction on repayment of
9.90% Senior Notes (7,053) -
Amortization expense (2,119) (2,133)
Other (71) 330
------------ ------------
Deferred financing charges and other,
end of year $ 13,156 $ 9,729
------------ ------------
------------ ------------
Costs incurred on the tender for the 9.90% senior term notes in 2005 were
as follows:
Premium payment $ 7,814
Consent solicitation fee 5,883
Pro-rata reduction of deferred financing
charges on repayment of 9.90% Senior Notes 7,053
------------
Total $ 20,750
------------
------------
9. Foreign exchange (gain) loss
Amounts charged to foreign exchange (gain) loss during the year ended
were as follows:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Foreign exchange gain on
translation of US$ debt $ (7,808) $ (14,652) $ (47,388)
Other foreign exchange loss 455 21 20
------------ ------------ ------------
Total $ (7,353) $ (14,631) $ (47,368)
------------ ------------ ------------
------------ ------------ ------------
10. Asset retirement obligations
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligations associated with the
retirement of oil and natural gas assets:
As at December 31, 2005 2004
------------ ------------
Asset retirement obligations, beginning of year $ 18,006 $ 17,329
Liabilities incurred 5,218 3,357
Liabilities settled and disposed (1,275) (4,350)
Accretion expense 1,975 1,670
Revision of estimates (3,154) -
------------ ------------
Asset retirement obligations, end of year $ 20,770 $ 18,006
------------ ------------
------------ ------------
The total undiscounted amount of estimated cash flows required to settle
the obligations was $185.8 million (2004 - $148.9 million), which has
been discounted using a credit-adjusted risk free rate of 10.7% (2004 -
10.8%). The majority of these obligations are not expected to be settled
for several years or decades into the future. Settlements will be funded
from general Company resources at the time of retirement and removal.
11. Capital stock
a) Authorized
The Company is authorized to issue an unlimited number of common
shares and an unlimited number of preferred shares, issuable in
series.
b) Issued and outstanding
As at December 31, 2005 2004
--------------------- ---------------------
Number Number
of of
Shares Amount Shares Amount
---------- ---------- ---------- ----------
(000s) (000s)
Common shares outstanding,
beginning of year 117,354 $ 135,526 116,423 $ 131,577
Shares issued for cash,
net 7,500 87,294 - -
Shares issued for
property - - 110 875
Shares issued under
stock option plan 2,926 4,424 1,271 3,589
Shares repurchased (517) (800) (450) (515)
---------- ---------- ---------- ----------
Common shares outstanding,
end of year 127,263 $ 226,444 117,354 $ 135,526
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
In February 2005, the Company issued 7,500,000 common shares for
gross proceeds of $90.0 million before underwriters' fees and issue
expenses of $4.1 million.
The Company maintains a Normal Course Issuer Bid program on an annual
basis. Under the current bid, the Company may purchase for
cancellation up to 6,000,000 of its common shares, representing
approximately 5.0% of the issued and outstanding common shares at the
time the bid received regulatory approval.
During the year, the Company purchased for cancellation 516,600
common shares at an average price of $11.84 per share (2004 - 450,100
common shares at an average price of $8.90 per share) pursuant to the
normal course issuer bid. The excess of the purchase price over book
value has been charged to retained earnings.
c) Shareholder rights plan
The Company has a shareholder rights plan (the "Plan") to ensure all
shareholders are treated fairly in the event of a take-over offer or
other acquisition of control of the Company.
Pursuant to the Plan, the Board of Directors authorized and declared
the distribution of one Right in respect of each common share
outstanding. In the event that an acquisition of 20% or more of the
Company's shares is completed and the acquisition is not a permitted
bid, as defined by the Plan, each Right will permit the holder to
acquire common shares at a 50% discount to the market price at that
time.
12. Stock-based compensation plans
a) Stock option plan
The Company has implemented a stock option plan for Directors,
Officers, and employees. The exercise price of each option
approximates the market price for the common shares on the date the
option was granted. Options granted under the plan before June 1,
2003 are generally fully exercisable after four years and expire ten
years after the grant date. Options granted under the plan after
June 1, 2003 are generally fully exercisable after four years and
expire five years after the grant date.
The following tables summarize the information relating to stock
options:
As at December 31, 2005 2004
--------------------- ---------------------
Weighted Weighted
average average
Stock exercise Stock exercise
options price options price
---------- ---------- ---------- ----------
(000s) (000s)
Outstanding, beginning
of year 11,655 $3.51 10,672 $2.54
Granted 2,930 $11.89 2,549 $7.34
Exercised (2,926) $1.32 (1,271) $2.56
Cancelled (213) $8.30 (295) $5.26
---------- ---------- ---------- ----------
Outstanding, end of year 11,446 $6.13 11,655 $3.51
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Exercisable, end of year 6,219 $3.38 7,812 $2.19
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
The range of exercise prices of stock options outstanding and
exercisable at December 31, 2005 were as follows:
Outstanding Options Exercisable Options
----------------------------------- -----------------------
Weighted
average Weighted Weighted
Range of Number of remaining average Number of average
exercise options contractual exercise options exercise
prices outstanding life (years) price outstanding price
----------- ------------- ----------- ----------- ----------- -----------
(000s) (000s)
$0.80 - $2.99 2,644 2.7 $1.55 2,644 $1.55
$3.00 - $3.99 1,509 5.3 $3.47 1,279 $3.40
$4.00 - $4.99 1,598 6.1 $4.30 1,215 $4.24
$5.00 - $6.99 1,188 2.9 $5.87 597 $5.88
$7.00 - $9.99 1,485 3.4 $7.62 427 $7.62
$10.00 - $12.99 2,690 4.2 $11.58 42 $10.60
$13.00 - $17.38 332 4.7 $13.70 15 $13.44
----------- ----------- ----------- ----------- -----------
11,446 4.1 $6.13 6,219 $3.38
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
The Company has recorded stock-based compensation expense in the
consolidated statement of earnings for stock options granted to
Directors, Officers, and employees after January 1, 2003 using the
fair value method.
The fair value of each option granted is estimated on the date of
grant using the Black-Scholes option pricing model with weighted
average assumptions for grants as follows:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Weighted average fair value
of options granted $5.45 $3.70 $3.01
Risk-free interest rate 3.6% 3.9% 4.3%
Expected life (years) 5.0 5.0 6.1
Expected volatility 43.9% 49.6% 56.0%
The following table presents the reconciliation of contributed
surplus with respect to stock-based compensation:
As at December 31, 2005 2004
------------ ------------
Contributed surplus, beginning of year $ 3,840 $ 760
Stock-based compensation expense 5,903 3,410
Stock options exercised (570) (330)
------------ ------------
Contributed surplus, end of year $ 9,173 $ 3,840
------------ ------------
------------ ------------
The Company has not recorded stock-based compensation expense in the
consolidated statement of earnings related to stock options granted
prior to 2003. If the Company had applied the fair value method to
options granted prior to 2003, the effect would have been as follows:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Reduction in net earnings $1,007 $1,545 $2,317
Reduction in net earnings
per common share -
basic and diluted $0.01 $0.01 $0.02
b) Share appreciation rights plan
CICA Handbook section 3870 requires recognition of compensation costs
with respect to changes in the intrinsic value for the variable
component of fixed share appreciation rights ("SARs"). During the
years ended December 31, 2005 and 2004, there were no significant
compensation costs related to the outstanding variable component of
these SARs, (2003 - $33,000). The liability related to the variable
component of these SARs amounts to $1.4 million, which is included in
accounts payable as at December 31, 2005 (2004 - $1.7 million). All
outstanding SARs having a variable component expire at various times
through 2011.
13. Per share amounts
The following table summarizes the common shares used in calculating net
earnings per common share:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
(000s) (000s) (000s)
Weighted average common shares
outstanding - basic 125,627 117,244 116,267
Effect of stock options 6,040 6,789 5,856
------------ ------------ ------------
Weighted average common shares
outstanding - diluted 131,667 124,033 122,123
------------ ------------ ------------
------------ ------------ ------------
In calculating diluted earnings per common share for the year ended
December 31, 2005, the Company excluded 331,800 options (2004 - 288,000,
2003 - 615,100) as the exercise price was greater than the average market
price of its common shares in those years.
14. Defined benefit pension plan
Substantially all of the employees of MPP are enrolled in a co-sponsored,
defined benefit pension plan. The Company does not have a pension plan
for other employees. Information relating to the MPP retirement plan is
outlined below:
As at December 31, 2005 2004
------------ ------------
Accrued benefit obligation $ 7,562 $ 5,855
------------ ------------
Fair value of plan assets $ 5,839 $ 5,221
------------ ------------
Funded status
Plan assets less than benefit obligation $ (1,723) $ (634)
Unamortized net actuarial loss (gain) 891 (269)
Unamortized past service costs 862 933
------------ ------------
Accrued benefit asset, included in deferred
financing charges and other
$ 30 $ 30
------------ ------------
------------ ------------
Economic assumptions used to determine benefit obligation and periodic
expense were:
Years ended December 31, 2005 2004
------------ ------------
Discount rate 5.0% 6.3%
Expected rate of return on assets 7.0% 7.0%
Rate of compensation increase 3.5% 4.5%
Average remaining service period of
covered employees 15 years 15 years
Actuarial evaluations are required every three years, the next evaluation
being January 1, 2006.
Pension expense, included in MPP operating costs, is as follows:
Years ended December 31, 2005 2004
------------ ------------
Current service cost $ 232 $ 190
Interest on accrued benefit obligation 372 336
Interest on assets (364) (333)
Amortization on past service cost 69 67
------------ ------------
Pension expense, included in general and
administrative expense $ 309 $ 260
------------ ------------
------------ ------------
MPP expects to contribute $340 thousand to the plan in 2006.
Contributions by the participants to the pension plan were $75 thousand
for the year ended December 31, 2005.
15. Income taxes
a) The following table reconciles income taxes calculated at the
Canadian statutory rate with actual income taxes:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Earnings before taxes and
non-controlling interest $ 145,247 $ 103,234 $ 142,093
------------ ------------ ------------
Canadian statutory rate 37.6% 38.6% 40.6%
Expected income taxes $ 54,613 $ 39,848 $ 57,690
Effect on taxes resulting from:
Non-deductible Crown charges 15,061 17,611 23,922
Resource allowance (11,980) (13,535) (16,485)
Non-deductible stock-based
compensation 2,221 1,316 309
Federal capital tax 1,896 2,526 2,497
Effect of tax rate changes (5,764) (8,359) (37,130)
Non-taxable portion of
capital items - (2,831) (8,202)
Other 1,341 (393) 722
------------ ------------ ------------
Provision for income taxes $ 57,388 $ 36,183 $ 23,323
------------ ------------ ------------
------------ ------------ ------------
Current
Income taxes $ 3,175 $ 225 $ 785
Federal capital taxes 1,896 2,526 2,497
Future 52,317 33,432 20,041
------------ ------------ ------------
$ 57,388 $ 36,183 $ 23,323
------------ ------------ ------------
------------ ------------ ------------
Effective tax rate 39.5% 35.0% 16.4%
------------ ------------ ------------
------------ ------------ ------------
A significant portion of the Company's taxable income is generated by
a partnership. Income taxes are incurred on the majority of the
partnership's taxable income in the year following its inclusion in
the Company's consolidated net earnings. Current income tax is
dependent upon the amount of capital expenditures incurred and the
method of deployment.
b) The net future income tax liability is comprised of:
As at December 31, 2005 2004
------------ ------------
Future income tax liabilities
Property and equipment in excess of
tax values $ 232,258 $ 199,931
Timing of partnership items 93,532 67,089
Foreign exchange gain on long-term debt 11,466 10,169
Future income tax assets
Attributed Canadian royalty income (8,830) (9,015)
Asset retirement obligations (6,984) (6,057)
Other (9,325) (921)
------------ ------------
Net future income tax liability $ 312,117 $ 261,196
------------ ------------
------------ ------------
16. Financial instruments
a) Derivative financial instruments and risk management activities
The Company is exposed to risks from fluctuations in commodity
prices, interest rates, and Canada/US currency exchange rates. The
Company utilizes various derivative financial instruments for
non-trading purposes to manage and mitigate its exposure to these
risks. Effective January 1, 2004, the Company elected to account for
all derivative financial instruments using the mark-to-market method.
Risk management activities during the periods, utilizing derivative
instruments, relate to commodity price hedges and cross currency
interest rate swap arrangements and are summarized below:
i) Commodity price hedges
The Company enters into hedge transactions relating to crude oil and
natural gas prices to mitigate volatility in commodity prices and the
resulting impact on cash flow. The contracts entered into are forward
transactions providing the Company with a range of prices on the
commodities sold. Outstanding hedge contracts at December 31, 2005
are:
Daily Mark-
Notional Average to-Market
Commodity Term Volume Price gain (loss)
--------- ---- -------- ------- -----------
Natural gas
Nov. 1/05 - $8.70 -
Collar Mar. 31/06 38,095 mcf $12.74/mcf $ (929)
Nov. 1/05 -
Fixed Mar. 31/06 9,524 mcf $9.03/mcf (1,735)
Apr. 1/06 - $8.73/mcf -
Collar Oct. 31/06 42,857 mcf $12.87/mcf (929)
-----------
(3,593)
Crude Oil
Jan. 1 - US$55.00 -
Collar Dec. 31/06 3,000 bbls $75.17/bbl 443
-----------
Unrealized risk management loss $ (3,150)
-----------
-----------
The Company has not entered into any additional contracts subsequent
to December 31, 2005.
At December 31, 2004 the mark-to-market valuation of commodity
contracts resulted in a $2.0 million unrealized risk management
asset.
ii) Deferred risk management loss
As at January 1, 2004, the Company elected not to designate any of
its risk management activities as accounting hedges and accordingly
accounts for all derivative instruments using the mark-to-market
method. As a result, on January 1, 2004, the Company recorded a
liability and a deferred risk management loss of $10.9 million
relating to then outstanding commodity hedges and the interest rate
swap. During the year ended December 31, 2005, $1.6 million (2004 -
$3.6 million) of the deferred loss was charged to earnings. The
remaining balance of $5.6 million at December 31, 2005 (2004 -
$7.3 million) relates to the interest rate swap and will be charged
to earnings in annual amounts of $1.6 million until eliminated in
2009.
iii) Cross currency interest rate swap
Concurrent with the closing of the 9.90% senior notes offering in
2002, the Company entered into interest rate swap arrangements with
its banking syndicate that convert fixed rate U.S. dollar denominated
interest obligations into floating rate Canadian dollar denominated
interest obligations. This arrangement resulted in an effective
interest rate of 7.63% during period ended December 31, 2005 (2004 -
7.24%, 2003 - 7.85%) net of gains realized. On purchase of the
majority of the 9.90% senior notes in November 2005, the Company
elected not to collapse the cross currency interest rate swap and
incur the associated costs of approximately $12.2 million.
Accordingly, the swap remains outstanding and at December 31, 2005,
the Company valued the liability relating to future unrealized losses
on the swap arrangements to be $14.8 million (2004 - $11.4 million)
on a mark-to-market basis.
iv) Risk management (gains) losses
Risk management (gains) and losses recognized during the periods
relating to the above are summarized below:
Commodity Interest
Year ended December 31, 2005 Contracts Rate Swap Total
------------ ------------ ------------
Unrealized
Amortization of deferred
loss $ - $ 1,642 $ 1,642
Change in fair value 5,136 3,393 8,529
------------ ------------ ------------
5,136 5,035 10,171
Realized
Cash settlements 9,663 (532) 9,131
------------ ------------ ------------
Total loss $ 14,799 $ 4,503 $ 19,302
------------ ------------ ------------
------------ ------------ ------------
Commodity Interest
Year ended December 31, 2004 Contracts Rate Swap Total
------------ ------------ ------------
Unrealized
Amortization of deferred
loss $ 2,001 $ 1,642 $ 3,643
Change in fair value (3,986) 2,522 (1,464)
------------ ------------ ------------
(1,985) 4,164 2,179
Realized
Cash settlements 9,151 (2,522) 6,629
------------ ------------ ------------
Total loss $ 7,166 $ 1,642 $ 8,808
------------ ------------ ------------
------------ ------------ ------------
Risk management loss of $4.1 million for year ended December 31, 2003
reflects realized losses recognized under hedge accounting.
b) Other financial instruments and risk
i) Credit risk management
Accounts receivable include amounts receivable for oil and natural
gas sales which are generally made to large credit worthy purchasers
and amounts receivable from joint venture partners which are
recoverable from production. Accordingly, the Company views credit
risks on these amounts as low.
The Company is exposed to losses in the event of non-performance by
counter-parties to financial instruments. The Company deals with
major institutions and believes these risks are minimal.
ii) Fair value of financial assets and liabilities
Other than its senior term notes, the fair values of the Company's
financial assets and liabilities that are included in the Company's
consolidated balance sheet as at December 31, 2005, approximate their
carrying value. The estimated fair value of senior term notes was
$361.1 million as at December 31, 2005 (2004 - $218.5 million) based
upon market information.
iii) Foreign currency risk management
The Company is exposed to fluctuations in the exchange rate between
the Canadian dollar and the U.S. dollar. Crude oil and to a certain
extent natural gas prices are based upon reference prices denominated
in U.S. dollars, while the majority of the Company's expenses are
denominated in Canadian dollars. When appropriate, the Company enters
into agreements to fix the exchange rate of Canadian dollars to U.S.
dollars in order to manage the risk. During 2003, a gain of
$2.5 million was realized and included in revenue. Subsequent to
December 31, 2005 the Company entered into the following forward
contracts:
Notional Exchange
Foreign Currency Term Amount Rate
---------------- ---- -------- --------
Currency forward Jan. 1 - Dec. 31/06 US$55,000/day 1.1530
Currency forward Jan. 1 - Dec. 31/06 US$55,000/day 1.1630
17. Cash flow
Changes in non-cash working capital items increased (decreased) cash as
follows:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Accounts receivable and other $ (17,371) $ (20,176) $ (16,593)
Accounts payable 78,385 39,598 23,635
Taxes payable (301) (2,526) 1,541
------------ ------------ ------------
$ 60,713 $ 16,896 $ 8,583
------------ ------------ ------------
------------ ------------ ------------
Net change in non-cash
working capital
Relating to:
Operating activities $ 8,441 $ (12,594) $ 1,318
Financing activities (1,829) 324 (1,387)
Investing activities 54,101 29,166 8,652
------------ ------------ ------------
$ 60,713 $ 16,896 $ 8,583
------------ ------------ ------------
------------ ------------ ------------
Amounts paid during the year relating to interest expense and capital
taxes were as follows:
Years ended December 31, 2005 2004 2003
------------ ------------ ------------
Interest paid $ 31,444 $ 28,604 $ 26,923
------------ ------------ ------------
------------ ------------ ------------
Current income taxes paid $ 4,101 $ 4,952 $ 1,485
------------ ------------ ------------
------------ ------------ ------------
18. Commitments and contingent liabilities
a) Commitments
The Company has committed to certain payments over the next five
years, as follows:
2006 2007 2008 2009 2010
-------- --------- --------- --------- ---------
Operating leases $ 11,277 $ 4,809 $ 2,609 $ - $ -
Office rent 1,356 249 - - -
MPP partnership
distributions 9,172 9,172 9,172 3,057 -
9.90% senior notes - - - 7,870 -
Other 52 - - - -
-------- --------- --------- --------- ---------
$ 21,857 $ 14,230 $ 11,781 $ 10,927 $ -
-------- --------- --------- --------- ---------
-------- --------- --------- --------- ---------
b) Legal proceedings
The Company is involved in various legal claims associated with
normal operations. These claims, although unresolved at the current
time, in management's opinion, are minor in nature and are not
expected to have a material impact on the financial position or
results of operations of the Company.
FORWARD LOOKING STATEMENTS
Certain information regarding the Company contained herein constitutes
forward-looking statements under the meaning of applicable securities laws,
including the United States Private Securities Litigation Reform Act of 1995.
Forward-looking statements include estimates, plans, expectations, opinions,
forecasts, projections, guidance, or other statements that are not statements
of fact, including statements regarding (i) reserve estimates, net present
value of reserves cash flow, 2006 Guidance and (ii) other risks and
uncertainties described from time to time in the reports and filings made by
Compton with securities regulatory authorities. Although Compton believes that
the expectations reflected in such forward-looking statements are reasonable,
it can give no assurance that such expectations will prove to have been
correct. There are many factors that could cause forward-looking statements
not to be correct, including risks and uncertainties inherent in the Company
business. These risks include, but are not limited to: crude oil and natural
gas price volatility, exchange rate fluctuations, availability of services and
supplies, operating hazards and mechanical failures, uncertainties in the
estimates of reserves and in projection of future rates of production and
timing of development expenditures, general economic conditions, and the
actions or inactions of third-party operators. Compton may, as considered
necessary in the circumstances, update or revise forward looking information,
whether as a result of new information, future events, or otherwise. The
Company's forward-looking statements are expressly qualified in their
entirety by this cautionary statement.
CONFERENCE CALL
Compton will be conducting a conference call and audio webcast Tuesday,
March 21, 2006 at 9:30 a.m. Mountain Standard Time (11:30 a.m. EST) to discuss
the Company's 2005 fourth quarter and 2005 annual financial and operating
results. To participate in the conference call, please contact the Conference
Operator at 9:20 a.m. (MST), ten minutes prior to the call.
Conference Operator Dial-in Number: Toll-Free 1-800-814-4861
Local Toronto: 1-416-644-3424
Audio webcast URL:
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1371260
The audio replay will be available two hours after the conclusion of the
conference call and will be accessible until Tuesday, March 28, 2006. Callers
may dial toll-free 1-877-289-8525 and enter access code 21176659 (followed by
the pound key).
Compton Petroleum Corporation is a Calgary-based public company actively
engaged in the exploration, development, and production of natural gas,
natural gas liquids, and crude oil in the Western Canada Sedimentary Basin.
Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT
and on the New York Stock Exchange under the symbol CMZ.
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