CALGARY, March 25 /PRNewswire-FirstCall/ - Compton Petroleum Corporation
(TSX - CMT, NYSE - CMZ) is pleased to report its financial and operating
results for the year and quarter ended December 31, 2007.
2007 HIGHLIGHTS
- Reserve additions, proved plus probable 22 million boe (net of
production & divestments),
9% increase
- Reserve value, before tax $3.4 billion, 8% DCF
- FD&A costs, $/boe
Including change in future capital $12.86 proved plus probable
$23.36 proved
- 2007 Average production 31,326 boe/d
- Production replacement 1.9 times
- Adjusted cash flow from operations $196 million
Drilling Results
During 2007 Compton successfully completed a 322 well drilling program,
with a 97% success rate. Of the 322 wells drilled in 2007, 91% were classified
as development wells and nine percent were classified as exploratory wells,
compared to 84% and 16% respectively in 2006. The higher percentage of
development wells in the current year reflects the increasing success of our
oil and gas plays.
Of particular note was our very successful horizontal drilling program
targeting the Rock Creek formation in the Niton area of central Alberta. We
completed a total of six horizontal natural gas wells utilizing multi-stage
frac technology with excellent results. As announced in our recent news
release of March 6, 2008 we are excited at the potential of applying this
technology to other core areas including the Basal Quartz at Hooker and the
Belly River in southern Alberta.
Dispositions and Acquisitions
We were also very active on the Acquisition and Divestment front during
2007. We pursued our strategy of divesting of non-focus assets and the
redeployment of the proceeds into our focus area natural gas plays. We closed
non-core property divestments, including our conventional light oil property
at Worsley, for total net proceeds of $303.1 million. We also added to our
core areas through a series of property acquisitions that totaled
approximately $73.7 million and completed two corporate acquisitions, Stylus
Energy Inc. and WIN Energy Corporation, that significantly expanded our
presence in southern Alberta and the Foothills at a total cost of $131.4
million.
Reserve Growth
Our 2008 activities resulted in strong reserve growth. We replaced 192% of
our 2007 production on a proved plus probable basis at very competitive
Finding, Development, and Acquisition costs ("FD&A") of $12.86/boe, including
change in future capital. We added 2.3 million boe of proved reserves and 22
million boe proved plus probable reserves, net of production and asset
divestitures. Asset divestitures during the year included total reserves of
12.2 million boe, of which 11.9 million boe were classified as proved
reserves.
Total proved plus probable reserves rose nine percent from the prior year
to 271 million boe and were valued before tax at $3.4 billion, based on eight
percent discounted cash flow. Total proved reserves at year end were 150
million boe. Proved producing reserves comprise 69% of total proved reserves.
Total proved reserves account for 55% of the proved plus probable reserves.
2007 proved plus probable reserves of 271 million boe equate to 2.10 boe
per common share outstanding, versus 1.93 boe per common share in 2006. During
the past five years, we have grown our reserve base at a 21% compound annual
growth rate.
Production, Revenue, and Adjusted Cash Flow From Operations
Overall average production, revenue, and adjusted cash flow from
operations for 2007 declined from 2006 levels primarily as a result of an
overall reduction in drilling, particularly during the first half of the year,
and natural declines and property divestments. During the last half of 2007,
activity increased appreciatively. We drilled a total of 238 wells during the
third and fourth quarters of 2007 and fourth quarter production averaged
32,646 boe/d, an increase of 7% over the third quarter.
2007 Objectives
A primary goal during 2007 was that of positioning the Company to execute
on its three year strategic plan to realize on the Company's large resource
potential through expanding drill programs. To this end, much was achieved in
2007 including:
- The continued strengthening of our technical and professional teams
necessary to manage expanded drilling programs,
- The testing of the applicability of advanced drilling and completion
technologies to our resource plays,
- The continued divestment of non-core properties and redeployment of
capital to our focus areas, and
- Developing internal systems and procedures to efficiently and cost
effectively manage larger drilling programs.
We are largely pleased with the result of our efforts in these areas and
look forward to 2008.
The following sections of this news release discuss in significant detail
our 2007 operational and financial results together with our plans for 2008
and beyond.
FINANCIAL SUMMARY
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Three Months Ended Dec. 31 Year Ended Dec. 31
($000s, except
per share
amounts) 2007 2006 % Change 2007 2006 % Change
-------------------------------------------------------------------------
Gross revenue $125,959 $130,289 -3% $500,987 $540,837 -7%
Adjusted cash
flow from
operations(1) $ 45,696 $ 55,263 -17% $196,194 $256,305 -23%
Per share
- basic $ 0.35 $ 0.43 -19% $ 1.52 $ 2.01 -24%
- diluted $ 0.35 $ 0.42 -17% $ 1.48 $ 1.92 -23%
Net earnings $ 50,457 ($10,037) 603% $129,266 $127,426 1%
Per share
- basic $ 0.39 ($ 0.08) 588% $ 1.00 $ 1.00 0%
- diluted $ 0.38 ($ 0.08) 588% $ 0.98 $ 0.95 3%
Adjusted net
earnings from
operations(2) $ (2,017) $ 11,822 -117% $ 21,286 $ 65,168 -67%
Capital
expenditures $385,532 $491,511 -22%
Corporate debt, net $871,403 $875,548 0%
Shareholders'
equity $869,956 $734,124 19%
Weighted
averages
shares (000s)
- basic 128,993 127,820
- diluted 132,539 133,626
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(1) Adjusted cash flow from operations is a non-GAAP term that represents
net earnings adjusted for non-cash items. We consider adjusted cash
flow from operations to be a key financial measure as it demonstrates
our ability to generate the cash flow necessary to fund future growth
through capital investment. Adjusted cash flow from operations may
not be comparable to similar measures presented by other companies.
(2) Adjusted net earnings from operations was referred to as Operating
Earnings in prior years.
OPERATING SUMMARY
-------------------------------------------------------------------------
Three Months Ended Dec. 31 Year Ended Dec. 31
(6:1 boe
conversion) 2007 2006 % Change 2007 2006 % Change
-------------------------------------------------------------------------
Average daily
production
Natural gas
(MMcf/d) 167 148 13% 145 142 2%
Liquids (light
oil & ngls)
(bbls/d) 4,818 8,600 -44% 7,166 9,516 -25%
Total oil
equivalent
(boe/d) 32,646 33,245 -2% 31,326 33,187 -6%
Average realized
prices
Natural gas
($/Mcf) $ 6.00 $ 6.48 -7% $ 6.33 $ 6.32 0%
Liquids ($/bbl) 77.60 50.18 55% 62.28 59.09 5%
Total oil
equivalent
($/boe) $ 41.94 $ 42.60 -1% $ 43.82 $ 44.65 -2%
Field operating
netback ($/boe) $ 23.93 $ 27.03 -11% $ 26.54 $ 28.17 -6%
Cash flow
netback ($/boe) $ 16.91 $ 19.38 -13% $ 18.25 $ 21.53 -15%
Undeveloped land
Gross acres 1,121,130 980,179 14%
Net acres 893,462 798,192 12%
Average working
interest 80% 81%
Reserves (Mboe)
Proved oil
equivalent 149,564 147,218 2%
Proved plus
probable oil
equivalent 270,819 248,755 9%
Proved plus
probable gas
equivalent, Tcfe 1.625 1.492
Proved reserve
life index (years) 13 12
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OPERATIONS
1. PROPERTY REVIEW
Compton engages in oil and gas exploration and development in the Western
Canada Sedimentary Basin of Alberta, Canada. Our focus is on the Deep Basin
portion of the Basin, which extends from Northwest Alberta and British
Columbia to the United States border. In this large geographical region, we
pursue two types of resource plays. A shallow gas resource play, targeting the
Plains Belly River and overlying Edmonton Horseshoe Canyon zones, and the
three deep gas plays that include the Basal Quartz sands at Hooker, the
Gething/Rock Creek sands at Niton and Caroline in central Alberta, and the
Foothills stacked, thrusted Upper Cretaceous Belly River play at Callum in the
south.
SHALLOW GAS
The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow gas
zones cover more than 1,200 sections of Compton held land in southern Alberta.
The entire 900 metre gas-charged section is comprised of multiple Belly River
sands, silts, shales, and coals, overlain by the Edmonton/Horseshoe Canyon
Coals that similarly include sands, silts, and shales. In 2007 we drilled a
total of 226 wells through the Edmonton Horseshoe Canyon Group targeting the
Belly River section. Going forward, we will focus on downspacing, development
drilling, and recompletions in order to establish a resource manufacturing and
processing model designed to maximize production.
Plains Belly River and Edmonton Coal Bed Methane
At December 31, 2007, we were producing approximately 55 mmcf/d from 630
Belly River and Edmonton coal bed methane wells. With 1,200 sections of land,
at four wells per section automatic downspacing, this translates to a
significant multi-year, low risk drilling inventory on which to grow our
company.
During 2007, we took full advantage of the four well per section reduced
spacing initiative for our Belly River drilling program. Wherever possible,
our shallow gas wells were drilled in batches in areas close to existing
infrastructure. This initiative enabled us to significantly reduce our 2007
spud to rig release and rig release to on-stream times to 2.8 days and 99
days, respectively. Drilling results at our southern Alberta Belly River play
were 100% successful in 2007, and we made particularly notable advances in the
Brant, south Hooker, Ghost Pine, and Vulcan areas. Using our 1,200 km(2) of
proprietary 3D seismic, coupled with detailed geological mapping, has allowed
us to model the Belly River sands for consistent, repeatable success.
At Brant, our 3-5-17-27W4M compressor station became fully operational in
November 2007, providing us the requisite horsepower needed to bring on eight
new 100% owned Belly River wells. These wells were producing a combined four
mmcf/d at year end. The average production rate of these wells is
approximately double the 30 day initial production rate of a typical Belly
River well. Our 2007 drilling targeted longer term producing wells such as
Compton Brant 00/07-05-017-27W4M/0 and Compton Silver 00/13-32-016-28W4M/2.
These two wells are producing 570 and 860 mcf/d, respectively. In 2008, we
will aggressively follow up similar trends into south Hooker and south Brant.
In the Ghost Pine area, we expanded our 15-11-30-23W4M compressor station
from eight to 12 mmcf/d in 2007. A total of 62 Belly River and Horseshoe
Canyon coal wells are currently producing 12 mmcf/d at Ghost Pine. We have 14
standing gas wells that are scheduled to be tied-in in the first quarter 2008.
We have recently reprocessed our 3D seismic in this area, and in 2008 we plan
to use this seismic to replicate the Ghost Pine Belly River gas well
02/07-10-030-23W4M, which had an initial production rate of 1,300 mcf/d, and
the 00/05-01-030-23W4/4 Coal Bed Methane gas well, which had an initial
production rate of 74 mcf/d.
Finally, further south in the Vulcan area, we placed five Belly River gas
wells drilled by Stylus Energy on production in late 2007. In aggregate, these
wells were placed on production at 2.2 mmcf/d. These wells are the
southernmost Belly River gas wells producing in Alberta.
Our total compression capacity for southern Alberta low pressure gas is 95
mmcf/d. Compton had 27,000 horsepower of installed compression dedicated to
the play installed and running at year end 2007.
In 2008, we plan to drill 275 Belly River wells, focusing specifically on
the top tier prospects identified by our technical teams. We have allocated
approximately $180 million in our budget to this area, with $5 million
ear-marked specifically to continue with identification of well locations and
licensing such that as industry conditions improve, we can readily ramp-up
activity. We estimate that roughly 40% of our 2008 Belly River wells drilled
in the latter part of the year will not come on production until early 2009
and will, as a result, take full advantage of the lower shallow gas royalty
rates effective for 2009.
Our 2008 southern Alberta plans also include an eight well per section
pilot project. Additionally and following on our Deep Basin deeper target
success, we will use extended reach drilling with multi-stage fracturing
techniques.
DEEP BASIN
Compton has two Deep Basin gas plays: the Basal Quartz sands at Hooker and
the Gething/Rock Creek sands at Niton and Caroline in central Alberta.
Southern Alberta: Hooker
Discovered by Compton in 1999, the Basal Quartz sandstone pool at Hooker
is the southern Alberta extension of the Lower Cretaceous Deep Basin gas
trend. Current production extends over five townships, and in 2007, we drilled
10 wells at Hooker.
In March 2008, Compton successfully completed the first horizontal well in
southern Alberta at Niton targeting the Basal Quartz formation utilizing
multi-stage fracturing technology. The well at 9-17-17-29W4 was drilled with a
700 metre horizontal leg that flow tested at six mmcf/d. It is scheduled to be
tied-in during mid March. A second horizontal well is currently drilling at
15-30-16-29W4 and 15 follow-up locations have been identified.
While Compton has been employing horizontal drilling and multi-stage frac
technology in the Niton area in central Alberta with good success, the 9-17
well at Hooker is of major significance in that it establishes that this
technology is applicable to the development of the Hooker Basal Quartz play in
southern Alberta. To date the Hooker play has been developed through drilling
one to two vertical wells per section. Reservoir modeling indicates up to four
vertical wells per section may be necessary to fully develop the play. A
horizontal well could replace two to three vertical wells, eliminating the
need for extensive down-spacing in the area
Central Alberta: Niton and Caroline
The Niton area in central Alberta, 150 miles west of Edmonton, is also in
the Alberta Deep Basin fairway. Our main targets are the Jurassic Rock Creek
and Cretaceous Gething, analogous to the Hooker pool in southern Alberta.
Proprietary exploration, development, and operational knowledge gained in
southern Alberta has resulted in accelerated growth of this core area. In
2007, we drilled 35 wells at Niton and Caroline.
We experienced significant drilling success with our Rock Creek horizontal
gas well program at Niton in 2007. The average cost to drill and complete a
Niton horizontal gas well is $4.5 million, or roughly two times the cost of a
comparative vertical Rock Creek gas well. With a 30 day initial production
average of 5.0 mmcfe/d per well, horizontal wells produce about four times
that of a comparative vertical well. Compton's average horizontal gas well is
2,600 meters deep and has a 1,000 meter open-hole section. Multiple open-hole
packers are set within the horizontal section and three to four staged
hydraulic fractures are completed. At year end, we had eight Niton horizontal
Rock Creek wells on production. Six of these wells were gas wells and two were
oil wells, with the gas wells producing approximately 16.2 mmcfe/d in
aggregate and the two oil wells were producing a combined 153 boe/d.
To date in 2008 we have drilled two additional horizontal wells at Niton
and a third well is currently drilling. The first well tested 3.0 mmcf/d and
most recently, the well at 4-27-52-17W5 completed at the end of February is
currently flow testing at 11 mmcf/d. The third well is scheduled to be
completed later this month. Production from these wells will be facility
constrained pending the completion of additional compression and gathering
lines. This work is currently underway and is scheduled for completion by the
end of March barring any delay resulting from an early spring break-up. A
total of 10 additional locations are planned for this area in 2008.
In 2008, Compton's Niton budget plans for 15 horizontal wells using this
multi-stage frac technology. Last year's focus by a number of producers,
including Compton, targeted the Compton discovered Edson Rock Creek P pool.
Following the Niton Rock Creek successes, Compton posted and acquired a 100%
interest in 12 sections of mineral rights on a second Rock Creek discovery.
Late in 2007, Compton drilled Edson 00/01-31-052-16W5M/0 discovery well on
this 100% block of land. This well was successful and is currently producing
at 3.5 mmcfe/d.
All major compression equipment has been ordered for this play and we are
currently drilling the third and fourth horizontal wells in this play. Pending
break-up and drilling success, we plan to have eight 100% working interest
horizontal wells on stream by the end of May 2008.
For 2008 we have allocated approximately $135 million or 33% of our total
planned capital expenditures to our central Alberta resource play. We plan to
drill 48 wells in this area, with 13 of these wells slated to be horizontal.
The 2008 plan is to continue to aggressively drill similar Rock Creek plays
and to transfer this multi-staged horizontal fracture technology to other
Compton operated deep basin gas plays throughout Alberta.
FOOTHILLS
Our Callum/Cowley property consists of a series of over pressured,
thrusted, low permeability Belly River sands in the foothills of southern
Alberta. A total of 15 exploratory wells have been drilled over the life of
the play. Based on our initial detailed geological, geophysical, and
engineering analysis of seismic, cores, well logs, and 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.
In 2007, we drilled a horizontal well targeting a specific group of sands
plus intersecting mapped fracture systems. The well came on production at
approximately 6.5 mmcf/d, without stimulation. Further reservoir and
completion work is planned on this well bore in 2008.
During the fourth quarter of 2007, we acquired WIN Energy Inc., a junior
oil and gas company that was active on lands immediately adjacent to ours.
This $30 million acquisition added 68,000 gross (53,600 net) acres of
undeveloped land in the Cowley area in southern Alberta prospective for the
thrusted Belly River trend. As at December 31, 2007, we held approximately 239
net sections of high impact exploration lands at Callum and Cowley.
With our acquisition of WIN Energy Inc., we also acquired 55 kilometres of
2D seismic and a new 36 square mile 3D seismic survey surrounding currently
producing wells. Using this seismic data, we plan to replicate our recent
horizontal well success at Callum in the Cowley area. In 2008, we plan to
drill four extended reach horizontal wells. These wells will be oriented to
intersect the maximum number of natural fractures in the foothills gas play.
Each of these horizontal wells will use multi-stage fracturing techniques and
they will be drilled from existing pads to minimize our environmental impact.
We plan to drill a total of nine wells in the Callum and Cowley area in 2008.
Compton treats the southern Alberta Foothills region as a unique
environmental eco- system. In conjunction with a number of southern Alberta
ranching operations, we are completing a rangeland health assessment that
addresses optimal ways to restore these systems to their natural state. This
includes funding of studies on native rough fescue grasses by the University
of Alberta, as well as working closely with both industry and landowner work
groups. Surface impact on all proposed wells will be minimized by using
existing drill pads or by selecting surface areas on sites previously
disturbed by the agriculture industry.
OPERATING RESULTS
UNDEVELOPED LAND
In 2007, we continued to build and maintain a dominant land position in
our core areas. The Company's total net land inventory increased 15% in 2007,
with acquisitions occurring primarily in the southern and central Alberta core
areas. Net undeveloped land increased 12% from the prior year.
Land Summary
-------------------------------------------------------------------------
Undeveloped Acres Total Acres
Area Gross Net Gross Net
-------------------------------------------------------------------------
Southern Alberta 576,253 537,631 1,058,145 941,972
Central Alberta 311,835 225,437 692,453 399,042
Peace River Arch 60,660 35,969 128,980 67,195
Northern Alberta 143,840 87,345 226,210 122,876
Other 28,542 7,080 63,149 11,750
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December 31, 2007 total 1,121,130 893,462 2,168,937 1,542,835
-------------------------------------------------------------------------
December 31, 2006 total 980,179 798,192 1,838,863 1,339,481
-------------------------------------------------------------------------
During 2008, we plan to continue to invest in the future and expand in our
core areas. Our 2008 budget includes $28 million directed towards land
acquisitions and seismic surveys in our major operating areas.
DRILLING ACTIVITY
We drilled 322 gross (266 net) wells in 2007 with a 97% success rate,
compared with 342 gross (274 net) wells in 2006.
Of the 322 wells drilled in 2007, 91% were classified as development wells
and nine percent were classified as exploratory wells, compared to 84% and 16%
respectively in 2006. The higher percentage of development wells in the
current year reflects the increasing maturity of our oil and gas plays.
Drilling Summary
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Natural
Years ended December 31, Gas Oil D&A Total Net Success
-------------------------------------------------------------------------
Southern Alberta 236 - 1 237 208 100%
Central Alberta 37 8 6 51 36 88%
Peace River Arch 3 17 3 23 13 87%
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Standing, cased wells 11 9
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2007 Total 322 266 97%
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2006 Total 266 56 20 342 274
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RESERVES
Netherland, Sewell & Associates Inc. ("NSAI"), independent reserve
evaluators, have completed an evaluation of 96% of Compton's petroleum and
natural gas reserves in accordance with National Instrument 51-101. The
remaining four percent of the Company's reserves have been evaluated
internally.
As required by National Instrument 51-101 "Standards of Disclosure for Oil
and Gas Activities" ("NI 51-101"), Compton filed Form 51-101 F1 as part of its
Annual Information Form ("AIF"). The AIF is considered comprehensive. Certain
information has been summarized below regarding the Company's operations. All
such information is consistent with the Form NI 51-101 F1 filing. Compton's
extended disclosure contained in the AIF is available on both the SEDAR
website and Compton's website.
i) Summary of Estimated Reserve Volumes - Forecast Prices and Costs(1)
-------------------------------------------------------------------------
Crude Oil Natural Gas NGLs
Gross Net Gross Net Gross Net
As at December 31, 2007 (Mbbl) (Mbbl) (Bcf) (Bcf) (Mbbl) (Mbbl)
-------------------------------------------------------------------------
Proved
Developed producing 9,015 8,501 502 411 9,182 6,498
Developed non-producing 222 197 55 45 1,079 749
Undeveloped 1,695 1,502 188 154 2,100 1,432
-------------------------------------------------------------------------
Total proved 10,933 10,199 745 610 12,362 8,679
Probable 6,495 5,842 625 510 9,820 6,879
-------------------------------------------------------------------------
Total proved plus
probable 17,427 16,042 1,369 1,120 22,182 15,558
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006 total proved
plus probable 29,233 26,213 1,189 984 19,068 13,761
-------------------------------------------------------------------------
----------------------------------------------------------
Sulphur Total
Gross Net Gross Net
As at December 31, 2007 (Mlt) (Mlt) (Mboe) (Mboe)
----------------------------------------------------------
Proved
Developed producing 1,968 1,674 103,884 85,205
Developed non-producing 66 55 10,464 8,559
Undeveloped 149 124 35,216 28,710
----------------------------------------------------------
Total proved 2,183 1,853 149,564 122,474
Probable 839 711 121,255 98,391
----------------------------------------------------------
Total proved plus
probable 3,022 2,563 270,819 220,865
----------------------------------------------------------
----------------------------------------------------------
2006 total proved
plus probable 2,271 1,975 248,755 205,895
----------------------------------------------------------
(1) Numbers may not add due to rounding.
In 2007, we added 22 MMboe, after production, to our proved plus probable
reserves primarily through the drill bit. Total proved plus probable reserves
increased nine percent from the prior year to 271 MMboe. Year end 2007
reserves do not include any reserves associated with our light oil asset at
Worsley, which was sold at the end of the third quarter of 2007.
Our total proved reserve base is comprised of 84% natural gas and 16%
liquids. Proved producing reserves comprise 69% of total proved reserves,
while total proved reserves account for 55% of the proved plus probable
reserves. We have a 13 year proved and a 23 year proved plus probable reserve
life index.
ii) Net Present Value of Reserves - Forecast Prices and Costs(1)
-------------------------------------------------------------------------
Future net revenue before income
taxes(1) discounted at a rate of
----------------------------------
($millions) 0% 8% 10%
-------------------------------------------------------------------------
Proved
Producing $2,872 $1,453 $1,304
Non-producing 383 183 160
Undeveloped 1,020 416 345
-------------------------------------------------------------------------
Total proved $4,275 $2,051 $1,809
Probable 3,800 1,356 1,109
-------------------------------------------------------------------------
2007 Total proved plus probable $8,075 $3,406 $2,919
-------------------------------------------------------------------------
2006 proved plus probable $7,633 $3,312 $2,845
-------------------------------------------------------------------------
(1) Pricing assumptions are the average of four major Canadian oil and
gas evaluation firms. Numbers may not add due to rounding.
Future net revenues are calculated based upon estimated revenue less
royalties, operating costs, future development costs, and well abandonment
costs. Estimated income taxes have not been deducted. The net present value
should not be considered the current market value of our reserves or the costs
that would be incurred to obtain equivalent reserves.
iii) Reserve Reconciliation (before royalties) -- Forecast Prices and
Costs (1)
-------------------------------------------------------------------------
Crude oil, Ngls, &
Sulphur Natural Gas
-----------------------------------------
Proved Probable Proved Probable
(Mbbl) (Mbbl) (Bcf) (Bcf)
-------------------------------------------------------------------------
December 31, 2006 32,745 17,827 687 502
Extensions, improved recovery,
& discoveries 1,460 1,770 60 113
Technical Revisions 2,254 -3,377 14 -39
Acquisitions 1,386 948 49 50
Dispositions -9,753 -14 -13 -1
Production -2,616 0 -53 0
-------------------------------------------------------------------------
December 31, 2007 25,477 17,154 745 625
-------------------------------------------------------------------------
-------------------------------------------------------------
Total
------------------------------
Proved
plus
Proved Probable Probable
(Mboe) (Mboe) (Mboe)
-------------------------------------------------------------
December 31, 2006 147,218 101,537 248,755
Extensions, improved recovery,
& discoveries 11,511 20,549 32,059
Technical Revisions 4,627 -9,848 -5,221
Acquisitions 9,583 9,269 18,851
Dispositions -11,940 -252 -12,192
Production -11,434 0 -11,434
-------------------------------------------------------------
December 31, 2007 149,564 121,255 270,819
-------------------------------------------------------------
(1) Numbers may not add due to rounding.
FINDING & DEVELOPMENT COSTS
-------------------------------------------------------------------------
3 Year
FD&A costs ($/boe) 2007 2006 2005 Average
-------------------------------------------------------------------------
Including future capital
Proved $23.36 $18.48 $15.42 $17.85
Proved plus probable $12.86 $13.57 $13.02 $13.17
Excluding future capital
Proved $24.18 $14.38 $12.84 $15.22
Proved plus probable $ 9.95 $ 8.85 $ 7.05 $ 8.27
-------------------------------------------------------------------------
FINANCIAL REVIEW
ADVISORIES
Management's Discussion and Analysis ("MD&A") is intended to provide both
an historical and prospective view of our activities. The MD&A was prepared as
at March 24, 2008, and should be read in conjunction with the audited
consolidated financial statements and related notes for the year ended
December 31, 2007 and the advisories set out below. The consolidated financial
statements have been prepared in accordance with Canadian generally accepted
accounting principles ("GAAP"). A reconciliation to U.S. GAAP is included in
Note 21 to the consolidated financial statements.
FORWARD LOOKING STATEMENTS
Certain information regarding the Company contained herein constitutes
forward-looking information and statements and financial outlooks
(collectively, "forward-looking statements") under the meaning of applicable
securities laws, including Canadian Securities Administrators' National
Instrument 51-102 Continuous Disclosure Obligations and 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) cash flow and capital and operating expenditures,
(ii) exploration, drilling, completion, and production matters, (iii) results
of operations, (iv) financial position, and (v) 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
assumptions underlying, and expectations reflected in, such forward-looking
statements are reasonable, it can give no assurance that such assumptions and
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's 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, access
difficulties and mechanical failures, weather related issues, 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, and other risks and
uncertainties described from time to time in the reports and filings made with
securities regulatory authorities by Compton. Statements relating to
"reserves" and "resources" are deemed to be forward-looking statements, as
they involve the implied assessment, based on estimates and assumptions, that
the reserves and resources described exist in the quantities predicted or
estimated, and can be profitably produced in the future.
The forward-looking statements contained herein are made as of the date of
this MD&A solely for the purpose of generally disclosing Compton's views of
its prospective activities. Compton may, as considered necessary in the
circumstances, update or revise the forward-looking statements, whether as a
result of new information, future events, or otherwise, but Compton does not
undertake to update this information at any particular time, except as
required by law. Compton cautions readers that the forward-looking statements
may not be appropriate for purposes other than their intended purposes and
that undue reliance should not be placed on any forward-looking statement. The
Company's forward-looking statements are expressly qualified in their entirety
by this cautionary statement.
NON-GAAP FINANCIAL MEASURES
Included in the MD&A and elsewhere in this report are references to
financial measures commonly used in the oil and gas industry, including
adjusted cash flow from operations and adjusted net earnings from operations.
These financial measures are not defined by Canadian generally accepted
accounting principles ("GAAP") and therefore are referred to as non-GAAP
measures. The non-GAAP measures used by the Company may not be comparable to
similar measures provided by other companies. We use these non-GAAP measures
to evaluate our performance.
Adjusted cash flow from operations should not be considered an alternative
to, or more meaningful than, cash provided by operating, investing and
financing activities or net earnings as determined in accordance with Canadian
GAAP, as an indicator of our performance or liquidity. Adjusted cash flow from
operations is used by us to evaluate operating results and our ability to
generate cash to fund future growth through capital investment.
Adjusted net earnings from operations represents net earnings excluding
certain items that are largely non-operational in nature and should not be
considered an alternative to, or more meaningful than, net earnings as
determined in accordance with Canadian GAAP. Adjusted net earnings from
operations is used by us to facilitate comparability of earnings between
periods.
USE OF BOE EQUIVALENTS
The oil and natural gas industry commonly expresses production volumes and
reserves on a barrel of oil equivalent ("boe") basis whereby natural gas
volumes are converted at the ratio of six thousand cubic feet to one barrel of
oil. The intention is to sum oil and natural gas measurement units into one
basis for improved measurement of results and comparisons with other industry
participants. We use the 6:1 boe measure which is the approximate energy
equivalency of the two commodities at the burner tip. However, boes do not
represent a value equivalency at the plant gate where we sell our production
volumes and therefore may be a misleading measure if used in isolation.
RESULTS OF OPERATIONS
2007 SUMMARY
- Drilled 322 gross (266 net) wells with a 97% success rate.
- Achieved annual average production of 31,326 boe/d.
- Generated adjusted cash flow from operations of $196.2 million, or
$1.48 per diluted share.
- Adjusted net earnings from operations for the year were
$21.3 million.
- Net earnings for the year were $129.2 million.
ADJUSTED CASH FLOW FROM OPERATIONS AND NET EARNINGS
-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------
Adjusted cash flow from
operations(1) ($000s) $ 196,194 $ 256,305 $ 278,112
Per share: basic $ 1.52 $ 2.01 $ 2.21
diluted $ 1.48 $ 1.92 $ 2.11
Net earnings ($000s) $ 129,266 $ 127,426 $ 81,326
Per share: basic $ 1.00 $ 1.00 $ 0.65
diluted $ 0.98 $ 0.95 $ 0.62
-------------------------------------------------------------------------
(1) Adjusted cash flow from operations is a non-GAAP term that represents
net earnings adjusted for non-cash items. We consider adjusted cash
flow from operations to be a key financial measure as it demonstrates
our ability to generate the cash flow necessary to fund future growth
through capital investment. Adjusted cash flow from operations may
not be comparable to similar measures presented by other companies.
Adjusted cash flow from operations
-------------------------------------------------------------------------
Years ended December 31, ($000s) 2007 2006 2005
-------------------------------------------------------------------------
Net earnings $ 129,266 $ 127,426 $ 81,326
-------------------------------------------------------------------------
Amortization of deferred charges
and other 3,417 1,996 2,190
-------------------------------------------------------------------------
Tender costs - - 20,750
-------------------------------------------------------------------------
Depletion and depreciation 151,411 143,057 105,504
-------------------------------------------------------------------------
Accretion of asset retirement
obligations 2,718 2,257 1,975
-------------------------------------------------------------------------
Unrealized foreign exchange (gain) (79,740) (665) (7,808)
-------------------------------------------------------------------------
Future income taxes (26,452) (3,636) 52,317
-------------------------------------------------------------------------
Unrealized risk management
(gain) loss 5,467 (27,522) 10,171
-------------------------------------------------------------------------
Stock-based compensation 8,416 9,121 5,903
-------------------------------------------------------------------------
Asset retirement expenditures (4,441) (2,352) (749)
-------------------------------------------------------------------------
Non-controlling interest 6,132 6,623 6,533
-------------------------------------------------------------------------
Adjusted cash flow from operations $ 196,194 $ 256,305 $ 278,112
-------------------------------------------------------------------------
Adjusted cash flow from operations declined in 2007 from the prior year's
level by approximately $60 million. The major causes of the decline were a $25
million reduction in realized risk management gains, a reduction of $19
million in revenue after royalties, and increases in general and
administrative and interest expenses. Additionally, at the end of the third
quarter of 2007, we closed the sale of our conventional light oil asset at
Worsley, which reduced production, adjusted cash flow from operations, and net
income accordingly for the last three months of the year as compared to the
prior year.
Net earnings for the year increased by approximately $2 million over 2006
and benefited from a foreign exchange gain of $79 million and a $26 million
future income tax recovery.
ADJUSTED NET EARNINGS FROM OPERATIONS
Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational and
non-cash nature. We evaluate our performance on adjusted net earnings from
operations which eliminates these non-operational items that can introduce a
level of volatility to net earnings determined in accordance with GAAP.
The following reconciliation identifies the after-tax effects of certain
items of non-operational nature that are included in our financial results.
Adjusted net earnings from operations may not be comparable to similar
measures presented by other companies.
SUMMARY OF ADJUSTED NET EARNINGS FROM OPERATIONS(1)
-------------------------------------------------------------------------
Years ended December 31,
($000s, except per share amounts) 2007 2006 2005
-------------------------------------------------------------------------
Net earnings, as reported $ 129,266 $ 127,426 $ 81,326
Non-operational items, after tax
Unrealized foreign exchange (gain) (66,934) (550) (6,339)
Unrealized risk management
(gain) loss 3,711 (18,027) 6,345
Stock-based compensation 5,713 5,974 3,682
Tender costs on repurchase
of 9.90% notes - - 14,414
Future income tax recovery due to
income tax rate reductions (50,470) (49,655) (5,764)
-------------------------------------------------------------------------
Adjusted net earnings from
operations $ 21,286 $ 65,168 $ 93,664
Per share: basic $ 0.17 $ 0.51 $ 0.75
diluted $ 0.16 $ 0.49 $ 0.71
-------------------------------------------------------------------------
(1) Adjusted net earnings from operations was referred to as Operating
Earnings in prior years.
Revenue
-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------
Average production
Natural gas (mmcf/d) 145 142 131
Liquids (bbls/d) 7,166 9,516 7,646
-------------------------------------------------------------------------
Total (boe/d) 31,326 33,187 29,424
Benchmark prices
NYMEX (U.S.$/mmbtu) $ 6.86 $ 7.26 $ 8.55
AECO ($/GJ)
Monthly index $ 6.27 $ 6.21 $ 8.04
Daily index $ 6.11 $ 6.19 $ 8.27
WTI (U.S.$/bbl) $ 72.37 $ 66.22 $ 56.56
Edmonton par ($/bbl) $ 76.23 $ 72.77 $ 68.72
Realized prices
Natural gas ($/mcf) $ 6.33 $ 6.32 $ 8.36
Liquids ($/bbl) 62.28 59.09 56.47
-------------------------------------------------------------------------
Total ($/boe) $ 43.82 $ 44.65 $ 52.54
Revenue ($000s)
Natural gas $ 334,920 $ 327,629 $ 398,543
Liquids 166,067 213,208 165,698
-------------------------------------------------------------------------
Total $ 500,987 $ 540,837 $ 564,241
-------------------------------------------------------------------------
SUMMARY OF REVENUE INCREASES FROM PRODUCTION AND PRICING
-------------------------------------------------------------------------
Natural Gas Liquids Total
($000s) Revenue Revenue Revenue
-------------------------------------------------------------------------
Reported 2006 revenue $ 327,629 $ 213,208 $ 540,837
Change in production volumes 7,291 (49,875) (42,584)
Change in prices - 2,734 2,734
-------------------------------------------------------------------------
Reported 2007 revenue $ 334,920 $ 166,067 $ 500,987
-------------------------------------------------------------------------
Overall production in 2007 fell 6% from the prior year. Natural gas
volumes increased 2%, while liquids production decreased 25% from 2006
volumes. The significant reduction in our year over year liquids volumes is
attributable to natural declines and the sale of our conventional light oil
asset, Worsley. This transaction closed at the end of the third quarter of
2007.
We market the majority of our natural gas production through a combination
of daily and monthly indexed contracts and aggregator contracts. During 2007,
approximately 10% of our natural gas production remained committed to longer
term aggregator contracts which realized a price that was, on average,
$0.75/mcf less than that received on non-aggregator volumes.
Our crude oil sales are priced based upon Edmonton postings and are
typically sold on 30 day evergreen arrangements. Natural gas liquids are bid
out on an annual basis to obtain the most favourable pricing. We sell our
crude oil and natural gas liquids primarily to refineries and marketers of
crude oil and natural gas liquids.
Periodically we enter into financial instrument contracts to hedge against
price volatility. This activity is fully disclosed in the Risk Management and
Financial Instrument sections of this MD&A. Realized commodity prices, as
reported in the MD&A, are before any hedging gains or losses.
ROYALTIES
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2007 2006 2005
-------------------------------------------------------------------------
Crown royalties $ 86,850 $ 100,230 $ 105,827
Other royalties 15,828 23,447 26,890
-------------------------------------------------------------------------
Net royalties $ 102,678 $ 123,677 $ 132,717
Percentage of revenues 20.5% 22.9% 23.5%
-------------------------------------------------------------------------
Royalties are paid to various government entities and other land and
mineral rights owners. Virtually all Crown royalties are paid to the province
of Alberta which has a royalty structure based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. Our royalty rate in 2007, as a percentage of revenue, decreased
from 2006 as a result of the increased contribution from lower productivity
wells to total production.
We anticipate 2008 royalty rates will remain relatively consistent with
prior years; however, significant changes to the Alberta royalty structure may
occur in 2009 as a result of the recent Alberta royalty review, the final
results of which are yet to be announced.
OPERATING EXPENSES
-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------
Operating expenses ($000s) $ 101,478 $ 102,643 $ 73,164
Operating expenses per boe ($/boe) $ 8.88 $ 8.47 $ 6.81
-------------------------------------------------------------------------
Year over year operating costs remained constant. However, when measured
on a $/boe basis, 2007 operating expenses increased by 5% when compared to
2006. Specific increases of note include salaries for field staff and contract
operators and rising electricity prices. Additionally, fourth quarter 2007
operating costs included significant lease repair and maintenance costs
associated with assets acquired during the last half of the year.
In prior years, operating costs were reported net of third party
processing fees. Commencing in 2007, third party processing income is included
in revenue and not netted against operating expenses. 2006 and 2005 operating
expenses have been reclassified accordingly.
With the current reduced level of activity in the industry, we are now
beginning to see indications that cost inflation is moderating. With an
increased emphasis on cost controls, we anticipate 2008 operating costs, on a
unit of production basis, will remain similar to those experienced in 2007.
TRANSPORTATION EXPENSES
-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------
Transportation costs ($000s) $ 12,615 $ 12,564 $ 10,858
Transportation costs per boe
($/boe) $ 1.10 $ 1.04 $ 1.01
-------------------------------------------------------------------------
We incur charges for the transportation of our production from the
wellhead to the point of sale. Pipeline tariffs and trucking rates for liquids
are primarily dependent upon production location and distance from the sales
point. Regulated pipelines transport natural gas within Alberta at tolls
approved by the government.
2007 transportation expense remained relatively constant with that of
2006. However, with the closing of the sale of our conventional oil property,
Worsley, at the end of the third quarter of 2007, our fourth quarter
transportation expense fell to $0.55/boe, as our oil trucking requirements
were reduced significantly.
GENERAL AND ADMINISTRATIVE EXPENSES
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2007 2006 2005
-------------------------------------------------------------------------
General and administrative expenses $ 41,633 $ 38,321 $ 34,638
Capitalized general and
administrative expenses (7,470) (9,625) (11,158)
Operator recoveries (2,835) (2,465) (2,257)
-------------------------------------------------------------------------
Total general and administrative
expenses $ 31,328 $ 26,231 $ 21,223
General and administrative per boe
($/boe) $ 2.74 $ 2.17 $ 1.98
-------------------------------------------------------------------------
Employee costs associated with increased personnel levels, together with a
general increase in remuneration necessary to attract and retain qualified
personnel in a very competitive industry, were the main contributors to the
increase in general and administrative expenses in 2007. Other increases
included insurance and costs associated with ongoing regulatory compliance
requirements. Additionally, increased expenses associated with additional
office space were incurred as a result of corporate acquisitions. During 2007,
we incurred direct expenses totaling approximately $1.5 million relating to
compliance requirements pursuant to the U.S. Sarbanes-Oxley Act of 2002 and
Canadian Multilateral Instrument 52-109.
General and administrative expenses in 2008 will be impacted by costs
associated with current shareholder activism activities. Such costs will
include additional legal fees, advisory fees and expenses, and employee
retention costs. Such costs are expected to be approximately $22 million, as
discussed in the Outlook and Guidance section of this MD&A and Note 20 to the
financial statements.
INTEREST AND FINANCE CHARGES
-------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted) 2007 2006 2005
-------------------------------------------------------------------------
Interest on bank debt, net $ 22,476 $ 14,243 $ 11,520
Interest on Senior Notes 38,345 35,880 20,912
-------------------------------------------------------------------------
Interest expense $ 60,821 $ 50,123 $ 32,432
Finance charges 2,672 3,952 2,519
-------------------------------------------------------------------------
Total interest and finance charges $ 63,493 $ 54,075 $ 34,951
-------------------------------------------------------------------------
Total interest and finance charges
per boe ($/boe) $ 5.55 $ 4.47 $ 3.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average annual debt
($000s, except where noted) 2007 2006 2005
-------------------------------------------------------------------------
Bank debt $ 348,216 $ 254,476 $ 228,381
Effective interest rate 6.46% 5.60% 4.23%
Senior notes (US$) $ 450,000 $ 412,802 $ 179,583
Effective interest rate 7.63% 7.64% 9.50%
-------------------------------------------------------------------------
Interest expenses relating to bank debt in 2007 increased from the prior
year as a result of increased borrowings incurred to fund our 2007 capital
program and overall floating interest rate increases.
NETBACKS
-------------------------------------------------------------------------
Years ended December 31, ($/boe) 2007 2006 2005
-------------------------------------------------------------------------
Realized price $ 43.82 $ 44.65 $ 52.54
Realized commodity hedge gain (loss) 1.68 3.24 (0.90)
Royalties (8.98) (10.21) (12.36)
Operating expenses (8.88) (8.47) (6.81)
Transportation (1.10) (1.04) (1.01)
-------------------------------------------------------------------------
Field operating netback $ 26.54 $ 28.17 $ 31.46
-------------------------------------------------------------------------
General and administrative (2.74) ard (5,422)
-
Attributed Canadian royalty income (7,810) (7,462)
Asset retirement obligations (9,177) (8,642)
Other (952) -
----------- -----------
Net future income tax liability $ 291,430 $ 308,480
----------- -----------
----------- -----------
The non-capital losses available for carry forward to reduce taxable
income in future years expire between 2011 and 2026.
17. Financial instruments
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.
On January 1, 2007 the Company adopted the new financial instrument
recognition, measurement, presentation and disclosure requirements of the
CICA as disclosed in Note 2 (b) to these consolidated financial
statements. Certain items have been reclassified as a reduction to
opening retained earnings, net of tax, as prescribed in the transitional
provisions.
Risk management activities during the year, utilizing derivative
instruments, relate to commodity price economic hedges, fixed price power
contracts, foreign currency contracts and cross currency interest rate
swap arrangements.
a) Unrealized risk management gains and losses as at December 31, 2007
i) Balance sheet classification
As at December 31, 2007, the Company had outstanding financial
instrument contracts for both commodity price risk management and
foreign currency risk management expiring at various periods to
December 2010. These contracts were valued on a mark-to-market
basis as at December 31, 2007 and the unrealized gains and losses
relating to these contracts are recorded on the consolidated
balance sheets as follows:
Commodity Foreign 2007 2006
As at December 31, 2007 Contracts Currency Total Total
---------- ---------- ---------- ----------
Unrealized gain
Current asset $ 1,790 $ 45 $ 1,835 $ 22,625
Non-current asset - 14,320 14,320 -
Unrealized loss
Current liability - (8,832) (8,832) (4,604)
Non current liability - (1,585) (1,585) (6,816)
---------- ---------- ---------- ----------
Total unrealized gains
(losses) $ 1,790 $ 3,948 $ 5,738 $ 11,205
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
The amounts relating to commodity price risk management and foreign
exchange risk management, respectively, are disclosed below:
ii) Commodity price risk management
The Company enters into economic 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. Prices are marked to industry benchmarks
specifically AECO spot for gas contracts and WTI NYMEX for oil
contracts and are valued in Canadian dollars unless otherwise
disclosed. Outstanding economic hedge contracts at December 31, 2007
are:
Daily Mark-to-
Notional Average Market
Commodity Term Volume Price gain
--------- ---- -------- ------- ---------
Natural gas $8.27 -
Collar Nov./07 - Mar./08 9,524mcf $10.50/mcf $ 1,416
Electricity Jan./06 - Dec./08 2.5MW $55.00/MWh 374
---------
$ 1,790
---------
---------
The gains and losses realized during the year on the electricity
contract are included in operating expenses.
Subsequent to December 31, 2007, the Company entered into the
following commodity contracts:
Natural gas
Collar Apr./08 - Oct./08 52,381 mcf $7.33 -
$8.48/mcf
Fixed Apr./08 - Oct./08 19,048 mcf $7.86/mcf
Collar Nov./08 - Mar./09 28,571 mcf $8.40 -
$10.00/mcf
Fixed Nov./08 - Mar./09 9,524 mcf $8.51/mcf
Oil
Fixed Mar./08 - Dec./08 1,000 bbl US$93.00/bbl
iii) Foreign currency risk management
The Company is exposed to fluctuations in the exchange rate between
the Canadian dollar and the US dollar. Crude oil and to a certain
extent natural gas prices are based upon reference prices denominated
in US 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 US
dollars in order to manage the risk.
Concurrent with the issuance of 9.90% Senior Notes in 2002, the
Company entered into cross currency interest rate swap arrangements
expiring May 2009 that convert fixed rate US dollar denominated
interest obligations into floating rate Canadian dollar denominated
interest obligations. 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 maintains it as a source of US funds
used to settle interest obligations on the 7.625% Senior Notes.
During the year the Company entered into a series of foreign exchange
contracts relating to the US$450 million senior notes due December 1,
2013, effectively fixing the liability in Canadian dollars on
December 1, 2010, being the second call date of the senior notes.
Additionally, the Company entered into a series of foreign exchange
contracts relating to the semi-annual interest settlement obligations
until November 30, 2010.
On December 31, 2007, the Company had the following foreign exchange
contracts in place:
Amount Amount Mark to
Contract USD Rate CDN Term Market
--------- ------ ---- ------ ---- --------
Matures on
Currency December 1,
Swap $450,000,000 96.9750 $436,387,500 2010 $ 14,146
Equal Payments
on May 30 and
Currency Nov. 30 until
Swap $78,435,000 99.5500 $78,082,043 2010 219
Cross
Currency Equal payments
Interest on May 15 and
Rate BA plus Nov. 15 until
Swap $24,502,500 4.845% $34,627,785 2009 (10,417)
---------
Total unrealized foreign exchange gain $ 3,948
---------
---------
b) Risk management (gain) loss
Risk management gains and losses recognized in the consolidated
statements of earnings and other comprehensive income during the
periods relating to commodity prices and foreign currency
transactions are summarized below:
Commodity Foreign
Year ended December 31, 2007 Contracts Currency Total
------------ ------------ ------------
Unrealized
Change in fair value $ 20,834 $ (15,367) $ 5,467
------------ ------------ ------------
Realized cash settlements (19,220) 7,739 (11,481)
------------ ------------ ------------
Total (gain) loss $ 1,614 $ (7,628) $ (6,014)
------------ ------------ ------------
------------ ------------ ------------
Commodity Foreign
Year ended December 31, 2006 Contracts Currency Total
------------ ------------ ------------
Unrealized
Amortization of deferred loss $ - $ 1,642 $ 1,642
Change in fair value (25,775) (3,389) (29,164)
------------ ------------ ------------
(25,775) (1,747) (27,522)
Realized cash settlements (39,217) 3,018 (36,199)
------------ ------------ ------------
Total (gain) loss $ (64,992) $ 1,271 $ (63,721)
------------ ------------ ------------
------------ ------------ ------------
Commodity Foreign
Year ended December 31, 2005 Contracts Currency 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
------------ ------------ ------------
------------ ------------ ------------
c) 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
generally 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 financial institutions and believes these risks are minimal.
d) Fair value of financial assets and liabilities
Held for trading financial assets and liabilities are carried at fair
value. The carrying value of accounts receivable, accounts payable,
and bank debt approximate fair value due to the short term nature of
these instruments and variable rates of interest. The senior term
notes trade in the US and the estimated fair value was determined
using quoted market prices.
As at December 31, 2007 2006
Carrying Fair Carrying Fair
Amount Value Amount Value
Financial Assets
Held-for-trading
Cash $ 8,665 $ 8,665 $ 11,876 $ 11,876
Other current assets 19,772 19,772 22,869 22,869
Loans and receivables
Accounts receivable $ 80,331 $ 80,331 $ 83,535 $ 83,535
Financial Liabilities
Other financial
liabilities
Accounts payable $147,983 $147,983 $141,443 $141,443
Bank debt 398,426 398,426 328,000 328,000
Senior term notes 433,762 415,743 524,385 503,410
The fair value of derivative financial instruments related to risk
management activities, classified as held-for-trading, are disclosed
elsewhere in this note.
ADD: /SECOND AND FINAL ADD - TO430 - Compton Petroleum Corporation/
18. Cash flow
Changes in non-cash working capital items increased (decreased) cash as
follows:
Years ended December 31, 2007 2006 2005
------------ ------------ ------------
Accounts receivable and other
current assets $ (11,614) $ 24,395 $ (17,672)
Accounts payable 6,540 (62,425) 78,385
------------ ------------ ------------
$ (5,074) $ (38,030) $ 60,713
------------ ------------ ------------
------------ ------------ ------------
Net change in non-cash working
capital
Relating to:
Operating activities $ (23,366) $ 19,823 $ 6,612
Investing activities 18,292 (57,853) 54,101
------------ ------------ ------------
$ (5,074) $ (38,030) $ 60,713
------------ ------------ ------------
------------ ------------ ------------
Amounts paid during the year relating to interest expense and capital
taxes were as follows:
Years ended December 31, 2007 2006 2005
------------ ------------ ------------
Interest paid $ 60,976 $ 48,857 $ 31,444
------------ ------------ ------------
------------ ------------ ------------
Current income taxes paid $ 41 $ 14 $ 4,101
------------ ------------ ------------
------------ ------------ ------------
19. Commitments and contingent liabilities
a) Commitments
The Company has committed to certain payments over the next five
years, as follows:
2008 2009 2010 2011 2012
---------- ---------- ---------- ---------- ----------
Operating leases $ 3,811 $ 3,325 $ 505 $ - $ -
Office facilities 4,351 4,921 6,160 5,484 5,569
MPP partnership
distributions 9,172 3,057 - - -
---------- ---------- ---------- ---------- ----------
$ 17,334 $ 11,303 $ 6,665 $ 5,484 $ 5,569
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
The Company has entered into a lease agreement for new office facilities
commencing 2009. Annual commitments under the lease agreement are
approximately $5.6 million per year for the 10 year term. The commitment
remaining on the office facilities subsequent to 2012 is $33.6 million
and the total of all commitments, to expiry, is $80 million.
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 not significant and are not
expected to have a material impact on the financial position or
results of operations of the Company.
20. Subsequent events
On January 23, 2008, Compton announced its budget for 2008 and the
Company's longer term plans for 2009 and 2010. On January 29, 2008, the
Company received a letter from Centennial Energy Partners LLC, a major
shareholder of the Company, wherein they restated comments contained in a
letter to the Company dated December 14, 2007, that in their opinion, a
major discount had developed between the underlying value of the
Company's asset base and its share price. Additionally, they expressed
concerns that the Company's plans, as announced, would not eliminate the
discount and require Compton shareholders' to assume significant
execution risk, commodity price risk and stock market risk for minimal
per-share return and requested that the Company be put up for sale.
In response to Centennial's concerns, the Board of Directors, in a news
release dated February 28, 2008, announced that it would conduct a formal
review of the Company's business plans and alternatives for enhancing
shareholder value, and had appointed independent financial advisors to
assist the Company in the conduct of this review.
The Company has estimated that during 2008, Compton will incur direct
costs associated with, and costs resulting from, the process that could
total approximately $22 million. These expenses will be recognized
throughout the year as they occur.
In addition to the above, cash outlays associated with change of control
provisions relating to the Company's senior notes, Mazeppa Processing
Partnership arrangements, and employee contracts could result depending
upon the outcome of the review.
Further Information
Additional information, including our Annual Information Form, will be
available by month end on the Canadian Securities Administrators' System
for Electronic Document Analysis and Retrieval ("SEDAR") at
www.sedar.com.
CONFERENCE CALL
Compton will be conducting a conference call and audio webcast Wednesday,
March 26, 2008 at 9:30 a.m. Mountain Standard Time (11:30 a.m. EST) to discuss
the Company's 2007 fourth quarter and 2007 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 1-800-732-9307
Local Toronto: 1-416-644-3418
Webcast URL:
http://phx.corporate-ir.net/phoenix.zhtml?p=irol-eventDetails&c=69018&eventID=1766299
The audio replay will be available two hours after the conclusion of the
conference call and will be accessible until Tuesday, April 3, 2007. Callers
may dial toll-free 1-877-289-8525 and enter access code 21263872 (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.
SOURCE Compton Petroleum Corporation
E.G. Sapieha, President & CEO, N.G. Knecht, VP Finance & CFO, or Lorna Klose,
Manager, Investor Relations, Telephone: (403) 237-9400, Fax (403) 237-9410;
Website: www.comptonpetroleum.com, Email: investorinfo@comptonpetroleum.com/
/FIRST ADD TO FOLLOW
