Compton reports 2007 year end results

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

-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
(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
-------------------------------------------------------------------------

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
-------------------------------------------------------------------------
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

-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------

Standing, cased wells 11 9
-------------------------------------------------------------------------
2007 Total 322 266 97%
-------------------------------------------------------------------------

2006 Total 266 56 20 342 274
-------------------------------------------------------------------------

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) (2.17) (1.98)
Interest (5.55) (4.47) (3.25)
Current taxes - - (0.47)
-------------------------------------------------------------------------
Cash flow netback $ 18.25 $ 21.53 $ 25.76
-------------------------------------------------------------------------

RISK MANAGEMENT

Our financial results are impacted by external market risks associated
with fluctuations in commodity prices, interest rates, and the Canadian/U.S.
dollar exchange rate. We utilize various financial instruments for non-trading
purposes to manage and mitigate our exposure to these risks. Our financial
instruments are not designated for hedge accounting, and accordingly are
recorded at fair value on the consolidated balance sheets, with subsequent
changes recognized in consolidated net earnings and other comprehensive
income.
Financial instruments utilized to manage risk are subject to periodic
settlements throughout the term of the instruments. Such settlements may
result in a gain or loss, which is recognized as a realized risk management
gain or loss at the time of settlement.
The mark-to-market values of financial instruments outstanding at the end
of a reporting period reflect the values of the instruments based upon market
conditions existing as of that date. Any change in the fair values of the
instruments from that determined at the end of the previous reporting period
is recognized as an unrealized risk management gain or loss. Unrealized risk
management gains or losses may or may not be realized in subsequent periods
depending upon subsequent moves in commodity prices, interest rates, or
exchange rates affecting the financial instruments. Risk management gains
and losses recognized in 2007 are outlined below.

-------------------------------------------------------------------------
Year ended December 31, ($000s) 2007 2006 2005
-------------------------------------------------------------------------

Commodity contracts
Realized (gain) loss $ (19,220) $ (39,217) $ 9,663
Unrealized (gain) loss 20,834 (25,775) 5,136
Foreign currency contracts
Realized (gain) loss 7,739 3,018 (532)
Unrealized (gain) loss (15,367) (1,747) 5,035
-------------------------------------------------------------------------
Total risk management (gain) loss $ (6,014) $ (63,721) $ 19,302
-------------------------------------------------------------------------

Realized (gain) loss $ (11,481) $ (36,199) $ 9,131
Unrealized (gain) loss 5,467 (27,522) 10,171
-------------------------------------------------------------------------
Total risk management (gain) loss $ (6,014) $ (63,721) $ 19,302
-------------------------------------------------------------------------

DEPLETION AND DEPRECIATION

-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------

Total depletion and depreciation
($000s) $ 151,411 $ 143,057 $ 105,504
Depletion and depreciation
per boe ($/boe) $ 13.24 $ 11.81 $ 9.82
-------------------------------------------------------------------------

Accelerated capital programs and competition throughout the oil and gas
industry during the current and prior years increased the demand and costs of
goods and services. This increase in costs is reflected in higher finding,
development, and on-stream costs which in turn, have resulted in an increase
in depletion and depreciation rates on a boe basis in the current year in
comparison to prior periods.
FOREIGN EXCHANGE
The foreign exchange gain recognized on the consolidated statements of
earnings results primarily from the translation of our 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 being recognized as an unrealized foreign
exchange gain or loss.
In 2007, we entered into foreign currency exchange contracts related to
our $450 million of U.S. dollar denominated Senior Notes. The notes were
issued in 2005 and 2006 and are due in 2013. The strengthening of the Canadian
dollar against that of the U.S. resulted in the Company recognizing the
unrealized foreign exchange gain referred to in the preceding paragraph. On
October 26 and 31, 2007 we entered into foreign exchange forward contracts to
purchase U.S.$450 million for C$436 million, as at December 1, 2010 being the
second call date on the notes. These contracts effectively crystallize a total
foreign exchange gain of approximately $91.7 million.
On November 22, 2005, pursuant to a tender offer, we repurchased U.S.$158
million of the 9.90% Senior Notes issued in 2002. As a result of the
repurchase, we crystallized $62 million of the accumulated unrealized foreign
exchange gains in 2005 that had previously been recognized with the
strengthening of the Canadian dollar subsequent to the note issuance.
STOCK-BASED COMPENSATION

-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------

Options granted (000s) 2,074 2,228 2,930
Weighted average fair value of
options granted ($/share) $ 4.23 $ 6.90 $ 5.45
Stock-based compensation expense
recognized ($000s) $ 11,034 $ 10,488 $ 5,903
-------------------------------------------------------------------------

We have a stock option plan for employees, officers, and directors. The
plan is designed to attract, motivate, and retain outstanding individuals and
to align their success with that of our shareholders. The fair value of
options granted is estimated on the date of grant using the Black-Scholes
option pricing model and the associated compensation expense is recognized
over the vesting period.
During 2006, in recognition of the shortage of, and competition for,
qualified personnel within the oil and gas industry in Western Canada, we
implemented an Employee Retention Program in July 2006 for our existing
employees, excluding officers and directors. Pursuant to the program, and
based upon various conditions existing on July 1, 2007, including the market
value of the Company's shares, we incurred additional compensation expense of
$4.0 million. For the years ended December 31, 2006 and 2007, we recognized
$1.4 million and $2.6 million respectively in stock-based compensation in
relation to this program.
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. The classification of future income
taxes between current and non-current is based upon the classification of the
liabilities and assets to which the future income tax amounts relate. The
classification of a future income tax amount as current does not imply a cash
settlement of the amount within the following twelve month period.
CURRENT INCOME TAXES
No current income taxes were incurred in 2007 and 2006 primarily as a
result of the elimination of federal capital tax effective January 1, 2006.
Current taxes of $5 million in 2005, in addition to capital taxes, included $3
million related to the resolution of a Notice of Objection with respect to a
corporate acquisition in a prior tax period. As a result of the reassessment
resulting from resolution of the Notice of Objection, $7 million of tax
deductible exploration expenses denied to the acquired corporation were added
to our income tax pools as a positive offset to incurring the current
liability. The resolution of this matter did not impact our total future
income tax expense for 2006.
FUTURE INCOME TAXES
Future income taxes in 2007 included a $50 million recovery as a result of
reductions in the federal corporate tax rates, which were enacted in the
second and fourth quarter of 2007. The federal tax rate is to be reduced by
1.0% in 2008, 1.0% in 2009, 1.0% in 2010, 2.0% in 2011, and 3.5% in 2012.
Future taxes in 2006 also included a $50 million recovery as a result of
reductions in the federal and Alberta corporate tax rates, which were enacted
in the second quarter of 2006.
CORPORATE TAX RATES

-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------

Statutory rate 32.1% 34.5% 37.6%
Effective rate (24.3)% (2.8)% 39.5%
-------------------------------------------------------------------------

A reconciliation of our effective tax rate to the statutory rate may be
found in Note 16a to the consolidated financial statements.
TAX POOLS
The following table summarizes our estimated tax pool balances by
classification.
-------------------------------------------------------------------------
Available Maximum
Balance Annual
As at January 1, 2008 ($000s) Deduction
-------------------------------------------------------------------------

Canadian exploration expense
and non-capital losses $ 360,500 100%
Canadian development expense 367,241 30%
Canadian oil and natural gas property expense 74,070 10%
Undepreciated capital cost and financing costs 316,151 ~25%
-------------------------------------------------------------------------
Total $1,117,962
-------------------------------------------------------------------------

A significant portion of our taxable income is generated by a wholly owned
partnership. Consolidated earnings before income taxes include $149 million
(2006 - $259 million) of partnership earnings that will be included in the
following year's income for income tax purposes. Future income taxes include
$44 million (2006 - $83 million) as a result of this deferral of partnership
earnings.
Based upon planned capital expenditure programs and current commodity
price assumptions, it appears we will not incur current income taxes until at
least 2010.
SUMMARY OF CAPITAL EXPENDITURES

-------------------------------------------------------------------------
Years ended December 31, 2007 2006 2005
-------------------------------------------------------------------------
($000s) % ($000s) % ($000s) %
-------------------------------------------------------------------------

Drilling and
completions $226,789 59 $294,197 60 $318,502 66
Land and seismic 47,528 12 59,905 12 55,469 11
Facilities 111,215 29 137,409 28 109,729 23
-------------------------------------------------------------------------
Sub-total $385,532 100 $491,511 100 $483,700 100
Corporate acquisitions 131,380 - -
Acquisitions and
divestments, net (229,391) 34,394 28,575
-------------------------------------------------------------------------
Sub-total $287,521 $525,905 $512,275
MPP 4,796 (31) 1,261
-------------------------------------------------------------------------
Total capital
expenditures $292,317 $525,874 $513,536
-------------------------------------------------------------------------

Capital spending in 2007 was directed towards the continued development of
our core natural gas resource plays in southern and central Alberta. Overall,
2007 capital spending, before acquisitions and divestitures, decreased by 22%
when compared to 2006. This reduction reflects the fewer number of wells
drilled in 2007 versus the prior year as well as an overall reduction in
certain service costs in 2007 as compared to 2006. We drilled 6% fewer wells
in 2007 as compared to 2006, and drilling and completions expenditures
declined by 23%, which implies an overall reduction in service costs of
approximately 17%. Lower spending on land and seismic and facilities during
2007 also reflect the lower level of activity as compared to 2006.
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
including strategic acquisitions. 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, resulting
in $229.4 million property divestments net of acquisitions. Through two
corporate acquisitions, Stylus Energy Inc. and WIN Energy Corporation, we
significantly expanded our presence in southern Alberta and the Foothills in
2007 at a total cost of $131.4 million.
During the second quarter of 2007, we undertook a major two week
maintenance turn around at the Mazeppa gas plant. This scheduled maintenance,
which is necessary every three years, accounts for the increased capital
spending at Mazeppa when compared to 2006 and 2005.
Capital expenditures, before acquisitions and divestitures, in 2006
increased only marginally from 2005; however, they reflect overall cost
inflation experienced in the industry during the year. We drilled a total of
274 net wells in 2006 at an average cost, to drill and complete, of $1,074,000
per well. In contrast, we drilled 334 net wells during 2005 at an average cost
of $954,000 per well. Although not an entirely comparable analysis, as the mix
of shallow, deep, and oil wells affected this comparison, this represented a
12.6% increase in drilling and completion costs, on a per well basis, in 2006
as compared to 2005.
Spending on production facilities increased $27.7 million in 2006 over
2005 and comprised 28% of our total capital program, before acquisitions and
divestments as compared to 23% in 2005. Although we deferred a portion of our
initial 2006 drilling program in deference to lower commodity prices and the
inflationary cost environment, we continued with the majority of our planned
expenditures in 2006 relating to equipment and facilities.
LIQUIDITY AND CAPITAL RESOURCES

-------------------------------------------------------------------------
As at December 31,
($000s, except where noted) 2007 2006 2005
-------------------------------------------------------------------------

Working capital deficiency(1) $ 39,215 $ 23,163 $ 62,116
Bank debt 398,426 328,000 177,900
Senior term notes 433,762 524,385 357,640
-------------------------------------------------------------------------
Total indebtedness $ 871,403 $ 875,548 $ 597,656

-------------------------------------------------------------------------
Shareholders' equity $ 869,956 $ 734,124 $ 596,336

Debt to adjusted cash flow
from operations(2) 4.2 3.4 2.2
Debt to book capitalization 49% 54% 50%
Debt to market capitalization 41% 39% 22%
-------------------------------------------------------------------------

1. Excludes unrealized risk management items net of related future
income taxes.
2. Based on trailing 12 month adjusted cash flow from operations.

Senior Term Notes

The Senior Notes are repayable in U.S. dollars for 2007 and are carried on
the balance sheet at their Canadian dollar equivalent less related unamortized
transaction costs. The 2005 and 2006 comparative amounts have not been
adjusted to reflect new accounting treatment. The Canadian dollar equivalent
is determined based upon the Canadian/U.S. dollar exchange rate at December
31.
During the fourth quarter of 2007, we entered into foreign currency
exchange contracts to purchase US$450 million for C$436 million as at December
1, 2010, being the second call date on the Senior Notes. The Senior Notes are
due on December 1, 2013. The foreign exchange contracts effectively fix the
Canadian dollar repayment amount of the Senior Notes at $436 million through
to December 1. 2010 and crystallized an unrealized foreign exchange gain of
approximately $91.7 million.
The carrying value of the Senior Notes will continue to vary in relation
to the Canadian/U.S. dollar exchange rate and any resulting unrealized foreign
exchange gains or losses will be recognized. The variance in the carrying
amount of the notes will largely be offset by the mark-to-market value of the
foreign exchange contracts. Effectively, unrealized foreign exchange gains and
losses resulting from translation of the notes will be offset by unrealized
gains and losses on the foreign exchange contracts until December 2, 2010. At
December 31, 2007 an accumulated gain of $14.1 million has been recorded on
the foreign exchange contracts as outlined in Note 17(a)(iii) to the financial
statements.
Bank Debt
Bank debt is comprised of a syndicated credit facility with a current
authorized limit of $500 million. The facility is a borrowing based facility
with the borrowing base being determined based upon year end reserves. The
facility is subject to review annually prior to the renewal date of July 4,
2008. We do not anticipate any reduction to the borrowing base and authorized
credit facility amount given the increase in 2007 reserves over 2006.
Our corporate debt is structured to provide us with financial flexibility.
Of our existing debt, 50% consists of Senior Notes that are not due until
2013, giving us the ability to draw on our senior secured credit facilities to
assist in funding our planned 2008 capital program.
We have identified a number of non-core properties for disposition during
2008. We anticipate the proceeds from the sale of these properties to be
approximately $250 million. Initially, the proceeds so generated will be
applied to reduce our outstanding bank debt. Additionally, the authorized
limit of $500 million may be reduced to recognize the reduction in reserves
related to these dispositions. Any such potential change is expected to be
minimal due to 2007 reserve additions.
We believe internally generated adjusted cash flow from operations and
proceeds from planned property dispositions will be more than sufficient to
fund our planned 2008 capital program. Excess funds will be used to reduce
bank indebtedness.
CONTRACTUAL OBLIGATIONS
As part of normal business, we have entered into arrangements and incurred
obligations that will impact our future operations and liquidity, some of
which are reflected as liabilities in the consolidated financial statements.
The following table summarizes our contractual obligations as at December 31,
2007.
-------------------------------------------------------------------------
Payments Due by Period

Less than 1-3 4-5 After
($000s) 1 year years years 5 years Total
-------------------------------------------------------------------------
Bank debt - $400,000 - - $400,000
Senior term notes - - $436,388 - 436,388
Operating leases $ 3,811 3,830 - - 7,641
Office facilities 4,351 16,565 5,569 $ 33,414 59,899
MPP partnership
distributions 9,172 3,057 - 12,229
Asset retirement
obligations 2,818 3,910 7,203 232,631 246,562
-------------------------------------------------------------------------
Total $ 20,152 $427,362 $449,160 $266,045 $1,162,719
-------------------------------------------------------------------------

We have the ability and the intention to extend the term of our bank debt
and therefore repayment of the facility, although included in the schedule of
contractual obligations, is not expected to occur.
OUTLOOK AND GUIDANCE FOR 2008
The following section summarizes our plans and guidance for 2008 as
announced in a news release dated January 23, 2008. We believe our budget to
be achievable, however, certain events more fully described under "Recent
Events", will impact our 2008 operations.
Summary of 2008 Guidance

-------------------------------------------------------------------------
2008 Budget Range
-------------------------------------------------------------------------

Capital expenditures ($millions) $410
Gross wells 350
Average production - total boe/d 36,000 - 37,000
Adjusted cash flow from operations ($millions) $245 - $255
-------------------------------------------------------------------------

Our 2008 projected adjusted cash flow from operations is based upon the
following pricing assumptions:
-------------------------------------------------------------------------
Benchmark Realized
-------------------------------------------------------------------------

Natural gas AECO Cdn $6.98/mcf Cdn $6.95/mcf
Crude oil ($/bbl) WTI U.S. $81.00/bbl Cdn $72.75bbl
-------------------------------------------------------------------------

The average Canadian/U.S. exchange rate is budgeted at $1.00 U.S. = $1.00
Cdn.
Concurrent with strengthening commodity prices during the first part of
2008, we have systematically entered into a number of commodity hedge
contracts as summarized in the Risk Management section of this MD&A and Note
17(a) (ii) to the financial statements. The effect of these contracts is an
increase in projected 2008 cash flow of $10.8 million from the amount noted
above. It is our intent to hedge approximately 50% of our gross production
forward 12 to 18 months.
Cash Flow Sensitivities for 2008

-------------------------------------------------------------------------
($millions) Change in Cash Flow
-------------------------------------------------------------------------

Change of Cdn $0.25/mcf in the benchmark AECO
natural gas price $14.0
Change of U.S. $1.00/bbl in the benchmark WTI
oil price $0.4
-------------------------------------------------------------------------

In the event of significant changes in commodity prices, operating and
exploration costs, or an overall change in general economic or industry
conditions, we can readily amend our capital expenditure program as
appropriate.
RECENT EVENTS
In response to concerns raised by a major shareholder of Compton, the
Board of Directors of the Company, as announced in a news release dated
February 27, 2008 will conduct a formal review of the Company's business plans
and strategic alternatives. This will include exploring potential asset
divestments, equity alternatives, strategic alliances, joint venture
opportunities, mergers, or a corporate transaction. In the aforementioned news
release, the Company cautioned shareholders that there is no assurance that
the review will result in any specific transaction and no timetable had been
set for its completion.
The Company has estimated that during 2008 direct costs and costs
resulting from the process associated with shareholder activism will be
approximately $22 million. Such costs will include additional legal fees,
advisory fees and expenses, and employee retention costs. Such costs will be
included in 2008 general and administrative expenses and will reduce cash flow
from operations. Depending upon the outcome of the process the Company could
incur additional cash outlays relating to change of control provisions
applicable to the Company's Senior Notes, Mazeppa Processing Partnership
arrangements, employee contracts, and additional advisory and legal fees.
At this stage, we are unable to predict the outcome of the review process
and the direction that Compton may ultimately take. As events unfold, we will
provide complete and timely updates.
ADDITIONAL DISCLOSURES

CONTROLS AND PROCEDURES

With respect to disclosure controls and procedures and internal control
over financial reporting, we are required to comply with the U.S.
Sarbanes-Oxley Act of 2002 and Canadian Multilateral Instrument 52-109,
Certification of Disclosure in Issuers' Annual and Interim Filings. These
regulations are substantially the same. However, the most significant
difference is the U.S. requirement for the registered public accounting firm
that audits our financial statements, included in our annual report, to issue
an attestation report on our internal control over financial reporting. There
is no corresponding Canadian attestation requirement.
There are certain procedural and wording differences between the U.S. and
Canadian certifications. We have chosen to file the form of certification
pursuant to Section 302 of the Sarbanes-Oxley Act with the U.S. Securities and
Exchange Commission ("SEC") and Form 52-109 F1, Certification of Annual
Filings, with the Canadian Securities Administrators ("CSA").
We have complied with both the U.S. and Canadian requirements in respect
of disclosure controls and procedures and internal control over financial
reporting and our report is below.
MANAGEMENT'S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The term "disclosure controls and procedures" is defined, under Rule
13a-15(d) of the U.S. Exchange Act of 1934, as controls and other procedures
that are designed to ensure both non-financial and financial information
required to be disclosed by us in our periodic reports is recorded, processed,
summarized, and reported within the time periods required, and this
information is accumulated and communicated to management as appropriate, to
allow timely decisions regarding required disclosures. The definition of
disclosure controls and procedures with respect to Canadian Multilateral
Instrument 52-109 is substantially the same.
As indicated in our certifications filed with the SEC and CSA, we
completed an evaluation of the effectiveness of the design and operation of
our disclosure controls and procedures as of December 31, 2007, under the
supervision and with the participation of our Management, including our
President & CEO and VP Finance & CFO. Based upon our evaluation, we concluded
our disclosure controls and procedures were effective.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including our President & CEO and VP Finance & CFO, is
responsible for establishing and maintaining adequate internal control over
financial reporting. The term "internal control over financial reporting" is
defined, under both Rule 13a-15(f) of the U.S. Exchange Act of 1934 and
Canadian Multilateral Instrument 52-109, as processes designed by, or under
the supervision of, our principal executive and principal financial officers,
and effected by our board of directors, management and other personnel, to
provide reasonable assurance regarding the reliability of our financial
reporting and the preparation of our financial statements for external
purposes in accordance with GAAP. These controls would include policies and
procedures that:
1. Pertain to the maintenance of our records, that accurately and fairly
reflect the transactions affecting, and dispositions of, our assets;

2. Provide reasonable assurance that transactions are recorded to be
able to prepare our financial statements in accordance with GAAP, and
that our receipts and expenditures are made only in accordance with
authorizations of our management and directors; and

3. Provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of our assets, which
could have a material effect on our financial statements.

We completed an evaluation of the effectiveness of the design and
operation of our internal control over financial reporting under the
supervision, and with the participation, of our Management, including our
President & CEO and VP Finance & CFO. We conducted our evaluation of the
effectiveness of our internal control over financial reporting based on the
Internal Control - Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission, also known as COSO. Based upon our
evaluation, we have concluded, as of December 31, 2007, internal control over
financial reporting was effective.
The effectiveness of internal control over financial reporting as of
December 31, 2007 was audited by Grant Thornton LLP, Chartered Accountants,
the independent registered public accounting firm, which also audits our
financial statements. They have issued their Independent Auditors' Report
which is included in this Annual Report.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
During the quarter ended March 31, 2007, we made two material changes to
internal control over financial reporting. On March 1, 2007 we converted our
production accounting and royalty management information systems. These
changes were implemented to improve both operational efficiencies and internal
controls. These conversions were not due to any identified internal control
weaknesses.
During the quarter ended December 31, 2007, we made one material change to
internal control over financial reporting. On October 15, 2007, we implemented
our substantially re-engineered capital expenditure approval and tracking
business process. This included improved policies and procedures as well as
new workflow software to support those policies and procedures. This change
was implemented to improve operational effectiveness and efficiency as well as
remediate internal control deficiencies.
These changes were subject to our change management procedures which are
effective.
There were no other changes during the year ended December 31, 2007 that
materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
Accounting estimates require us to make assumptions regarding matters that
are uncertain at the time the estimate is made and may have a material impact
on our financial condition. A comprehensive discussion of our significant
accounting policies may be found in Note 1 to the consolidated financial
statements.
OIL AND NATURAL GAS RESERVES
The independent petroleum engineering and geological consulting firm of
Netherland, Sewell & Associates, Inc. evaluated and reported on 96% of our oil
and natural gas reserves. The remainder was internally evaluated.
The estimation of reserves is a subjective process. Forecasts are based on
engineering data, projected future rates of production, and the timing of
future expenditures, all of which are subject to numerous uncertainties and
various interpretations. We expect that our estimates of reserves will change
with updated information from the results of future drilling, testing, or
production levels. Such revisions could be upwards or downwards. Reserve
estimates have a material impact on depletion and depreciation, asset
retirement obligations, and impairment costs, all of which could possibly have
a material impact on our consolidated net earnings.
DEPLETION
Capitalized costs and estimated future expenditures to develop proved
reserves, including abandonment costs, are depleted based on the proportion of
proved oil and natural gas reserves produced during the year compared to
estimated total proved reserves. Investments in unproved properties and major
development projects are not amortized until proved reserves associated with
the projects can be determined or until impairment occurs. If it is determined
that properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized.
In 2007, we incurred $151 million of depletion and depreciation. If our
proved reserves were to increase by 5%, our depletion and depreciation expense
would decrease by $1.8 million and consolidated net earnings after tax would
increase by $1.4 million. If our proved reserves were to decrease by 5%, our
depletion and depreciation expense would increase by $2.0 million and
consolidated net earnings after tax would decrease by $1.5 million.
IMPAIRMENT
In applying the full cost method of accounting, we periodically calculate
a ceiling or limitation on the amount that property and equipment may be
carried for on the consolidated balance sheets. An impairment exists if the
undiscounted future net cash flows from proved reserves at future commodity
prices plus the cost of undeveloped properties is less than the carrying value
of the capitalized costs. As at December 31, 2007, the ceiling amount
calculated was $2.4 billion (2006 - $2.7 billion) in excess of the carrying
value of the costs capitalized.
If an impairment is found to exist, the impaired properties are written
down to their fair value. The fair value of the assets is calculated based on
future net cash flows from proved plus probable reserves, discounted at a risk
free interest rate using future commodity prices, plus the cost of undeveloped
properties. An impairment may result in a material loss for a particular
period; however, future depletion and depreciation expense would be reduced as
a result.
Assumptions about reserves and future prices are required to calculate
future net cash flows. The assumptions made to estimate reserves have been
discussed above. There is significant uncertainty regarding forecasting future
commodity prices due to economic and political uncertainties. Future prices
are derived from a consensus of price forecasts among recognized reserve
evaluators. Estimates of future cash flows assume a long term price forecast
and current operating costs per boe plus an inflation factor.
It is difficult to determine and assess the impact of a decrease in proved
reserves on impairment. The relationship between reserve estimates and the
estimated undiscounted cash flows, and the nature of the property-by-property
impairment test is complex. As a result, it is not possible to provide a
reasonable sensitivity analysis of the impact that a reserve estimate decrease
would have on impairment. No material downward revisions to our reserves are
anticipated.
ASSET RETIREMENT OBLIGATION
We recognize 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 we
will be required to retire tangible long term 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 term assets. 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. Amounts recorded for asset retirement obligations are subject to
uncertainty associated with the method, timing, and extent of future
retirement activities. Actual payments to settle the obligations may differ
from estimated amounts.
RECENT ACCOUNTING PRONOUNCEMENTS
On January 1, 2008, the Company will adopt the following CICA Handbook
Sections:
a. Section 3031, "Inventories" which replaces the existing standard. The
requirements include the consistent grouping of like assets and the
application of the first-in-first-out or weighted average cost
formula methodologies.

b. Section 1400, "General Standards of Financial Statement
Presentation" which requires assessing and disclosing the Company's
ability to continue as a going concern.

c. Section 3862, "Financial Instruments - Disclosures" and Section 3863,
"Financial Instruments - Presentation". These new standards will
require increased disclosure of financial instruments with particular
emphasis on the risks associated with recognized and unrecognized
financial instruments and how those risks are managed.

d. Section 1535, "Capital Disclosures", requiring disclosure of
information about an entity's capital and the objectives, policies,
and processes for managing capital.

The adoption of these standards is not expected to have a material impact
on the Company's consolidated financial statements.
On January 1, 2009 the Company will be required to adopt CICA Handbook
Section 3064, "Intangible Assets". The new section established standards for
the recognition, measurement, and disclosure of goodwill and intangible assets
and replaces the existing Handbook Section 3062, "Goodwill and Other
Intangible Assets" and Section 3450, "Research and Development Costs".
Intangible assets associated with the exploration and development of oil and
gas assets are specifically excluded under the new standard. The Company is
evaluating the implications of this adoption, but expects no material impact
on the consolidated financial statements.
On January 10, 2006, the CICA Accounting Standards Board ("AcSB") ratified
a new strategic plan that would see the convergence of Canadian Generally
Accepted Accounting Principles ("GAAP") with International Financial Reporting
Standards ("IFRS") within 5 years. In March 2007, the AcSB released an
"Implementation Plan for Incorporating IFRSs into Canadian GAAP", which
assumed a convergence date of January 1, 2011. The AcSB confirmed this date in
February 2008. The Company continues to monitor and assess the consequences of
convergence on the consolidated financial statements as they could have a
material impact.
RISK MANAGEMENT
Our operations are subject to risks inherent to the oil and natural gas
industry. We are exposed to financial risks including fluctuations in
commodity prices, currency exchange rates, interest rates, credit ratings, and
changing expenditure costs due to shifts in market conditions. We take
specific measures to manage these risks, particularly those impacting adjusted
cash flow from operations.
A more detailed discussion of risk factors is presented in our most recent
Annual Information Form, filed with securities regulatory authorities on or
before March 31, 2008 on www.sedar.com.
COMMODITY PRICE RISK MANAGEMENT
We enter into commodity price contracts to actively manage risk associated
with price volatility to protect adjusted cash flow from operations required
to fund our capital program. We use fixed price and costless collar contracts
as well as balancing physical and financial contracts in terms of volumes,
timing of performance, and delivery obligations to manage risk. Net open
positions may exist or may be established to take advantage of market
conditions. Net earnings for the year ended December 31, 2007, include
realized and unrealized loss of $1.6 million (2006 - $65.0 million gain) on
these transactions.
The following table outlines commodity hedge transactions in place at
December 31, 2007 together with transactions entered into subsequent to the
year end:
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