CALGARY, March 26 /CNW/ - Compton Petroleum Corporation (TSX - CMT, NYSE - CMZ) is pleased to report its financial and operating results for the year and quarter ended December 31, 2006.
2006 HIGHLIGHTS
- Reserve additions 42.2 million boe
(net of production),
20% increase
- Reserve value $3.3 billion, 8% DCF
- FD&A costs, $/boe
Excluding change in future capital $8.84 proved plus probable
$14.36 proved
Including change in future capital $13.56 proved plus probable
$18.45 proved
- 2006 Average Production (boe/d) 33,187 - 13% increase
- Production replacement 4.5 times
- Cash flow $256 million, $1.92/share F.D.
Strong Reserve and Production Growth
Total proved plus probable reserves rose 20% from the prior year to 249 million boe and were valued at $3.3 billion, 8% DCF. Total proved reserves at year end were 147 million boe, an increase of 17% from 2005. Proved producing reserves comprise 67% of total proved reserves. Total proved reserves account for 59% of the proved plus probable reserves.
Our 2006 production grew 13% to average 33,187 boe/day versus 29,424 boe/day in 2005. Ernie Sapieha, President and CEO, commented that "Compton's increase in low cost reserves and production growth are largely as a result of our continued successful drilling program and capital investment in facilities and infrastructure expansion. Our ten year compound annual growth rate on reserves is 35%, and we have never had any material revisions to our reserve reports."
Drilling Results
During 2006 Compton achieved reserve additions of 54.3 MMboe, before production, of reserve additions, primarily through the drill bit, at highly competitive finding and development costs. We successfully completed our 342 well drilling program, with a 94% success rate. We replaced 448% of our 2006 production at an all-in Finding, Development, and Acquisition cost ("FD&A") of $8.84/boe, excluding the change in future capital, or $13.56/boe, including change in future capital.
Of the 342 wells drilled in 2006, 86% were classified as development wells and 14% were classified as exploratory wells, compared to 80% and 20% respectively in 2005. The higher percentage of development wells in the current year reflects the increasing success of our oil and gas plays.
Revenue and Cash Flow
Although Compton experienced significant production gains, both revenue and cash flow declined by 4% and 8%, respectively, due to lower commodity prices, particularly natural gas. The negative effect of lower commodity prices on cash flow was reduced by realized gains of $36 million from risk management activities.
Property Dispositions
In December 2006, Compton entered into agreements for the sale of two minor non-core properties that generated net proceeds of $45.9 million, all of which were received in the first quarter of 2007. The effective dates of these sales were as of the year end, and accordingly, these properties are excluded from our December 31, 2006 reserve evaluation and report. Canadian GAAP requires we recognize the sales as at their closing dates in 2007 and Compton's 2006 financial results do not include these transactions. The following Financial Summary and The Liquidity and Capital Resources section of this Release reflect the pro forma effect of the receipt of the proceeds of $45.9 million as at December 31, 2006 consistent with the presentation of reserve information.
Additionally, the Company is pursuing the monetization of $25 million of production facilities that is expected to close in April 2007.
FINANCIAL SUMMARY
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Three Months Ended Dec. 31 Year Ended Dec. 31
($000s, except
per share
amounts) 2006 2005 % Change 2006 2005 % Change
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Gross revenue $127,902 $184,428 -31% $533,656 $557,879 -4%
Cash flow(1) $ 55,263 $ 89,640 -38% $256,305 $278,112 -8%
Per share
- basic $ 0.43 $ 0.71 -39% $ 2.01 $ 2.21 -9%
- diluted $ 0.42 $ 0.67 -37% $ 1.92 $ 2.11 -9%
Net earnings ($10,037) $ 38,106 -126% $127,426 $ 81,326 57%
Per share
- basic ($ 0.08) $ 0.30 -127% $ 1.00 $ 0.65 54%
- diluted ($ 0.08) $ 0.29 -128% $ 0.95 $ 0.62 53%
Operating
earnings $ 11,822 $ 33,413 -65% $ 65,168 $ 93,664 -30%
Capital
expenditures $525,874 $513,536 2%
Corporate debt $875,548 $597,656 46%
Pro forma Corporate
debt, after
dispositions(2) $829,679
Shareholders'
equity $734,124 $596,336 23%
Weighted
averages
shares (000s)
- basic 127,820 125,627
- diluted 133,626 131,667
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(1) The term "cash flow" should not be considered an alternative to, or
more meaningful than "cash flow from operating activities" as
determined in accordance with Canadian GAAP as an indicator of the
Company's financial performance. Compton's determination of cash flow
may not be comparable to that reported by other companies. The other
items required to arrive at cash flow from operating activities are
considered to be corporate charges.
(2) See Property Disposition discussion above.
OPERATING SUMMARY
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Three Months Ended Dec. 31 Year Ended Dec. 31
(6:1 boe
conversion) 2006 2005 % Change 2006 2005 % Change
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Average daily
production
Natural gas
(MMcf/d) 148 133 11% 142 131 8%
Liquids (light
oil & ngls)
(bbls/d) 8,600 8,879 -3% 9,516 7,646 24%
Total oil
equivalent
(boe/d) 33,245 31,042 7% 33,187 29,424 13%
Average realized
prices
Natural gas
($/Mcf) $ 6.52 $ 11.20 -42% $ 6.37 $ 8.42 -24%
Liquids
($/bbl) $ 49.46 $ 57.99 -15% $ 58.53 $ 56.04 4%
Total oil
equivalent
($/boe) $ 41.82 $ 64.58 -35% $ 44.05 $ 51.95 -15%
Field operating
netback
($/boe) $ 27.03 $ 38.88 -30% $ 28.16 $ 31.46 -10%
Cash flow
netback
($/boe) $ 19.38 $ 31.46 -38% $ 21.52 $ 25.76 -16%
Undeveloped land
Gross acres 980,179 971,317 1%
Net acres 798,192 738,954 8%
Average working
interest 81% 76% 7%
Reserves (Mboe)
Proved oil
equivalent 147,218 125,960 17%
Proved plus
probable oil
equivalent 248,755 206,671 20%
Proved plus
probable gas
equivalent, Tcfe 1.492 1.240
Proved reserve
life index
(years) 12 12
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OPERATIONS
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 Sedimentary 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 resource plays that include the Basal Quartz sands at Hooker, the stacked, thrusted Foothills Upper Cretaceous Belly River play at Callum in the south, and the Gething/Rock Creek sands at Niton in central Alberta. Compton's third core area, located in the Peace River Arch, is comprised of two conventional oil properties at Worsley and Cecil.
SHALLOW GAS
The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow gas zones cover more than 1,000 sections of Compton held land in southern Alberta. The entire 800 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 2006 we drilled 183 wells through the Edmonton Horseshoe Canyon Group targeting the Belly River section, for a total of 550 wells drilled as of year end. This allows for numerous recompletion and commingling opportunities. 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. Three key elements - one industry driven, the others Compton driven - have recently come together to make this model possible.
1. In July 2006, the Alberta Energy and Utilities Board ("EUB")
announced a downspacing initiative for zones above the Mannville,
including the Plains Belly River, that is intended to see standard
well spacing increase from one to four wells per section. Reduced
spacing is critical in the development of our unconventional
reservoirs that require greater well density for more efficient
resource development and recognition. With our current land
holdings, this new regulation adds over 4,000 locations to our
drilling inventory. Additional to downspacing, we now have the
ability to maximize production through commingling Belly River with
the Edmonton Horseshoe Canyon zones. The EUB released a directive for
commingling on October 31, 2006 that allows for concurrent production
of Belly River and Edmonton/Horseshoe Canyon Coals as a single
procedure, following minimal application.
2. We are in a unique position of having a large 3D seismic data base,
totaling 2,140 km(2) (826 mi(2)) as at December 31, 2006, with an
additional 427 km(2)(165 mi(2)) as of the first quarter of 2007. The
use of 3D seismic is key in positioning downspace well locations that
maximize production and reduce capital requirements.
3. In recent years, we have focused efforts on establishing and
expanding infrastructure and facilities in our core areas. We
currently have 466 km of low pressure pipelines. Years in the making,
this intricate system of compressors and low pressure pipeline
gathering systems covers a large portion of our existing land base.
2006 saw Compton take advantage of new EUB downspacing and commingling initiatives to successfully test our seismic modeling and complete infrastructure development. In 2006 we drilled 25 sections to as many as four wells per section. Preliminary results on the second to fourth wells in each section have generally exceeded the first drill in the section. As a result, we will ramp up our Belly River/Edmonton drilling program in 2007 to grow production from these zones. Late in the fourth quarter of 2006, we tied in 21 Belly River/Coalbed Methane wells. An additional 21 wells are projected to be tied in during the first and second quarters of 2007.
In 2006, we expanded our southern Alberta shallow gas compression capability to 105 mmcf/d.
In 2007, we have budgeted 215 shallow gas wells targeting the Plains Belly River/Edmonton group. In select areas, drilling is planned in groups of 20 to 40 wells to capitalize on downspacing and associated cost efficiencies. As well, we have 69 hybrid coal bed methane and sand gas wells. Low pressure gathering and compression facilities are largely in place in the area to assist in reducing on-stream times. It is our intent that production from these multi-zone wells will be commingled for optimal production results. Going forward, in 2008 and beyond, we plan to accelerate drilling and associated production through large well counts plus tie-ins to existing facilities. A 4,000 well drilling inventory makes this possible.
DEEP GAS
Compton has three deep gas resource plays: the Basal Quartz sands at Hooker, the stacked, thrusted, Belly River play at Callum in southern Alberta, and the Gething/Rock Creek sands at Niton in central 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. This play covers an extensive area of approximately 124,800 net acres, with our working interest averaging 85%. Current production extends over five townships, and in 2006, we drilled 18 wells at Hooker, testing the aerial extent of the play. The edges of the Hooker pool have yet to be defined.
In 2006, the total Hooker infrastructure system was expanded to 65 mmcf/d.
The key to maximizing production at Hooker, or any Deep Basin play, is downspacing. Currently, Compton's drilling is approved for two wells per section, although the majority of the 120 gas wells drilled to date in this area are on single section spacing. Our engineering and geological models indicate that a minimum four wells per section is required for optimal production here. As such, we have made an application to the EUB to reduce space one section in the pool to four wells per section on a pilot basis, with two other sections pending. We will be drilling approximately 20 Basal Quartz wells during 2007. The majority of these wells are infill locations planned for the second half of 2007, once downspacing is approved.
Callum
Our Callum property consists of a series of overpressured, thrusted, low permeability Belly River sands in the foothills of southern Alberta. With the acquisition of our partner's interest in 2006, we now hold a 100% interest in 70,400 acres (110 sections) of land on trend. A total of 13 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 2006, we drilled five exploratory wells, all of which encountered multiple sands. The wells were cased and extensively cored. The two most recent wells, drilled during the third quarter of 2006, are two and 15 miles south of current production, respectively, and following laboratory analysis of the cores, these wells will be appropriately completed.
Compton is conducting environmental studies on four additional pads prior to submitting the required license applications. We are working with all stakeholders in the area to proceed in an environmentally responsible manner and we remain committed to minimizing the impact of our activities. To this end, drilling in this area is based on one drill pad per section.
In 2007, we plan to drill two exploratory wells at Callum. We remain confident in pursuing this challenging and technically complex play. Our activities in the area will increase once regulatory well licensing issues are resolved.
Niton
The Niton area in central Alberta, 150 miles west of Edmonton, is in the Alberta Deep Basin. Our main targets are the Jurassic Rock Creek and Cretaceous Gething, analogous to the Hooker pool in southern Alberta. Proprietary exploration, development, and operations knowledge gained in southern Alberta has resulted in accelerated growth of this core area. We have assembled 156,800 (128,000 net) acres of land in this multi-target area. In 2006, 31 wells were drilled with results exceeding expectations.
Compton undertook a major facility project at Niton during 2006. At our McLeod River 7-34-54-14W5 gas plant all major equipment was purchased in 2006 to prepare for a March 31, 2007 completed gas plant expansion from 18 to 23 mmscf/d processing capacity.
In 2007, we plan to drill 39 wells in this area.
Worsley/Cecil
Located in the Peace River Arch, the Worsley and Cecil properties produce from the Triassic Charlie Lake Formation, a layered sandy Carbonate. These two properties comprise the majority of Compton's conventional oil production.
For 2006 the Worsley pool was the focus of the Company's operations in this area. We drilled 27 Charlie Lake oil wells in 2006, for a total of 118 vertical and 12 horizontal wells in the area.
The horizontal drilling program at Worsley has produced very positive results. One horizontal well replaces three vertical wells, at a cost saving of $1.2 million. Horizontal wells allow successful drilling and production in oil bearing rock layers where underlying water is recognized.
In 2005, the Company initiated a waterflood program in this area that is projected to increase the ultimate recovery factor for the pool to 25% from 15% on primary depletion. A total of eight wells have been converted to injectors.
The Worsley gas plant was successfully expanded with the installation of a 15 mmcf/d amine unit in the first quarter of 2007. The plant is now capable of processing 13 mmcf/d.
2007 will focus on horizontal drilling and definition of pool boundaries.
OPERATING RESULTS
UNDEVELOPED LAND
In 2006, we continued to maintain a dominant land position in our core areas. The Company's total net land inventory increased 12% in 2006, with acquisitions occurring primarily in the southern and central Alberta core areas. Net undeveloped land increased 8% from the prior year. For 2006 we had an 81% average working interest in our undeveloped land base, as opposed to 76% in 2005, reflecting Compton's strategy to establish high ownership levels and control of operations.
Land Summary
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Undeveloped Acres Total Acres
Area Gross Net Gross Net
-------------------------------------------------------------------------
Southern Alberta 495,854 473,444 907,134 822,966
Central Alberta 284,603 206,617 581,016 340,254
Peace River Arch 102,400 71,775 196,960 119,188
Northern Alberta 41,888 15,572 68,769 23,207
Other 55,434 30,784 84,984 33,866
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December 31, 2006 total 980,179 798,192 1,838,863 1,339,481
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December 31, 2005 total 971,317 738,954 1,709,982 1,195,792
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During 2007, we plan to continue to invest in the future and expand in our core areas. Our 2007 budget includes $39 million directed towards land acquisitions and seismic surveys in our major operating areas.
DRILLING ACTIVITY
We drilled 342 gross (274 net) wells in 2006 with a 94% success rate, compared with 392 gross (334 net) wells drilled in 2005.
Of the 342 wells drilled in 2006, 84% were classified as development wells and 16% were classified as exploratory wells, compared to 80% and 20% respectively in 2005. 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 184 1 4 189 167 98%
Central Alberta 56 9 5 70 47 93%
Peace River Arch 11 46 11 68 46 84%
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251 56 20 327 260 94%
Standing, cased wells 15 14
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2006 Total 342 274
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2005 Total 261 114 17 392 334
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RESERVES
For the year ended December 31, 2006, Netherland, Sewell & Associates, Inc. ("NSAI") independently evaluated 94% of Compton's reserves and audited the Company's internal evaluation of the remaining 6%.
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 our 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.
In December 2006, Compton entered into agreements for the sale of two minor, non-core properties that generated net proceeds of $45.9 million, all of which were received in the first quarter of 2007. The effective dates of these sales were as of year end. Accordingly, we excluded these properties from the December 31, 2006 reserve report and the calculation of finding, development, and acquisition costs. The impact of these sales on corporate indebtedness as at December 31, 2006 is set out in the Liquidity and Capital Resource section of Management's Discussion and Analysis in this Annual Report.
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, 2006 (Mbbl) (Mbbl) (Bcf) (Bcf) (Mbbl) (Mbbl)
-------------------------------------------------------------------------
Proved
Developed producing 15,065 13,985 443 362 8,021 5,734
Developed non-producing 1,714 1,592 69 57 1,152 795
Undeveloped 3,220 2,752 175 146 2,016 1,473
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Total proved 19,999 18,329 687 565 11,189 8,002
Probable 9,234 7,884 502 419 7,879 5,759
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Total proved plus
probable 29,233 26,213 1,189 984 19,068 13,761
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2005 total proved plus
probable 28,493 25,488 954 788 16,628 12,070
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-----------------------------------------------------------
Sulphur Total
Gross Net Gross Net
As at December 31, 2006 (Mlt) (Mlt) (Mboe) (Mboe)
-----------------------------------------------------------
Proved
Developed producing 1,392 1,237 98,337 81,302
Developed non-producing 50 40 14,364 11,893
Undeveloped 115 96 34,517 28,693
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Total proved 1,557 1,373 147,218 121,888
Probable 714 603 101,537 84,007
-----------------------------------------------------------
Total proved plus
probable 2,271 1,975 248,755 205,895
-----------------------------------------------------------
-----------------------------------------------------------
2005 total proved plus
probable 2,545 2,221 206,672 171,031
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(1) Numbers may not add due to rounding.
In 2006, we added 42.2 MMboe, after production, to our proved plus
probable reserves primarily through the drill bit. Total proved plus probable
reserves increased 20% from the prior year to 249 MMboe.
Our total proved reserve base is comprised of 78% natural gas and 22%
liquids. Proved producing reserves comprise 67% of total proved reserves,
while total proved reserves account for 59% of the proved plus probable
reserves. We have a 12 year proved reserve life index.
ii) Net Present Value of Reserves - Forecast Prices and Costs(1)
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Future net revenue before income
taxes(1) discounted at a rate of
----------------------------------
($millions) 0% 8% 10%
-------------------------------------------------------------------------
Proved
Producing $ 2,774 $ 1,446 $ 1,302
Non-producing 546 274 242
Undeveloped 1,072 438 363
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Total proved $ 4,392 $ 2,158 $ 1,907
Probable 3,241 1,154 938
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Total proved plus probable $ 7,633 $ 3,312 $ 2,845
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2005 proved plus probable $ 6,199 $ 2,842 $ 2,493
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(1) Pricing assumptions are the average of four major Canadian oil and
gas evaluation firms. Numbers may not add due to rounding.
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 (net after royalties) - Forecast Prices and
Costs
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Crude Oil, NGLs, and Sulphur Natural Gas
-------------------------------------------------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
(Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf)
-------------------------------------------------------------------------
December 31, 2005 28,731 11,047 39,778 449,790 337,719 787,509
Extensions 916 1,033 1,949 27,309 20,086 47,395
Improved recovery 1,027 1,069 2,096 50,394 125,247 175,641
Technical revisions (667) 620 (47) 75,206 (84,481) (9,275)
Discoveries 317 54 371 4,312 4,441 8,753
Acquisitions 222 437 659 11,331 16,982 28,313
Dispositions (229) (14) (243) (12,939) (1,426) (14,365)
Production (2,613) 0 (2,613) (40,300) 0 (40,300)
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December 31, 2006 27,704 14,246 41,950 565,102 418,568 983,671
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FINDING & DEVELOPMENT COSTS
Our 2006 reserve report was reduced by property sales that closed subsequent to year end. Accordingly, Finding, Development and Acquisition ("FD&A") costs have been calculated giving effect to the net proceeds realized on the dispositions. It should be noted that the aggregate of the exploration and development costs incurred in 2006 and the change during the year in estimated future development costs, generally will not reflect total F&D costs related to reserves additions for the year.
-------------------------------------------------------------------------
3 Year
FD&A costs ($/boe) 2006 2005 2004 Average
-------------------------------------------------------------------------
Including future capital
Proved $18.45 $15.42 $14.91 $16.37
Proved plus probable $13.56 $13.02 $13.19 $13.19
Excluding future capital
Proved $14.36 $12.84 $13.87 $13.61
Proved plus probable $ 8.84 $ 7.05 $ 8.51 $ 7.97
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FINANCIAL REVIEW
CASH FLOW FROM OPERATIONS AND NET EARNINGS
-------------------------------------------------------------------------
Years ended December 31, 2006 2005 2004
-------------------------------------------------------------------------
Cash flow from operations(1)
($000s) $ 256,305 $ 278,112 $ 177,131
Per share: basic $ 2.01 $ 2.21 $ 1.51
diluted $ 1.92 $ 2.11 $ 1.43
Net earnings ($000s) $ 127,426 $ 81,326 $ 63,633
Per share: basic $ 1.00 $ 0.65 $ 0.54
diluted $ 0.95 $ 0.62 $ 0.51
-------------------------------------------------------------------------
(1) Cash flow from operations represents net earnings before depletion
and depreciation, future income taxes, and other non-cash expenses.
Cash flow from operations in 2006 was $256.3 million as compared to $278.1 million in 2005, with lower commodity prices more than offsetting production gains. The negative effect of lower commodity prices on cash flow was reduced by realized gains of $36 million resulting from risk management activities during the year.
While cash flow from operations in 2006 declined from the prior year's level, net earnings of $127.4 million in 2006 actually increased from 2005 due to the positive effect of future income tax recoveries resulting from reductions in statutory corporate income tax rates and the unrealized gains from risk management activities. The impact of these items is summarized in the schedule of Operating Earnings presented below.
OPERATING EARNINGS
Operating earnings is a non-GAAP measure that adjusts net earnings for non-operating items that Management believes reduce the comparability of our underlying financial performance between periods. The following Summary of Operating Earnings reconciles Net Earnings, determined in accordance with GAAP, to Operating Earnings and has been prepared to provide readers with information that is more comparable between periods.
SUMMARY OF OPERATING EARNINGS
-------------------------------------------------------------------------
Years ended December 31,
($000s, except per share amounts) 2006 2005 2004
-------------------------------------------------------------------------
Net earnings, as reported 127,426 $ 81,326 $ 63,633
Non-operational items, after tax
Unrealized foreign exchange (gain) (550) (6,339) (11,821)
Unrealized risk management
(gain) loss (18,027) 6,345 1,338
Stock-based compensation 5,974 3,682 2,094
Tender costs on repurchase of
9.90% notes - 14,414 -
Future income tax recovery due to
income tax rate reductions (49,655) (5,764) (8,359)
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Operating earnings $ 65,168 $ 93,664 $ 46,885
Per share: basic $ 0.51 $ 0.75 $ 0.40
diluted $ 0.49 $ 0.71 $ 0.38
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REVENUE
Revenue in 2006 decreased 4% as result of a 15% decrease in realized
prices, despite a 13% increase in production volumes.
-------------------------------------------------------------------------
Years ended December 31, 2006 2005 2004
-------------------------------------------------------------------------
Average production
Natural gas (mmcf/d) 142 131 123
Liquids (bbls/d) 9,516 7,646 6,330
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Total (boe/d) 33,187 29,424 26,876
Benchmark prices
NYMEX (U.S.$/mmbtu) $ 7.26 $ 8.55 $ 6.09
AECO ($/GJ)
Monthly index $ 6.21 $ 8.04 $ 6.44
Daily index $ 6.19 $ 8.27 $ 6.18
WTI (U.S.$/bbl) $ 66.22 $ 56.56 $ 41.40
Edmonton par ($/bbl) $ 72.77 $ 68.72 $ 52.37
Realized prices
Natural gas ($/mcf) $ 6.37 $ 8.42 $ 6.46
Liquids ($/bbl) 58.53 56.04 43.21
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Total ($/boe) $ 44.05 $ 51.95 $ 39.82
Revenue ($000s)
Natural gas $ 330,349 $ 401,468 $ 291,565
Liquids 203,307 156,411 100,094
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Total $ 533,656 $ 557,879 $ 391,659
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SUMMARY OF REVENUE INCREASES FROM PRODUCTION AND PRICING
-------------------------------------------------------------------------
Natural Gas Liquids Total
($000s) Revenue Revenue Revenue
-------------------------------------------------------------------------
Reported 2005 revenue $ 401,468 $ 156,411 $ 557,879
Increase in production volumes 26,427 39,951 66,378
Change in prices (97,546) 6,945 (90,601)
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Reported 2006 revenue $ 330,349 $ 203,307 $ 533,656
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Overall production in 2006 rose 13% from the prior year. Natural gas volumes increased 8%, while liquids production increased 24% over 2005 volumes. The growth in liquids production is largely the result of our ongoing conventional crude oil exploration and development program at Cecil and Worsley. Unfortunately, the year over year decline in North American natural gas prices overwhelmed the growth in production volumes.
We market the majority of our natural gas production through a combination of daily and monthly indexed contracts and aggregator contracts. During 2006, approximately 11% of our natural gas production remained committed to longer term aggregator contracts which realized a price that was, on average, $1.31/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 in funding our capital expenditure programs. This activity is fully disclosed in the Risk Management and Financial Instrument sections of this MD&A. At present approximately 30% of our production is currently hedged through to October 31, 2007. Depending on market conditions, we may enter into additional hedges throughout the year with a goal of hedging approximately 50% of future production volumes before royalties.
ROYALTIES ------------------------------------------------------------------------- Years ended December 31, ($000s, except where noted) 2006 2005 2004 ------------------------------------------------------------------------- Crown royalties $ 100,230 $ 105,827 $ 75,477 Other royalties 23,447 26,890 17,939 ------------------------------------------------------------------------- Net royalties $ 123,677 $ 132,717 $ 93,416 Percentage of revenues 23.2% 23.8% 23.9% -------------------------------------------------------------------------
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 2006, as a percentage of revenue, decreased slightly from 2005 as a result of lower commodity prices in 2006.
We anticipate 2007 royalty rates will remain relatively consistent with prior years; however, this could change as the Alberta government has stated its intent to review the current royalty regime.
OPERATING EXPENSES ------------------------------------------------------------------------- Years ended December 31, 2006 2005 2004 ------------------------------------------------------------------------- Operating expenses ($000s) $ 95,462 $ 66,802 $ 55,655 Operating expenses per boe ($/boe) $ 7.88 $ 6.22 $ 5.66 -------------------------------------------------------------------------
Cost pressures associated with an industry operating at maximum capacity resulted in increased operating costs during 2006 particularly when measured on a boe basis. Specific increases of note include salaries for field staff and contract operators and rising electricity prices. Additionally, liquids production increased 24% during the year as compared to the 8% increase in natural gas volumes. As the 2006 per unit operating expenses for liquids were approximately $3.60 per boe greater than natural gas per unit costs, the overall cost per boe rose to reflect the change in the oil/natural gas production mix.
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 2007 operating costs, on a unit of production basis, will remain similar to those experienced in 2006.
TRANSPORTATION EXPENSES ------------------------------------------------------------------------- Years ended December 31, 2006 2005 2004 ------------------------------------------------------------------------- Transportation costs ($000s) $ 12,564 $ 10,858 $ 8,595 Transportation costs per boe ($/boe) $ 1.04 $ 1.01 $ 0.87 -------------------------------------------------------------------------
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.
While higher transportation costs in 2006 resulted from a combination of increased trucking costs associated with additional crude oil production and surcharges associated with high fuel costs, the cost per boe remained relatively constant to the prior year.
GENERAL AND ADMINISTRATIVE EXPENSES ------------------------------------------------------------------------- Years ended December 31, ($000s, except where noted) 2006 2005 2004 ------------------------------------------------------------------------- General and administrative expenses $ 38,321 $ 34,638 $ 20,182 Capitalized general and administrative expenses (9,625) (11,158) (2,982) Operator recoveries (2,465) (2,257) (1,985) ------------------------------------------------------------------------- Total general and administrative expenses $ 26,231 $ 21,223 $ 15,215 General and administrative per boe ($/boe) $ 2.17 $ 1.98 $ 1.55 -------------------------------------------------------------------------
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 2006. Other increases included insurance and costs associated with ongoing regulatory compliance requirements. During 2006, we incurred expenses totaling $1.1 million relating to compliance requirements pursuant to the U.S. Sarbanes-Oxley Act of 2002 and Canadian Multilateral Instrument 52-109.
INTEREST AND FINANCE CHARGES ------------------------------------------------------------------------- Years ended December 31, ($000s, except where noted) 2006 2005 2004 ------------------------------------------------------------------------- Interest on bank debt, net $ 15,356 $ 11,520 $ 9,662 Interest on Senior Notes 35,880 20,912 21,281 ------------------------------------------------------------------------- Interest expense 51,236 32,432 30,943 Finance charges 2,839 2,519 2,790 ------------------------------------------------------------------------- Total interest and finance charges $ 54,075 $ 34,951 $ 33,733 ------------------------------------------------------------------------- Total interest and finance charges per boe ($/boe) $ 4.47 $ 3.25 $ 3.44 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted average annual debt ($000s, except where noted) 2006 2005 ------------------------------------------------------------------------- Bank debt $ 254,476 $ 228,381 Effective interest rate 5.60% 4.23% Senior notes (US$) $ 412,802 $ 179,583 Effective interest rate 7.64% 9.50% -------------------------------------------------------------------------
Interest expenses relating to bank debt in 2006 increased from the prior year as a result of increased borrowings incurred to fund our 2006 capital program and overall floating interest rate increases. The decrease in the effective interest rate incurred on the Senior Notes resulted from the repurchase of the 9.90% Senior Notes issued in 2002 with a portion of the proceeds of the 7.625% Senior Notes issued in 2005. Our debt instruments are more fully described in Notes 5 and 6 to our consolidated financial statements.
TENDER COSTS ------------------------------------------------------------------------- Years ended December 31, ($000s) 2005 ------------------------------------------------------------------------- Premium payment $ 7,814 Consent solicitation fee 5,883 Reduction of deferred financing charges on repayment of 9.90% Senior Notes 7,053 ------------------------------------------------------------------------- Total tender costs $ 20,750 -------------------------------------------------------------------------
In November 2005, we completed a tender offer and consent solicitation to purchase our 9.90% Senior Notes due in 2009. 96% of the Senior Notes were tendered to the offer and purchased by the Company. The unamortized portion of deferred financing charges relating to the tendered portion of the 9.90% Senior Notes is included in tender costs. The remaining 4% of the Notes were purchased in 2006 pursuant to the call option provisions and no additional tender costs were incurred.
NETBACKS ------------------------------------------------------------------------- Years ended December 31, ($/boe) 2006 2005 2004 ------------------------------------------------------------------------- Realized price $ 44.05 $ 51.95 $ 39.82 Commodity hedge gain (loss) 3.24 (0.90) (0.93) Royalties (10.21) (12.36) (9.50) Operating expenses (7.88) (6.22) (5.66) Transportation (1.04) (1.01) (0.87) ------------------------------------------------------------------------- Field operating netback $ 28.16 $ 31.46 $ 22.86 ------------------------------------------------------------------------- General and administrative (2.17) (1.98) (1.55) Interest (4.47) (3.25) (3.43) Current taxes - (0.47) (0.28) ------------------------------------------------------------------------- Cash flow netback $ 21.52 $ 25.76 $ 17.60 -------------------------------------------------------------------------
RISK MANAGEMENT
Our financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/U.S. 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.
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 fair values of the 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.
The mark-to-market fair value method of accounting for financial instruments and the recognition of unrealized gains and losses in determining earnings has introduced an additional element of volatility into our earnings that may not be particularly meaningful in assessing our financial performance.
Risk management gains and losses recognized in 2006 are outlined below. ------------------------------------------------------------------------- Year ended December 31, ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Commodity contracts Realized (gain) loss $ (39,217) $ 9,663 $ 9,151 Unrealized (gain) loss (25,775) 5,136 (1,985) Foreign currency contracts Realized (gain) (1,405) - - Cross currency interest rate swap Realized loss (gain) 4,423 (532) (2,522) Unrealized (gain) loss (1,747) 5,035 4,164 ------------------------------------------------------------------------- Total risk management (gain) loss $ (63,721) $ 19,302 $ 8,808 ------------------------------------------------------------------------- Realized (gain) loss $ (36,199) $ 9,131 $ 6,629 Unrealized (gain) loss (27,522) 10,171 2,179 ------------------------------------------------------------------------- Total risk management (gain) loss $ (63,721) $ 19,302 $ 8,808 ------------------------------------------------------------------------- A. DEPLETION AND DEPRECIATION ------------------------------------------------------------------------- Years ended December 31, 2006 2005 2004 ------------------------------------------------------------------------- Total depletion and depreciation ($000s) $ 143,057 $ 105,504 $ 82,554 Depletion and depreciation per boe ($/boe) $ 11.81 $ 9.82 $ 8.39 -------------------------------------------------------------------------
Accelerated capital programs and competition throughout the oil and gas industry during the year 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.
The Canadian/U.S. exchange rate increased marginally to one Canadian Dollar being equal to U.S.$0.8581 as at December 31, 2006, from one Canadian Dollar being equal to U.S.$0.8577 at December 31, 2005, resulting in the recognition of a $1 million foreign exchange gain in 2006.
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 $62 million of the accumulated unrealized foreign exchange gains in 2005 that had previously been recognized with the strengthening of the Canadian dollar subsequent to the note issuance.
STOCK-BASED COMPENSATION ------------------------------------------------------------------------- Years ended December 31, 2006 2005 2004 ------------------------------------------------------------------------- Options granted (000s) 2,228 2,930 2,549 Weighted average fair value of options granted ($/share) $ 6.90 $ 5.45 $ 3.70 Stock-based compensation expense recognized ($000s) $ 10,488 $ 5,903 $ 3,410 -------------------------------------------------------------------------
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 that currently exists within the industry, we implemented an Employee Retention Program in July 2006 for our existing employees, excluding Officers and Directors. Under the program, and contingent upon various conditions existing on July 1, 2007, including the market value of the Company's shares, we may incur additional compensation expense to a maximum amount of $4.2 million. For the year ended December 31, 2006, we have accrued $1.4 million 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
Current taxes decreased to nil in 2006 from $5 million in 2005 (2004 - $3 million) due partially to the elimination of federal capital tax effective January 1, 2006. Current taxes in 2005 also 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 taxes in 2006 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. The federal tax rate is to be reduced from 22.1% to 19% over a 3 year period starting January 1, 2008 and the Alberta tax rate was reduced from 11.5% to 10.0% effective April 1, 2006.
CORPORATE TAX RATES ------------------------------------------------------------------------- Years ended December 31, 2006 2005 2004 ------------------------------------------------------------------------- Statutory rate 34.5% 37.6% 38.6% Effective rate (2.8)% 39.5% 35.0% -------------------------------------------------------------------------
A reconciliation of our effective tax rate to the statutory rate may be found in Note 15a 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, 2007 ($000s) Deduction
-------------------------------------------------------------------------
Canadian exploration expense $ 169,735 100%
Canadian development expense 421,500 30%
Canadian oil and natural gas property expense 260,146 10%
Undepreciated capital cost and financing costs 318,105 ~25%
-------------------------------------------------------------------------
Total $1,169,486
-------------------------------------------------------------------------
A significant portion of our taxable income is generated by a wholly owned partnership. Consolidated earnings before income taxes include $259 million (2005 - $263 million) of partnership earnings that will be included in the following year's income for income tax purposes. Future income taxes include $83 million (2005 - $94 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.
CAPITAL EXPENDITURES
SUMMARY OF CAPITAL EXPENDITURES
-------------------------------------------------------------------------
Years ended December 31, 2006 2005 2004
-------------------------------------------------------------------------
($000s) % ($000s) % ($000s) %
-------------------------------------------------------------------------
Drilling and
completions $294,197 60 $318,502 66 $175,003 62
Land and seismic 59,905 12 55,469 11 38,326 14
Facilities 137,409 28 109,729 23 68,861 24
-------------------------------------------------------------------------
Sub-total 491,511 100 483,700 100 282,190 100
Acquisitions and
divestments, net 34,394 28,575 22,825
-------------------------------------------------------------------------
Sub-total 525,905 512,275 305,015
MPP (31) 1,261 11,386
-------------------------------------------------------------------------
Total capital
expenditures $525,874 $513,536 $316,401
-------------------------------------------------------------------------
Capital spending in 2006 was directed towards the continued development of our core natural gas resource plays in southern and central Alberta and our conventional oil play in the Peace River Arch.
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 will also affect this comparison, this represents 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 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 relating to equipment and facilities. This spending should allow us to place new production on-stream more quickly in 2007.
Consistent with the focus on our natural gas resource plays, we expanded our land position and working interests in core areas through a number of acquisitions at a total cost of $34.4 million.
To assist in funding our capital programs, we entered into agreements for the divestment of two minor non-operated properties prior to year end. Net proceeds of $45.9 million relating to these divestments were received subsequent to December 31, 2006 and have not been recognized in 2006 net acquisition and divestment. These funds were redeployed in the ongoing development of our resource plays and we plan to continue this strategy of capital redeployment in the future.
With the current slow-down in industry activity, we are beginning to see evidence of a reduction in the cost of certain goods and services. Costs are expected to moderate over the year in select areas which combined with our increased emphasis on capital discipline and cost control should have an overall positive effect on 2007 capital efficiencies.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------------------------------------------------
As at December 31, 2006 Pro
($000s, except where noted) forma(3) 2006 2005 2004
-------------------------------------------------------------------------
Working capital deficiency(1) $(24,706) $ 21,163 $ 62,116 $ 603
Bank debt 330,000 330,000 177,900 220,000
Senior term notes 524,385 524,385 357,640 198,594
-------------------------------------------------------------------------
Total indebtedness $829,679 $875,548 $597,656 $419,197
Capital stock $213,992 $231,992 $226,444 $135,526
Contributed surplus 16,974 16,974 9,173 3,840
Retained earnings 485,158 485,158 360,719 284,712
-------------------------------------------------------------------------
Shareholders' equity $734,124 $596,336 $424,078
Debt to cash flow from
operations(2) 3.2 3.4 2.2 2.4
Debt to book capitalization 53% 54% 50% 50%
Debt to market capitalization 38% 39% 22% 25%
-------------------------------------------------------------------------
(1) Excludes unrealized risk management items net of related future
income taxes.
(2) Based on trailing 12 month cash flow from operations.
(3) In December 2006, Compton entered into agreements for the sale of two
minor, non-core properties that generated net proceeds of
$45.9 million, all of which were received in the first quarter of
2007. The effective dates of these sales were as of year end.
Accordingly, we excluded these properties from the December 31, 2006
reserve report, the details of which are set out in the Annual
Information Form and elsewhere in the Annual Report. Canadian
Generally Accepted Accounting Principles require that we recognize
the transactions as at dates of closing in 2007. The pro forma
numbers presented above reflect the effect of the receipt of the net
proceeds of $45.9 million as at December 31, 2006, consistent with
the presentation of reserves data as set out in the Annual
Information Form.
In November 2006, we expanded our banking syndicate adding four additional banks including several U.S. based banking institutions. Concurrent with the increase in syndicate members, we increased our authorized senior secured facilities to $500 million consistent with the Company's borrowing base. The terms and conditions of the increased facilities remain the same as those established upon renewal of the facilities in July 2006. Our borrowing base is determined based upon year end reserves. With the increase in 2006 reserves over 2005, we anticipate the borrowing base will increase. We do not, however, expect to request an increase in our authorized credit facilities at this time.
Our corporate debt is structured to provide us with financial flexibility. Of our existing debt, 61% 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 2007 capital program.
During the fourth quarter of 2006, we entered into agreements for the sale of two minor, non-core properties. The sales of these properties were recorded in 2007 concurrent with the closing of sales. We are also pursuing the monetization of $25 million of production facilities that are expected to close in early April 2007. The sale of additional non-core properties and certain major conventional oil properties remains a potential source of funds for the continued development of our overall natural gas resource play strategy.
We believe internally generated cash flow from operations, proceeds from property dispositions, and funds available through our expanded credit facilities will be more than sufficient to fund our planned 2007 capital program, while still maintaining an appropriate capital structure.
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, 2006.
-------------------------------------------------------------------------
Payments Due by Period
Less than After
($000s) 1 year 1-3 years 4-5 years 5 years
-------------------------------------------------------------------------
Operating leases $ 3,737 $ 6,211 - -
Office facilities $ 3,509 $14,523 $ 9,600 $24,000
MPP partnership distributions $ 9,172 $12,229 - -
-------------------------------------------------------------------------
Total $16,418 $32,963 $ 9,600 $24,000
-------------------------------------------------------------------------
We have the ability and the intention to extend the term of our bank borrowings and therefore repayment of the facility is not included in the schedule of contractual obligations above.
OUTLOOK AND GUIDANCE FOR 2007
Consistent with general industry thinking, we are of the opinion that natural gas prices will strengthen significantly during 2007. We are also of the opinion that the cost of specific goods and services will moderate during the year.
In the interim, we believe it prudent to move forward with a relatively moderate capital spending program. During 2007, the majority of our activities will focus on the continued development and delineation of our natural gas resource plays. We will concentrate on development drilling and the acceleration of on-stream timing with a view to production growth. At the same time, increased emphasis will be placed on capital discipline and efficiency. Equally important is our need to increase our complement of qualified personnel for the expansion of operations necessary to realize on our opportunities in an efficient manner. We view the current reduction in industry activity as an opportunity to attract additional staff in preparation for increased drilling programs in the last half of 2007 and into 2008.
The following section summarizes our plans and guidance for 2007.
SUMMARY OF 2007 GUIDANCE
-------------------------------------------------------------------------
2007 Budget Range
-------------------------------------------------------------------------
Capital expenditures ($millions) $375
Gross wells 330
Average production - total boe/d 37,000 to 38,000
Cash flow from operations ($millions) $310 to $320
-------------------------------------------------------------------------
Our 2007 projected cash flow from operations is based upon the following
pricing assumptions:
-------------------------------------------------------------------------
Benchmark Realized
-------------------------------------------------------------------------
Natural gas AECO Cdn $7.30/GJ Cdn $7.50/mcf
Crude oil ($/bbl) WTI U.S. $62.00/bbl Cdn $60.00/bbl
-------------------------------------------------------------------------
The average Canadian/U.S. exchange rate is budgeted at $0.89 U.S. (equal sign) $1.00
Cdn.
CASH FLOW SENSITIVITIES FOR 2007
-------------------------------------------------------------------------
($millions) Change in Cash Flow
-------------------------------------------------------------------------
Change of Cdn $0.25/mcf in the benchmark AECO
natural gas price $12
Change of U.S. $1.00/bbl in the benchmark WTI oil price $ 2
-------------------------------------------------------------------------
In the event of significant decreases in commodity prices, increases in
exploration costs, or an overall economic downturn, our capital expenditure
program can be readily modified.
SELECTED QUARTERLY INFORMATION
------------------------------
The following tables set out selected quarterly financial information for
the last two fiscal years.
-------------------------------------------------------------------------
Three Months Ended Year
Ended
-------------------------------------------------------------------------
($000s, except March 31, June 30, Sept. 30, Dec. 31, Dec. 31,
where noted) 2006 2006 2006 2006 2006
-------------------------------------------------------------------------
Average production
(boe/d) 34,029 32,645 32,843 33,245 33,187
Average pricing
($/boe) $ 48.21 $ 44.85 $ 41.33 $ 41.82 $ 44.05
Total revenue $147,644 $133,224 $124,886 $127,902 $533,656
Cash flow from
operations $ 73,596 $ 67,326 $ 60,120 $ 55,263 $256,305
Per share:
basic $ 0.58 $ 0.53 $ 0.47 $ 0.43 $ 2.01
diluted $ 0.55 $ 0.50 $ 0.45 $ 0.42 $ 1.92
Operating earnings $ 22,249 $ 17,947 $ 13,150 $ 11,822 $ 65,168
Net earnings (loss) $ 38,002 $ 68,744 $ 30,717 $(10,037) $127,426
Per share: basic $ 0.30 $ 0.54 $ 0.24 $ (0.08) $ 1.00
diluted $ 0.28 $ 0.51 $ 0.23 $ (0.08) $ 0.95
-------------------------------------------------------------------------
During the second half of 2006, lower realized commodity prices from those experienced during the first half of the year resulted in reduced revenue, cash flow, and operating earnings. Production increases in the third and fourth quarter were more than offset by the reduction in commodity prices. The negative effect of lower commodity prices on cash flow was reduced by realized gains of $36 million from risk management activities. Net earnings for the nine months ended September 30, 2006 benefited from an unrealized foreign exchange gain of $19.1 million, after tax, and an income tax recovery of $35 million. Net earnings in the fourth quarter were negative due to the reversal of unrealized foreign exchange gains recorded in prior quarters, as the result of the weakening of the Canadian dollar compared to the U.S. dollar.
-------------------------------------------------------------------------
Three Months Ended Year
Ended
-------------------------------------------------------------------------
($000s, except March 31, June 30, Sept. 30, Dec. 31, Dec. 31,
where noted) 2005 2005 2005 2005 2005
-------------------------------------------------------------------------
Average production
(boe/d) 28,714 28,877 29,041 31,042 29,424
Average pricing
($/boe) $ 41.25 $ 46.33 $ 54.31 $ 64.58 $ 51.95
Total revenue $106,589 $121,748 $145,114 $184,428 $557,879
Cash flow from
operations $ 52,277 $ 62,006 $ 74,189 $ 89,640 $278,112
Per share:
basic $ 0.43 $ 0.49 $ 0.58 $ 0.71 $ 2.21
diluted $ 0.41 $ 0.47 $ 0.56 $ 0.67 $ 2.11
Operating earnings $ 15,534 $ 18,923 $ 25,794 $ 33,413 $ 93,664
Net earnings $ 10,059 $ 22,034 $ 11,127 $ 38,106 $ 81,326
Per share:
basic $ 0.08 $ 0.18 $ 0.09 $ 0.30 $ 0.65
diluted $ 0.08 $ 0.17 $ 0.08 $ 0.29 $ 0.62
-------------------------------------------------------------------------
As compared to 2004, total revenue increased throughout 2005 as the result of high commodity prices and increasing production volumes. Average production increased in the third and fourth quarters, after abnormally wet weather in the summer restricted access in Southern Alberta resulting in flat production volumes in the second quarter. Quarterly net earnings fluctuated due to non-operational items such as unrealized risk management gains and losses and unrealized foreign exchange losses.
SELECTED ANNUAL INFORMATION
-------------------------------------------------------------------------
Years ended December 31, ($000s) 2006 2005 2004
-------------------------------------------------------------------------
Total revenue $ 533,656 $ 557,879 $ 391,659
Net earnings $ 127,426 $ 81,326 $ 63,633
Per share: basic $ 1.00 $ 0.65 $ 0.54
diluted $ 0.95 $ 0.62 $ 0.51
Total assets $2,147,472 $1,758,098 $1,330,611
Total long term financial
liabilities $ 854,385 $ 535,540 $ 198,594
-------------------------------------------------------------------------
Total revenue in 2006 was marginally lower than 2005 with increases in production being more than offset by reduced commodity prices. Net earnings in 2006 increased $46.1 million over 2005 primarily as a result of risk management gains that offset the reduction in revenue and increases in expenses. Long term financial obligation in 2006 increased over 2005 as a result of increased borrowings to fund the capital programs.
Total revenue in 2005 was higher than in the previous year due to a combination of increased production and higher commodity prices. Net earnings in 2005 increased 28% from 2004, but was reduced by non-recurring costs of $14 million ($21 million before taxes) relating to the repurchase of U.S.$158 million of 9.90% Senior Notes. Total assets increased from the prior year primarily due to capital expenditures of $514 million. The change in long term financial liabilities at December 31, 2005 resulted from issuing U.S.$300 million Senior Notes and reclassifying bank debt as long term.
Forward Looking Statements
Certain information contained herein constitutes forward looking statements under the meaning of applicable securities laws, including the United States Private Securities Litigation Reform Act of 1995. Forward looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact, including statements regarding (i) cash flow, production, capital expenditures and planned wells in 2007, and (ii) other risks and uncertainties described from time to time in the reports and filings made by us with securities regulatory authorities. Although we believe that the expectations reflected in such forward looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward looking statements not to be correct, including risks and uncertainties inherent in our business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of reserves and in projections of future rates of production and timing of development expenditures, general economic conditions, the actions or inactions of third party operators and regulatory pronouncements. We may, as considered necessary in the circumstances, update or revise forward looking information, whether as a result of new information, future events, or otherwise. Our forward looking statements are expressly qualified in their entirety by this cautionary statement.
Non-GAAP Financial Measures
Included herein are references to terms used in the oil and gas industry such as cash flow from operations, cash flow per share and operating earnings. These terms are not defined by GAAP in Canada and consequently are referred to as non-GAAP measures. Non-GAAP measures do not have any standardized meaning and therefore reported amounts may not be comparable to similarly titled measures reported by other companies.
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. Cash flow from operations is used by us to evaluate operating results and our ability to generate cash to fund capital expenditures and repay debt.
Operating earnings 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. Operating earnings 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.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Balance Sheets
(unaudited)(thousands of dollars)
-------------------------------------------------------------------------
December 31, December 31,
Assets 2006 2005
Current
Cash $ 12,232 $ 8,954
Accounts receivable 83,535 122,073
Unrealized risk management gain
(Note 16a (i)) 22,625 -
Other current assets (Note 16b (ii)) 24,513 10,726
Future income taxes (Note 15b) 1,479 2,609
------------ ------------
144,384 144,362
Property and equipment (Note 4 and 19) 1,977,062 1,587,371
Goodwill (Note 2) 7,914 7,914
Deferred financing charges and other (Note 8) 14,144 12,841
Deferred risk management loss (Note 16a (ii)) 3,968 5,610
------------ ------------
$2,147,472 $1,758,098
------------ ------------
------------ ------------
Liabilities
Current
Accounts payable $ 141,443 $ 203,869
Unrealized risk management loss
(Note 16a (i) and (iii)) 4,604 7,758
Future income taxes (Note 15b) 7,269 -
------------ ------------
153,316 211,627
Bank debt (Note 5) 330,000 177,900
Senior term notes (Note 6) 524,385 357,640
Asset retirement obligations (Note 10) 29,791 20,770
Unrealized risk management loss
(Note 16a (iii)) 6,816 10,201
Future income taxes (Note 15b) 302,690 314,726
Non-controlling interest (Note 3) 66,350 68,898
------------ ------------
1,413,348 1,161,762
------------ ------------
Shareholders' equity
Capital stock (Note 11b) 231,992 226,444
Contributed surplus (Note 12a) 16,974 9,173
Retained earnings 485,158 360,719
------------ ------------
734,124 596,336
------------ ------------
$2,147,472 $1,758,098
------------ ------------
------------ ------------
Commitments and contingent liabilities
(Note 18)
Subsequent events (Note 19)
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Earnings
(unaudited) (thousands of dollars, except per share data)
-------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
-------------------- --------------------
2006 2005 2006 2005
--------- --------- --------- ---------
Revenue
Oil and natural gas
revenues $ 127,902 $ 184,428 $ 533,656 $ 557,879
Royalties (29,182) (43,524) (123,677) (132,717)
--------- --------- --------- ---------
98,720 140,904 409,979 425,162
--------- --------- --------- ---------
Expenses
Operating 27,316 18,929 95,462 66,802
Transportation 3,214 3,118 12,564 10,858
General and administrative 7,422 6,864 26,231 21,223
Interest and finance charges
(Note 7) 15,926 10,741 54,075 34,951
Tender costs (Note 8) - 20,750 - 20,750
Depletion and depreciation 37,036 31,005 143,057 105,504
Foreign exchange (gain)
loss (Note 9) 22,708 (347) (891) (7,353)
Accretion of asset retirement
obligations (Note 10) 632 559 2,257 1,975
Stock-based compensation
(Note 12a and c) 3,616 1,649 10,488 5,903
Risk management (gain) loss
(Note 16a (iv)) (6,028) (16,808) (63,721) 19,302
--------- --------- --------- ---------
111,842 76,460 279,522 279,915
--------- --------- --------- ---------
Earnings before taxes and
non-controlling interest (13,122) 64,444 130,457 145,247
--------- --------- --------- ---------
Income taxes (Note 15a)
Current 21 3,597 44 5,071
Future (5,530) 21,261 (3,636) 52,317
--------- --------- --------- ---------
(5,509) 24,858 (3,592) 57,388
--------- --------- --------- ---------
Earnings before non-controlling
interest (7,613) 39,586 134,049 87,859
Non-controlling interest
(Note 3) 2,424 1,480 6,623 6,533
--------- --------- --------- ---------
Net earnings $ (10,037) $ 38,106 $ 127,426 $ 81,326
--------- --------- --------- ---------
--------- --------- --------- ---------
Net earnings per share
(Note 13)
Basic $ (0.08) $ 0.30 $ 1.00 $ 0.65
--------- --------- --------- ---------
--------- --------- --------- ---------
Diluted $ (0.07) $ 0.28 $ 0.95 $ 0.62
--------- --------- --------- ---------
--------- --------- --------- ---------
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
-------------------- --------------------
2006 2005 2006 2005
--------- --------- --------- ---------
Retained earnings, beginning
of year $ 495,727 $ 323,311 $ 360,719 $ 284,712
Net earnings (10,037) 38,106 127,426 81,326
Premium on redemption of
shares (Note 11b) (532) (698) (2,987) (5,319)
--------- --------- --------- ---------
Retained earnings, end
of year $ 485,158 $ 360,719 $ 485,158 $ 360,719
--------- --------- --------- ---------
--------- --------- --------- ---------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
-------------------- --------------------
2006 2005 2006 2005
--------- --------- --------- ---------
Operating activities
Net earnings $ (10,037) $ 38,106 $ 127,426 $ 81,326
Amortization of deferred
charges and other 401 743 1,996 2,190
Tender costs - 20,750 - 20,750
Depletion and depreciation 37,036 31,005 143,057 105,504
Accretion of asset
retirement obligations 632 559 2,257 1,975
Unrealized foreign exchange
(gain) loss 22,500 (796) (665) (7,808)
Future income taxes (5,530) 21,261 (3,636) 52,317
Unrealized risk management
(gain) loss 6,073 (24,759) (27,522) 10,171
Stock-based compensation 2,249 1,649 9,121 5,903
Asset retirement
expenditures (485) (358) (2,352) (749)
Non-controlling interest 2,424 1,480 6,623 6,533
--------- --------- --------- ---------
55,263 89,640 256,305 278,112
Change in non-cash working
capital (Note 17) 23,087 11,809 18,901 8,441
--------- --------- --------- ---------
78,350 101,449 275,206 286,553
--------- --------- --------- ---------
Financing activities
Issuance (repayment) of
bank debt 50,000 (82,100) 152,100 (42,100)
Issuance of senior notes - 353,130 174,930 353,130
Issue costs on senior notes - (12,670) (3,408) (12,670)
Redemption of senior notes - (199,973) (7,520) (199,973)
Proceeds from share
issuances, net 598 331 4,672 89,752
Distributions to partner (2,293) (2,293) (9,171) (9,172)
Redemption of common shares (635) (790) (3,433) (6,118)
Change in non-cash working
capital (Note 17) (8,092) (6,679) 1,278 (1,829)
--------- --------- --------- ---------
39,578 48,956 309,448 171,020
--------- --------- --------- ---------
Investing activities
Property and equipment
additions (88,453) (161,186) (490,429) (484,213)
Property acquisitions (3,603) (11,376) (34,444) (28,575)
Property dispositions - - 1,350 -
Change in non-cash working
capital (Note 17) (35,636) 14,211 (57,853) 54,101
--------- --------- --------- ---------
(127,692) (158,351) (581,376) (458,687)
--------- --------- --------- ---------
Change in cash (9,764) (7,946) 3,278 (1,114)
Cash, beginning of year 21,996 16,900 8,954 10,068
--------- --------- --------- ---------
Cash, end of year $ 12,232 $ 8,954 $ 12,232 $ 8,954
--------- --------- --------- ---------
--------- --------- --------- ---------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Notes to the Consolidated Financial Statements
December 31, 2006
(unaudited)
(Tabular amounts in thousands of dollars, unless otherwise stated)
-------------------------------------------------------------------------
1. Significant accounting policies
Compton Petroleum Corporation (the "Company" or "Compton") is in the
business of the exploration for and production of petroleum and
natural gas reserves in the Western Canada Sedimentary Basin.
a) Basis of presentation
The consolidated financial statements of the Company have been
prepared in accordance with accounting principles generally accepted
in Canada within the framework of the accounting policies summarized
below.
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. The consolidated financial
statements also include the accounts of Mazeppa Processing
Partnership in accordance with Accounting Guideline 15 ("AcG-15")
"Consolidation of Variable Interest Entities", as outlined in Note 3.
All amounts are presented in Canadian dollars unless otherwise
stated.
b) Measurement uncertainty
The timely preparation of financial statements requires that
Management make estimates and assumptions and use judgment regarding
assets, liabilities, revenues, and expenses. Such estimates relate
primarily to transactions and events that have not settled as of the
date of the financial statements. Accordingly, actual results may
differ from estimated amounts as future confirming events occur.
Amounts recorded for depletion and depreciation, and amounts used in
impairment test calculations are based upon estimates of petroleum
and natural gas reserves and future costs to develop those reserves.
By their nature, these estimates of reserves, costs, and related
future cash flows are subject to uncertainty, and the impact on the
consolidated financial statements of future periods could be
material.
The calculation of asset retirement obligations includes estimates of
the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, and timing of settlement. The impact of future
revisions to these assumptions on the consolidated financial
statements of future periods could be material.
The values of pension assets and obligations and the amount of
pension costs charged to net earnings depend on certain actuarial and
economic assumptions which by their nature are subject to measurement
uncertainty.
c) Property and equipment
i) Capitalized costs
The Company follows the full cost method of accounting for its
petroleum and natural gas operations within one Canadian cost
centre. Under this method all costs related to the exploration
for and development of petroleum and natural gas reserves are
capitalized. Costs include lease acquisition costs, geological
and geophysical expenses, costs of drilling both producing and
non-producing wells, production facilities, future asset
retirement costs, and certain general and administrative
expenses directly related to exploration and development
activities.
Proceeds from the sale of properties are applied against
capitalized costs, without any gain or loss being realized,
unless such sale would significantly alter the rate of depletion
and depreciation.
Expenditures related to renewals or betterments that improve the
productive capacity or extend the life of an asset are
capitalized. Maintenance and repairs, other than major
turnaround costs, are expensed as incurred. Major turnaround
costs are included in property and equipment when incurred and
charged to depletion and depreciation in the consolidated
statement of earnings over the estimated period of time to the
next scheduled turnaround.
ii) Depletion and depreciation
Depletion and depreciation of property and equipment is provided
using the unit-of-production method based upon estimated proved
petroleum and natural gas reserves. The costs of significant
undeveloped properties are excluded from costs subject to
depletion until it is determined whether or not proved reserves
are attributable to the properties or impairment has occurred.
Estimated future costs to be incurred in developing proved
reserves are included and estimated salvage values are excluded
in costs subject to depletion. For depletion and depreciation
purposes, relative volumes of natural gas production and
reserves are converted at the energy equivalent conversion rate
of six thousand cubic feet of natural gas to one barrel of crude
oil.
Depreciation of certain midstream facilities is provided for on
a straight line basis over 30 years and depreciation of office
equipment is provided for on a declining balance basis which
ranges from 20% to 30% per year.
iii) Impairment test
At each reporting period the Company performs an impairment test
to determine the recoverability of capitalized costs associated
with reserves. An impairment loss is recognized when the
carrying amount of a cost centre exceeds its fair value. The
carrying amount of the cost centre is not recoverable if the
carrying amount exceeds the sum of the undiscounted cash flows
from proved reserves plus the costs of unproved properties. If
the sum of the cash flows is less than the carrying amount, the
impairment loss is limited to the amount by which the carrying
amount exceeds the sum of the fair value of discounted proved
and probable reserves and the costs of unproved properties that
have been subject to a separate impairment test and contain no
probable reserves.
iv) Asset retirement obligations
The Company recognizes the fair value of estimated asset
retirement obligations on the consolidated balance sheet when a
reasonable estimate of fair value can be made. Asset retirement
obligations include those legal obligations where the Company
will be required to retire tangible long-lived assets such as
well sites, pipelines, and facilities. The asset retirement
cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the
related long-lived asset. Changes in the estimated obligation
resulting from revisions to estimated timing or amount of
undiscounted cash flows are recognized as a change in the asset
retirement obligation and the related asset retirement cost.
Asset retirement costs are amortized using the
unit-of-production method and are included in depletion and
depreciation in the consolidated statement of earnings.
Increases in the asset retirement obligations resulting from the
passage of time are recorded as accretion of asset retirement
obligations in the consolidated statement of earnings.
Actual expenditures incurred are charged against the accumulated
obligation.
v) Inventories
Physical inventory held for exploration, development, and
operating activities is included in property and equipment and
is valued at cost.
d) Goodwill
Goodwill is recorded on a corporate acquisition when the purchase
price is in excess of the fair values assigned to assets acquired and
liabilities assumed. Goodwill is not amortized and an impairment test
is performed at least annually to evaluate the carrying value. To
assess impairment, the fair value of the consolidated entity,
excluding the Mazeppa Processing Partnership, is determined and
compared to the carrying value. If the fair value is less than the
carrying value then a second test is performed to determine the
amount of the impairment. Any loss recognized is equal to the
difference between the implied fair value and the carrying value of
the goodwill.
e) Financial instruments and derivatives
Financial instruments consist mainly of cash, accounts receivable,
other current assets, accounts payable, and long-term debt. The
Company uses derivative financial instruments for non-trading
purposes to manage fluctuations in commodity prices, foreign currency
exchange rates, and interest rates as outlined in Note 16. The
Company has elected not to designate any of its current risk
management activities as accounting hedges and accounts for all
derivative financial instruments using the mark-to-market accounting
method.
f) Joint operations
Certain petroleum and natural gas activities are conducted jointly
with others. These consolidated financial statements reflect only the
Company's proportionate interest in such activities.
g) Earnings per share amounts
The Company uses the treasury stock method to determine the dilutive
effect of stock options. This method assumes that proceeds received
from the exercise of in-the-money stock options are used to
repurchase common shares at the average market price for the period.
Basic net earnings per common share are determined by dividing net
earnings by the weighted average number of common shares outstanding
during the period. Diluted earnings per share are computed by giving
effect to the potential dilution that would occur if stock options
were exercised.
h) Income taxes
Income taxes are recorded using the liability method of accounting.
Future income taxes are calculated based on the difference between
the accounting and income tax basis of an asset or liability, using
the substantively enacted income tax rates. Changes in income tax
rates that are substantively enacted are reflected in the period the
change occurs.
i) Revenue recognition
Revenue associated with the production and sale of crude oil, natural
gas, and natural gas liquids owned by the Company is recognized when
title passes to the customer and delivery has taken place. Revenue as
reported, represents the Company's share and is presented before
royalty payments to governments and other mineral interest owners.
Other revenue is recognized in the period that the service is
provided to the customer.
j) Stock-based compensation plan
The Company records compensation expense in the consolidated
statements of earnings for stock options granted to Directors,
Officers, and employees using the fair-value method. Compensation
costs are recognized over the vesting period and the fair values are
determined using the Black-Scholes option pricing model.
The Company also has an employee stock savings plan. The
contributions are recorded as compensation expense as incurred.
k) Deferred financing charges
Financing costs related to the issuance of senior term notes are
deferred and are amortized over the term of the notes on a straight-
line basis. If the notes are retired, in whole or in part, prior to
maturity, a pro-rata share of the unamortized balance is expensed in
the consolidated statement of earnings.
l) Foreign currency translation
Monetary assets and liabilities of the Company that are denominated
in foreign currencies are translated into Canadian dollars at the
period-end exchange rate, with any resulting gain or loss recorded in
the consolidated statement of earnings.
m) Dividend policy
The Company has neither declared nor paid any dividends on its common
shares. The Company intends to retain its earnings to finance growth
and expand its operations and does not anticipate paying any
dividends on its common shares in the foreseeable future.
n) Defined benefit pension plan
The Company accrues for obligations under a defined benefit pension
plan and the related costs, net of plan assets for employees of
Mazeppa Processing Partnership. The cost of the pension is
actuarially determined using the projected benefit method based on
length of service and reflects Management's best estimate of expected
plan investment performance, salary escalation, and retirement age of
employees.
o) Recent accounting pronouncements
In 2005, the Canadian Institute of Chartered Accountants ("CICA")
issued three new accounting standards: Handbook Section 1530,
"Comprehensive Income", Handbook Section 3855, "Financial Instruments
- Recognition and Measurement", and Handbook Section 3865, "Hedges".
The new standards introduce the Consolidated Statement of
Comprehensive Income which is used to temporarily provide for gains
and losses including foreign currency translation adjustments and
other amounts arising from changes in fair value until they are
realized and recorded in net earnings. As well, all financial
instruments, including derivatives, are to be included in the
Company's consolidated balance sheet and measured at fair value. In
certain situations assets that are classified as held to maturity
will continue to be measured at cost. The new standards also include
further clarification on the application of hedge accounting which
will have no impact on the Company's financial statements which
currently reflect mark-to-market accounting for derivative
instruments. These new standards are effective for fiscal years
beginning on or after October 1, 2006 and early adoption is
permitted. The Company has assessed the impact of these new
accounting standards on the consolidated financial statements at
January 1, 2007 and has determined that:
- The balance in deferred financing charges will no longer be
disclosed separately but will be netted against the corresponding
senior term notes.
- The presentation of accumulated other comprehensive income will be
similar to the presentation of United States accounting principles
and reporting included in Note 20.
- The measurement and recording of financial instruments at fair
value will not have a material impact on the Company's consolidated
financial statements.
In July 2006, the CICA replaced Handbook Section 1506, "Accounting
Changes" with a new Section 1506, "Accounting Changes" to
substantially harmonize with International Accounting Standards for
the accounting and disclosure of changes in accounting estimates and
errors. Under the new standard, accounting changes should be applied
retrospectively unless otherwise permitted or where impracticable to
determine. In addition, voluntary changes in accounting policy are
made only if they result in the financial statements providing
reliable and more relevant information. New disclosure is required
for changes in accounting policies, changes in accounting estimates
and correction of errors. The standard is effective for fiscal years
beginning on or after January 1, 2007. The Company does not expect
the application of this revised standard to have a material impact on
the consolidated financial statements.
In December 2006, the CICA issued two new accounting standards:
Handbook 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.
The standards are effective for fiscal years beginning on or after
October 1, 2007 and the Company is currently assessing the impact on
the consolidated financial statements.
In December 2006, the CICA issued a new accounting standard: Handbook
Section 1535, "Capital Disclosures", requiring disclosure of
information about an entity's capital and the objectives, policies,
and processes for managing capital. The standard is effective for
fiscal years beginning on or after October 1, 2007 and the Company is
currently assessing the impact on the consolidated financial
statements.
p) Reclassification
Certain amounts disclosed for prior years have been reclassified to
conform with current period presentation.
2. Business combinations
On April 12, 2004 and November 15, 2004, respectively, the Company
acquired 100% of the issued and outstanding shares of Redwood Energy,
Ltd. and Mayfair Energy Ltd. for total cash consideration of
$12.1 million plus the assumption of $12.1 million of debt. Both entities
were independent exploration and production companies with operations in
the Company's core areas.
The business combinations have been accounted for using the purchase
method with results of operations included in the consolidated financial
statements from the date of acquisition. Goodwill recognized on these
transactions amounted to $7.9 million.
During the year ended December 31, 2004, both companies were wound up
into Compton Petroleum Corporation and dissolved.
3. Non-controlling interest
Mazeppa Processing Partnership ("MPP" or "the Partnership") is a limited
partnership organized under the laws of the province of Alberta and owns
certain midstream facilities, including gas plants and pipelines in
Southern Alberta. The Company processes a significant portion of its
production from the area through these facilities pursuant to a
processing agreement with MPP. The Company does not have an ownership
position in MPP, however, the Company, through a management agreement,
manages the activities of MPP and is considered to be the primary
beneficiary of MPP's operations. Pursuant to AcG-15, these consolidated
financial statements include the assets, liabilities, and operations of
the Partnership. Equity in the Partnership, attributable to the partners
of MPP, is recorded on consolidation as a non-controlling interest and is
comprised of the following:
As at December 31, 2006 2005
------------ ------------
Non-controlling interest, beginning of year $ 68,898 $ 71,537
Earnings attributable to
non-controlling interest 6,623 6,533
Distributions to limited partner (9,171) (9,172)
------------ ------------
Non-controlling interest, end of year $ 66,350 $ 68,898
------------ ------------
------------ ------------
Commencing May 1, 2004, pursuant to the terms of a processing agreement
between Compton and MPP, Compton pays a monthly fee to MPP for the
transportation and processing of natural gas through the MPP owned
facilities. The fee is comprised of a fixed base fee of $764 thousand per
month plus MPP operating costs, net of third party revenues. These
amounts are eliminated from revenues and expenses on consolidation.
The processing agreement has a five year term ending April 1, 2009, at
which time Compton may renew the agreement under terms determined at that
time or purchase the Partnership units for the predetermined amount of
$55 million, deemed to be fair value. In the event that the Company does
not renew the processing agreement nor exercise the purchase option, the
Limited Partner may dispose of the Partnership units to an independent
third party.
MPP has guaranteed payment of certain obligations of its limited partner
under a credit agreement between the limited partner and a syndicate of
lenders. The maximum liability of the Partnership under the guarantee is
limited to amounts due and payable to MPP by the Company pursuant to the
processing agreement. The maximum liability at December 31, 2006 was
$21.4 million (2005 - $30.6 million) payable over the remaining term of
the processing agreement. The Company has determined that its exposure to
loss under these arrangements is minimal, if any.
4. Property and equipment
Accumulated
depletion
and
As at December 31, 2006 Cost depreciation Net
------------ ------------ -----------
Exploration and development costs $1,931,594 $(482,524) $1,449,070
Production equipment and
processing facilities 582,705 (77,863) 504,842
Inventory 6,818 - 6,818
Future asset retirement costs 17,128 (4,906) 12,222
Office equipment 9,359 (5,249) 4,110
------------ ------------ -----------
$2,547,604 $(570,542) $1,977,062
------------ ------------ -----------
------------ ------------ -----------
Accumulated
depletion
and
As at December 31, 2005 Cost depreciation Net
------------ ------------ -----------
Exploration and development costs $1,553,543 $(366,902) $1,186,641
Production equipment and
processing facilities 436,948 (52,771) 384,177
Inventory 6,469 - 6,469
Future asset retirement costs 10,365 (3,771) 6,594
Office equipment 7,641 (4,151) 3,490
------------ ------------ -----------
$2,014,966 $(427,595) $1,587,371
------------ ------------ -----------
------------ ------------ -----------
At December 31, 2006, $9.6 million (2005 - $11.1 million) relating to
employee salaries, insurance costs and overhead recoveries determined in
accordance with industry procedures were capitalized.
As at December 31, 2006, future capital expenditures of $329.7 million
(2005 - $192.9 million, 2004 - $89.1 million), as estimated by
independent reserve engineers, relating to the development of proved
reserves have been included in costs subject to depletion. The estimated
salvage value of production equipment and processing facilities at
December 31, 2006 was $120.1 million (2005 - $108.6 million, 2004 -
$81.0 million) and was excluded from costs subject to depletion.
Undeveloped properties with a cost at December 31, 2006 of $202.9 million
(2005 - $251.3 million, 2004 - $187.8 million) included in exploration
and development costs, have not been subject to depletion.
The prices used in the evaluation of the carrying value of the Company's
reserves for the purposes of the impairment test are:
Natural
As at December 31, 2006 gas Oil NGL
------------ ------------ -----------
$ per mcf $ per bbl $ per bbl
2007 7.77 63.95 60.66
2008 8.27 65.20 60.10
2009 8.19 62.83 58.37
2010 8.18 60.37 56.69
2011 8.37 58.72 55.21
Approximate % increase thereafter 2.0% 2.0% 2.0%
5. Credit facilities
As at December 31, 2006 2005
------------ ------------
Authorized $ 500,000 $ 289,000
------------ ------------
------------ ------------
Prime rate $ 35,000 $ 22,900
Bankers' Acceptance 295,000 155,000
------------ ------------
Utilized $ 330,000 $ 177,900
------------ ------------
------------ ------------
As at December 31, 2006, the Company had arranged authorized senior
credit facilities with a syndicate of banks in the amount of
$500 million. Advances under the facilities can be drawn and currently
bear interest as follows:
Prime rate plus 0.75%
Bankers' Acceptance rate plus 1.75%
LIBOR rate plus 1.75%
Margins are determined based on the ratio of total consolidated debt to
consolidated cash flow. The facilities reach term on July 4, 2007 and, if
not renewed, will mature 366 days later on July 5, 2008.
The senior credit facilities are secured by a first fixed and floating
charge debenture in the amount of $1.0 billion covering all the Company's
assets and undertakings.
6. Senior term notes
As at December 31, 2006 2005
------------ ------------
Senior term notes
US$450 million, 7.625% due December 1, 2013 $ 524,385 $ 349,770
US$6.75 million, 9.90% due May 15, 2009 - 7,870
------------ ------------
$ 524,385 $ 357,640
------------ ------------
------------ ------------
On April 4, 2006, the Company issued an additional U.S.$150 million
7.625% senior term notes due 2013 under the same terms and conditions as
the 7.625% notes outstanding at December 31, 2005. The proceeds from the
issue of the notes were used to repay a portion of the debt outstanding
under the Company's senior credit facilities. The Company also used a
portion of the proceeds to redeem the balance of the U.S.$6.75 million
9.90% senior notes on May 16, 2006, being the first call date, at
104.95%.
In November 2005, the Company and a wholly owned subsidiary of the
Company completed a tender offer and consent solicitation to amend the
Indenture relating to the 9.9% notes. The Company and a wholly owned
subsidiary paid 107.195% plus accrued and unpaid interest for the U.S.
158.25 million 9.9% notes tendered by the note holders. Information
related to the tender costs can be found in note 8.
The 7.625% notes are not redeemable by the Company prior to December 1,
2009, except in limited circumstances. After that time, they can be
redeemed in whole or part, at the rates indicated below:
December 1, 2009 103.813%
December 1, 2010 101.906%
December 1, 2011 and thereafter 100.000%
The senior term notes are subordinate to the Company's senior credit
facilities.
7. Interest and finance charges
Amounts charged to expense during the year ended are as follows:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Interest on bank debt, net $ 15,356 $ 11,520 $ 9,662
Interest on senior term notes 35,880 20,912 21,281
Finance charges 2,839 2,519 2,790
------------ ------------ -----------
Total $ 54,075 $ 34,951 $ 33,733
------------ ------------ -----------
------------ ------------ -----------
Finance charges include the amortization of deferred charges and other
current year expenses.
The effective interest rate on bank debt at December 31, 2006 was 5.6%
(2005 - 4.2%).
8. Deferred financing charges and other
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of deferred financing charges associated
with the issue of senior term notes:
Years ended December 31, 2006 2005
------------ ------------
Deferred financing charges and other,
beginning of year $ 12,841 $ 9,729
Issue costs on 7.625% Senior Notes 3,408 12,670
Pro-rata reduction on repayment of 9.90%
Senior Notes (293) (7,053)
Amortization expense (1,905) (2,119)
Other 93 (386)
------------ ------------
Deferred financing charges and other,
end of year $ 14,144 $ 12,841
------------ ------------
------------ ------------
Costs incurred on the tender for the 9.90% senior term notes in 2005 were
as follows:
2005
------------
Premium payment $ 7,814
Consent solicitation fee 5,883
Pro-rata reduction of deferred financing charges on repayment
of 9.90% Senior Notes 7,053
------------
Total $ 20,750
------------
------------
The balance of the 9.9% senior notes were purchased in 2006 pursuant to a
call option provision and no additional tender costs were incurred.
9. Foreign exchange (gain) loss
Amounts charged to foreign exchange (gain) loss during the year ended
were as follows:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Foreign exchange gain on
translation of US$ debt $ (665) $ (7,808) $ (14,652)
Other foreign exchange (gain) loss (226) 455 21
------------ ------------ -----------
Total $ (891) $ (7,353) $ (14,631)
------------ ------------ -----------
------------ ------------ -----------
10. Asset retirement obligations
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligations associated with the
retirement of oil and natural gas assets:
As at December 31, 2006 2005
------------ ------------
Asset retirement obligations, beginning of year $ 20,770 $ 18,006
Liabilities incurred 7,031 5,218
Liabilities settled and disposed (267) (1,275)
Accretion expense 2,257 1,975
Revision of estimates - (3,154)
------------ ------------
Asset retirement obligations, end of year $ 29,791 $ 20,770
------------ ------------
------------ ------------
The total undiscounted amount of estimated cash flows required to settle
the obligations was $233.0 million (2005 - $185.8 million), which has
been discounted using a credit-adjusted risk free rate of 10.6% (2005 -
10.7%). The majority of these obligations are not expected to be settled
for several years or decades into the future. Settlements will be funded
from general Company resources at the time of retirement and removal.
11. Capital stock
a) Authorized
The Company is authorized to issue an unlimited number of common
shares and an unlimited number of preferred shares, issuable in
series.
b) Issued and outstanding
As at December 31, 2006 2005
-------------------- ---------------------
Number Number
of of
Shares Amount Shares Amount
--------- --------- --------- ----------
(000s) (000s)
Common shares outstanding,
beginning of year 127,263 $ 226,444 117,354 $ 135,526
Shares issued for cash, net - - 7,500 87,294
Shares issued under stock
option plan 1,489 5,993 2,926 4,424
Shares repurchased (249) (445) (517) (800)
--------- --------- --------- ----------
Common shares outstanding,
end of year 128,503 $ 231,992 127,263 $ 226,444
--------- --------- --------- ----------
--------- --------- --------- ----------
The Company maintains a Normal Course Issuer Bid program on an annual
basis. Under the current program, the Company may purchase for
cancellation up to 6,000,000 of its common shares, representing
approximately 5.0% of the issued and outstanding common shares at the
time the bid received regulatory approval.
During the year, the Company purchased for cancellation 248,900
common shares at an average price of $13.79 per share (2005 - 516,600
common shares at an average price of $11.84 per share) pursuant to
the normal course issuer bid. The excess of the purchase price over
book value has been charged to retained earnings.
c) Shareholder rights plan
The Company has a shareholder rights plan (the "Plan") to ensure all
shareholders are treated fairly in the event of a take-over offer or
other acquisition of control of the Company.
Pursuant to the Plan, the Board of Directors authorized and declared
the distribution of one Right in respect of each common share
outstanding. In the event that an acquisition of 20% or more of the
Company's shares is completed and the acquisition is not a permitted
bid, as defined by the Plan, each Right will permit the holder to
acquire common shares at a 50% discount to the market price at that
time.
12. Stock-based compensation plans
a) Stock option plan
The Company has a stock option plan for employees, including
Directors and Officers. The exercise price of each option
approximated the market price for the common shares on the date the
option was granted. Options granted under the plan before June 1,
2003 are generally fully exercisable after four years and expire ten
years after the grant date. Options granted under the plan after
June 1, 2003 are generally fully exercisable after four years and
expire five years after the grant date.
The following tables summarize the information relating to stock
options:
As at December 31, 2006 2005
-------------------- ---------------------
Weighted Weighted
average average
Stock exercise Stock exercise
options price options price
--------- --------- --------- ----------
(000s) (000s)
Outstanding, beginning of
year 11,446 $ 6.13 11,655 $ 3.51
Granted 2,228 $ 13.99 2,930 $ 11.89
Exercised (1,489) $ 3.14 (2,926) $ 1.32
Cancelled (574) $ 10.92 (213) $ 8.30
--------- --------- --------- ----------
Outstanding, end of year 11,611 $ 7.79 11,446 $ 6.13
--------- --------- --------- ----------
--------- --------- --------- ----------
Exercisable, end of year 6,593 $ 4.82 6,219 $ 3.38
--------- --------- --------- ----------
--------- --------- --------- ----------
The range of exercise prices of stock options outstanding and
exercisable at December 31, 2006 is as follows:
Outstanding Options Exercisable Options
------------------------------------ ------------------------
Weighted
average Weighted Weighted
Range of Number of remaining average Number of average
exercise options contractual exercise options exercise
prices outstanding life (years) price outstanding price
----------- ------------- ----------- ----------- ----------- -----------
(000s) (000s)
$1.25 - $2.99 1,859 2.2 $ 1.76 1,859 $ 1.76
$3.00 - $3.99 1,318 4.5 $ 3.51 1,242 $ 3.49
$4.00 - $4.99 1,402 5.1 $ 4.28 1,310 $ 4.25
$5.00 - $6.99 972 2.0 $ 5.86 727 $ 5.86
$7.00 - $9.99 1,267 2.4 $ 7.61 696 $ 7.61
$10.00 - $12.99 2,827 3.5 $11.64 660 $11.64
$13.00 - $18.39 1,966 4.1 $14.38 99 $13.62
------------- ----------- ----------- ----------- -----------
11,611 3.5 $ 7.79 6,593 $ 4.82
------------- ----------- ----------- ----------- -----------
------------- ----------- ----------- ----------- -----------
The Company has recorded stock-based compensation expense in the
consolidated statement of earnings for stock options granted to
employees, Directors, and Officers after January 1, 2003 using the
fair value method.
The fair value of each option granted is estimated on the date of
grant using the Black-Scholes option pricing model with weighted
average assumptions for grants as follows:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Weighted average fair value of
options granted $ 6.90 $ 5.45 $ 3.70
Risk-free interest rate 4.0% 3.6% 3.9%
Expected life (years) 5.0 5.0 5.0
Expected volatility 43.5% 43.9% 49.6%
The following table presents the reconciliation of contributed
surplus with respect to stock-based compensation:
As at December 31, 2006 2005
------------ ------------
Contributed surplus, beginning of year $ 9,173 $ 3,840
Stock-based compensation expense 9,121 5,903
Stock options exercised (1,320) (570)
------------ ------------
Contributed surplus, end of year $ 16,974 $ 9,173
------------ ------------
------------ ------------
The Company has not recorded stock-based compensation expense in the
consolidated statement of earnings related to stock options granted
prior to 2003. If the Company had applied the fair value method to
options granted prior to 2003, the effect would have been as follows:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Reduction in net earnings $ 412 $ 1,007 $ 1,545
Reduction in net earnings
per common share - basic
and diluted $ 0.00 $ 0.01 $ 0.01
b) Share appreciation rights plan
CICA Handbook section 3870 requires recognition of compensation costs
with respect to changes in the intrinsic value for the variable
component of fixed share appreciation rights ("SARs"). During the
years ended December 31, 2006, 2005 and 2004, there were no
significant compensation costs related to the outstanding variable
component of these SARs. The liability related to the variable
component of these SARs amounts to $1.2 million, which is included in
accounts payable as at December 31, 2006 (2005 - $1.4 million). All
outstanding SARs having a variable component expire at various times
through 2011.
c) Employee retention program
In recognition of the shortage of qualified personnel that currently
exists within the industry, the Company implemented an Employee
Retention program in July 2006 for its existing employees, excluding
Officers and Directors. Under the program and contingent upon various
conditions present as at July 1, 2007, the Company may incur
additional compensation costs to a maximum amount of $4.2 million.
During the year ended December 31, 2006 $1.4 million has been
recognized in stock-based compensation expense as a partial
recognition of this potential liability. Any amount payable under the
program will be paid on July 1, 2007 at which time the final amount
will be fully determinable.
13. Per share amounts
The following table summarizes the common shares used in calculating net
earnings per common share:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
(000s) (000s) (000s)
Weighted average common shares
outstanding - basic 127,820 125,627 117,244
Effect of stock options 5,806 6,040 6,789
------------ ------------ -----------
Weighted average common shares
outstanding - diluted 133,626 131,667 124,033
------------ ------------ -----------
------------ ------------ -----------
In calculating diluted earnings per common share for the year ended
December 31, 2006, the Company excluded 1,537,100 options (2005 -
331,800, 2004 - 288,000) as the exercise price was greater than the
average market price of its common shares in those years.
14. Defined benefit pension plan
There are 34 employees of MPP currently enrolled in a co-sponsored,
defined benefit pension plan. The Company does not have a pension plan
for other employees. Information relating to the MPP retirement plan is
outlined below:
As at December 31, 2006 2005
------------ ------------
Accrued benefit obligation
Accrued benefit obligation - beginning
of year $ 7,562 $ 6,110
Current service cost 368 284
Interest cost 387 372
Benefits paid (392) (378)
Actuarial (gain) loss (208) 1,174
------------ ------------
Accrued benefit obligation - end of year $ 7,717 $ 7,562
------------ ------------
------------ ------------
Fair value of plan assets
Fair value of plan assets - beginning of year $ 5,839 $ 5,221
Employee contributions 82 75
Employer contributions 439 308
Benefits paid (392) (378)
Actual return on plan assets 667 613
------------ ------------
Fair value of plan assets - end of year $ 6,635 $ 5,839
------------ ------------
------------ ------------
Accrued benefit asset
Funded status - plan assets less than benefit
obligation (1,082) (1,723)
Unamortized net actuarial gain 414 891
Unamortized past service costs 793 862
------------ ------------
Accrued benefit asset, included in deferred
financing charges and other $ 125 $ 30
------------ ------------
------------ ------------
Economic assumptions used to determine benefit obligation and periodic
expense were:
Years ended December 31, 2006 2005
------------ ------------
Discount rate 5.0% 5.0%
Expected rate of return on assets 7.0% 7.0%
Rate of compensation increase 3.5% 3.5%
Average remaining service period of covered
employees 16 years 15 years
Actuarial evaluations are required every three years, the next evaluation
being January 1, 2009.
Pension expense, included in MPP operating costs, is as follows:
Years ended December 31, 2006 2005
------------ ------------
Current service cost $ 292 $ 232
Interest on accrued benefit obligation 387 372
Interest on assets (407) (364)
Amortization on past service cost 69 69
Amortization of net actuarial loss 9 -
------------ ------------
Pension expense, included in operating expense $ 350 $ 309
------------ ------------
------------ ------------
MPP expects to contribute $437 thousand to the plan in 2007.
15. Income taxes
a) The following table reconciles income taxes calculated at the
Canadian statutory rate with actual income taxes:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Earnings before taxes and
non-controlling interest $ 130,457 $ 145,247 $ 103,234
------------ ------------ -----------
Canadian statutory rate 34.5% 37.6% 38.6%
Expected income taxes $ 45,008 $ 54,613 $ 39,848
Effect on taxes resulting from:
Non-deductible Crown charges 2,145 15,061 17,611
Resource allowance (1,987) (11,980) (13,535)
Non-deductible stock-based
compensation 3,147 2,221 1,316
Federal capital tax - 1,896 2,526
Effect of tax rate changes (49,655) (5,764) (8,359)
Non-taxable portion of
capital items (115) - (2,831)
Other (2,135) 1,341 (393)
------------ ------------ -----------
Provision for income taxes $ (3,592) $ 57,388 $ 36,183
------------ ------------ -----------
------------ ------------ -----------
Current
Income taxes $ 44 $ 3,175 $ 225
Federal capital taxes - 1,896 2,526
Future (3,636) 52,317 33,432
------------ ------------ -----------
$ (3,592) $ 57,388 $ 36,183
------------ ------------ -----------
------------ ------------ -----------
Effective tax rate (2.8)% 39.5% 35.0%
------------ ------------ -----------
------------ ------------ -----------
A significant portion of the Company's taxable income is generated by
a partnership. Income taxes are incurred on the majority of the
partnership's taxable income in the year following its inclusion in
the Company's consolidated net earnings. Current income tax is
dependent upon the amount of capital expenditures incurred and the
method of deployment.
During the second quarter of 2006, the Canadian Federal and Alberta
governments enacted corporate tax rate reductions.
b) The net future income tax liability is comprised of:
As at December 31, 2006 2005
------------ ------------
Future income tax liabilities
Property and equipment in excess of tax
values $ 229,936 $ 232,258
Timing of partnership items 83,328 93,532
Foreign exchange gain on long-term debt 8,729 11,466
Other 2,591 -
Future income tax assets
Attributed Canadian royalty income (7,462) (8,830)
Asset retirement obligations (8,642) (6,984)
Other - (9,325)
------------ ------------
Net future income taxes $ 308,480 $ 312,117
------------ ------------
------------ ------------
Net future income taxes $ 308,480 $ 312,117
Current portion (5,790) 2,609
------------ ------------
Non-current future income taxes $ 302,690 $ 314,726
------------ ------------
------------ ------------
16. Financial instruments
a) Derivative financial instruments and risk management activities
The Company is exposed to risks from fluctuations in commodity
prices, interest rates, and Canada/US currency exchange rates. The
Company utilizes various derivative financial instruments for non-
trading purposes to manage and mitigate its exposure to these risks.
Effective January 1, 2004, the Company elected to account for all
derivative financial instruments using the mark-to-market method.
Risk management activities during the periods, utilizing derivative
instruments, relate to commodity price hedges, foreign currency
contracts and cross currency interest rate swap arrangements and are
summarized below:
i) Commodity price hedges
The Company enters into hedge transactions relating to crude oil and
natural gas prices to mitigate volatility in commodity prices and the
resulting impact on cash flow. The contracts entered into are forward
transactions providing the Company with a range of prices on the
commodities sold. Outstanding hedge contracts at December 31, 2006
are:
Daily Mark-
Notional Average to-Market
Commodity Term Volume Price gain
--------- ---- -------- ------- -----------
Natural
gas
$8.43 -
Collar Nov./06 - Mar./07 38,095 mcf $11.15/mcf $ 5,818
$6.74 -
Collar Apr./07 - Oct./07 28,571 mcf $9.28/mcf 3,187
-----------
9,005
Crude Oil
US$75.00 -
Collar Jan./07 - Dec./07 3,000 bbls $84.55/bbl 13,620
-----------
Unrealized risk management gain $ 22,625
-----------
-----------
The following financial instruments were entered into subsequent to
December 31, 2006:
Natural gas
$7.35 -
Collar Apr./07 - Oct./07 14,286 mcf $8.88/mcf
At December 31, 2005 the mark-to-market valuation of commodity
contracts resulted in a $3.2 million unrealized risk management loss.
ii) Deferred risk management loss
As at January 1, 2004, the Company elected not to designate any of
its risk management activities as accounting hedges and accordingly
accounts for all derivative instruments using the mark-to-market
method. As a result, on January 1, 2004, the Company recorded a
liability and a deferred risk management loss of $10.9 million
relating to then outstanding commodity hedges and the interest rate
swap. During the year ended December 31, 2006, $1.6 million (2005 -
$1.6 million) of the deferred loss was charged to earnings. The
remaining balance of $4.0 million at December 31, 2006 (2005 -
$5.6 million) relates to the interest rate swap and will be charged
to earnings in annual amounts of $1.6 million until eliminated in
2009 upon the termination of the swap contract.
iii) Cross currency interest rate swap
Concurrent with the issuance of 9.90% Senior Notes in 2002, the
Company entered into interest rate swap arrangements expiring May
2009 that convert fixed rate U.S. 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. Accordingly, the swap remains outstanding and at
December 31, 2006, the Company valued the liability relating to
future unrealized losses on the swap arrangements to be $11.4 million
(2005 - $14.8 million) on a mark-to-market basis. The current portion
of this amount at December 31, 2006 is $4.6 million (2005 -
$4.6 million).
iv) Risk management (gain) loss
Risk management (gains) and losses recognized during the periods
relating to commodity prices, foreign exchange notes and the interest
rate swap are summarized below:
Interest
Year ended December 31, Commodity Foreign Rate
2006 Contracts Currency Swap 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) (1,405) 4,423 (36,199)
--------- --------- --------- ----------
Total (gain) loss $ (64,992) $ (1,405) $ 2,676 $ (63,721)
--------- --------- --------- ----------
--------- --------- --------- ----------
Year ended December 31, Commodity Foreign Rate
2005 Contracts Currency Swap Total
--------- --------- --------- ----------
Unrealized
Amortization of deferred
loss $ - $ - $ 1,642 $ 1,642
Change in fair value 5,136 - 3,393 8,529
--------- --------- --------- ----------
5,136 - 5,035 10,171
Realized
Cash settlements 9,663 - (532) 9,131
--------- --------- --------- ----------
Total loss $ 14,799 $ - $ 4,503 $ 19,302
--------- --------- --------- ----------
--------- --------- --------- ----------
Year ended December 31, Commodity Foreign Rate
2004 Contracts Currency Swap Total
--------- --------- --------- ----------
Unrealized
Amortization of
deferred loss $ 2,001 $ - $ 1,642 $ 3,643
Change in fair value (3,986) - 2,522 (1,464)
--------- --------- --------- ----------
(1,985) - 4,164 2,179
Realized
Cash settlements 9,151 - (2,522) 6,629
--------- --------- --------- ----------
Total loss $ 7,166 $ - $ 1,642 $ 8,808
--------- --------- --------- ----------
--------- --------- --------- ----------
b) Other financial instruments and risk
i) Credit risk management
Accounts receivable include amounts receivable for oil and natural
gas sales which are generally made to large credit worthy purchasers
and amounts receivable from joint venture partners which are
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.
ii) Fair value of financial assets and liabilities
The carrying value of cash, accounts receivable, other current
assets, current liabilities, and bank debt approximate fair value.
The estimated fair value of senior term notes was $503.4 million as
at December 31, 2006 versus the carrying amount of $524.4 million.
Other current assets are comprised of prepaid expenses, Crown royalty
deposits and marketable securities valued at cost. The fair value of
the marketable securities at December 31, 2006 exceeded the cost by
$1.3 million.
iii) Foreign currency risk management
The Company is exposed to fluctuations in the exchange rate between
the Canadian dollar and the U.S. dollar. Crude oil and to a certain
extent natural gas prices are based upon reference prices denominated
in U.S. dollars, while the majority of the Company's expenses are
denominated in Canadian dollars. When appropriate, the Company enters
into agreements to fix the exchange rate of Canadian dollars to U.S.
dollars in order to manage the risk.
On December 31, 2006, all existing foreign exchange contracts expired
and the Company has not entered into any new contracts subsequent to
year end.
17. Cash flow
Changes in non-cash working capital items increased (decreased) cash as
follows:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Accounts receivable and other
current assets $ 24,751 $ (17,371) $ (20,176)
Accounts payable (62,425) 78,385 39,598
Taxes payable - (301) (2,526)
------------ ------------ -----------
$ (37,674) $ 60,713 $ 16,896
------------ ------------ -----------
------------ ------------ -----------
Net change in non-cash working
capital
Relating to:
Operating activities $ 18,901 $ 8,441 $ (12,594)
Financing activities 1,278 (1,829) 324
Investing activities (57,853) 54,101 29,166
------------ ------------ -----------
$ (37,674) $ 60,713 $ 16,896
------------ ------------ -----------
------------ ------------ -----------
Amounts paid during the year relating to interest expense and capital
taxes were as follows:
Years ended December 31, 2006 2005 2004
------------ ------------ -----------
Interest paid $ 48,857 $ 31,444 $ 28,604
------------ ------------ -----------
------------ ------------ -----------
Current income taxes paid $ 14 $ 4,101 $ 4,952
------------ ------------ -----------
------------ ------------ -----------
18. Commitments and contingent liabilities
a) Commitments
The Company has committed to certain payments over the next five
years, as follows:
2007 2008 2009 2010 2011
--------- --------- --------- --------- ---------
Operating leases $ 3,737 $ 3,365 $ 2,846 $ - $ -
Office facilities 3,509 4,923 4,800 4,800 4,800
MPP partnership
distributions 9,172 9,172 3,057 - -
--------- --------- --------- --------- ---------
$ 16,418 $ 17,460 $ 10,703 $ 4,800 $ 4,800
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
The Company has entered into a lease agreement for new office
facilities commencing October 2008. Annual commitments under the
lease agreement are approximately $4.8 million per year for the 10
year term.
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.
19. Subsequent events
Prior to December 31, 2006, the Company entered into transactions for the
sale of certain minor non-core properties, effective at year end. The
transactions closed subsequent to year end and net proceeds of
$45.9 million from the dispositions were received. The dispositions have
been recorded as at the closing dates and have not been recognized in the
2006 financial statements.
Further Information
Additional information, including our Annual Information Form, is
available 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 Tuesday,
March 27, 2007 at 9:30 a.m. Mountain Standard Time (11:30 a.m. EST) to discuss
the Company's 2006 fourth quarter and 2006 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://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1775840
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 21223944 (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.
%SEDAR: 00003803E %CIK: 0001043572