EXHIBIT 20.3
------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
ADVISORIES
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") IS INTENDED TO PROVIDE BOTH AN
HISTORICAL AND PROSPECTIVE VIEW OF THE COMPANY'S ACTIVITIES. THE MD&A WAS
PREPARED AS AT MARCH 15, 2006 AND SHOULD BE READ IN CONJUNCTION WITH THE
AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES FOR THE YEAR ENDED
DECEMBER 31, 2005. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN
ACCORDANCE WITH CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP"). A
RECONCILIATION TO U.S. GAAP IS INCLUDED IN NOTE 19 TO THE CONSOLIDATED
FINANCIAL STATEMENTS.
ADDITIONAL ADVISORIES WITH RESPECT TO FORWARD LOOKING STATEMENTS, THE USE OF
NON-GAAP FINANCIAL MEASURES, AND THE USE OF BOE VOLUMETRIC MEASURES ARE SET
OUT AT THE END OF THIS MD&A.
CORPORATE OVERVIEW & STRATEGY
Compton Petroleum Corporation is an independent, public company actively
engaged in the exploration, development, and production of natural gas,
natural gas liquids, and crude oil in Western Canada. The Company's activities
are concentrated in three core geographic areas, primarily in Alberta, in the
Western Canada Sedimentary Basin. Compton's growth and reserve base has
resulted predominantly from exploration and development activities,
complemented by strategic acquisitions.
Compton's objective has been and remains that of building an exploration and
development company capable of delivering and sustaining long term growth.
Management has adhered to a consistent strategy in pursuing this objective.
Major components of Management's strategy currently include:
o concentrating activities in a limited number of core areas;
o focusing on unconventional natural gas in large resource plays;
o pursuing growth through the drill bit, complemented by selective
acquisitions;
o controlling infrastructure and operatorship; and
o maintaining financial flexibility.
RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
o Drilling program included 392 wells in 2005, with a 96% success rate,
more than double the 186 wells drilled in 2004.
o Annual production averaged 29,424 BOE/D, a 9% increase from the prior
year.
o Cash flow from operations increased 57% to $278 million driven by
production growth and strong commodity prices.
o Operating earnings for the year rose 100% to $94 million.
o Net earnings for the year increased 28% to $81 million.
-1-
CASH FLOW FROM OPERATIONS AND NET EARNINGS
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Cash flow from operations (1) ($000s) $ 278,112 $ 177,131 $ 154,893
Per share: basic $ 2.21 $ 1.51 $ 1.33
diluted $ 2.11 $ 1.43 $ 1.27
Net earnings ($000s) $ 81,326 $ 63,633 $ 118,880
Per share: basic $ 0.65 $ 0.54 $ 1.02
diluted $ 0.62 $ 0.51 $ 0.97
- -----------------------------------------------------------------------------------------------------------
(1) Cash flow from operations represents net earnings before depletion and
depreciation, future income taxes, and other non-cash expenses.
Cash flow from operations in 2005 reached a new high as a result of strong
commodity prices and increasing production levels.
Net earning in 2005 increased $18 million, or 28%, from 2004 and were reduced
by non-recurring one-time costs of $14.4 million ($20.8 million before taxes)
relating to the repurchase of U.S.$158.25 million of 9.90% Senior Notes. See
discussion on Tender Costs.
The following table reconciles cash flow from operating activities to cash
flow from operations.
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Cash flow from operating activities, as reported $ 286,553 $ 164,537 $ 156,211
Changes in non-cash operating working capital items (8,441) 12,594 (1,318)
- -----------------------------------------------------------------------------------------------------------
Cash flow from operations $ 278,112 $ 177,131 $ 154,893
- -----------------------------------------------------------------------------------------------------------
OPERATING EARNINGS
Operating earnings is a non-GAAP measure that adjusts net earnings by
non-operating items that Management believes reduce the comparability of the
Company's underlying financial performance between periods. The following
reconciliation of operating earnings has been prepared to provide investors
with information that is more comparable between years.
SUMMARY OF OPERATING EARNINGS
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s, except per share amounts) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Net earnings, as reported $ 81,326 $ 63,633 $ 118,880
Non-operational items, after tax
Unrealized foreign exchange (gain) (6,339) (11,821) (37,761)
Unrealized risk management loss 6,345 1,338 -
Stock-based compensation 3,682 2,094 451
Tender costs on repurchase of 9.90% notes 14,414 - -
Future tax recovery due to tax rate reductions (5,764) (8,359) (37,130)
- -----------------------------------------------------------------------------------------------------------
Operating earnings $ 93,664 $ 46,885 $ 44,440
Per share: basic $ 0.75 $ 0.40 $ 0.38
diluted $ 0.71 $ 0.38 $ 0.36
- -----------------------------------------------------------------------------------------------------------
-2-
The same factors that drove the increase in cash flow from operations - strong
commodity prices and higher production volumes - resulted in 2005 operating
earnings almost doubling the prior year level.
REVENUE
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
AVERAGE PRODUCTION
Natural gas (MMCF/D) 131 123 118
Liquids (BBLS/D) 7,646 6,330 5,924
- -----------------------------------------------------------------------------------------------------------
Total (BOE/D) 29,424 26,876 25,552
BENCHMARK PRICES
NYMEX (U.S.$/MMBTU) $ 8.55 $ 6.09 $ 5.60
AECO ($/MCF) $ 8.04 $ 6.44 $ 6.35
WTI (U.S.$/BBL) $ 56.56 $ 41.40 $ 31.04
Edmonton par ($/BBL) $ 68.72 $ 52.37 $ 43.14
REALIZED PRICES
Natural gas ($/MCF) $ 8.42 $ 6.46 $ 6.27
Liquids ($/BBL) 56.04 43.21 35.59
- -----------------------------------------------------------------------------------------------------------
Total ($/BOE) $ 51.95 $ 39.82 $ 37.16
- -----------------------------------------------------------------------------------------------------------
REVENUE ($000s)
Natural gas $ 401,468 $ 291,565 $ 269,622
Liquids 156,411 100,094 76,943
- -----------------------------------------------------------------------------------------------------------
Total $ 557,879 $ 391,659 $ 346,565
- -----------------------------------------------------------------------------------------------------------
Revenue in 2005 increased from the comparable period due to a combination of
increased production volumes and higher realized prices.
SUMMARY OF REVENUE INCREASES FROM PRODUCTION AND PRICING
- -----------------------------------------------------------------------------------------------------------
Natural Gas Liquids Total
($000s) Revenue Revenue Revenue
- -----------------------------------------------------------------------------------------------------------
Reported 2004 revenue $ 291,565 $ 100,094 $ 391,659
Increase in production volumes 21,659 26,579 48,238
Increase in prices 88,244 29,738 117,982
- -----------------------------------------------------------------------------------------------------------
Reported 2005 revenue $ 401,468 $ 156,411 $ 557,879
- -----------------------------------------------------------------------------------------------------------
Production volumes in 2005 increased 9% from 2004 as a result of the Company's
2005 drilling program. Production growth in Southern Alberta, which accounts
for 60% of Compton's total volumes, was hampered by abnormally wet weather
conditions during the summer months. Well completions, pipeline constructions,
and tie-ins scheduled for the second and third quarters were delayed by field
conditions, partially offsetting Compton's aggressive efforts to increase
annual production volumes.
-3-
Compton's natural gas production is sold under a combination of longer term
contracts with aggregators and short term daily or 30 day AECO indexed
contracts. Approximately 10% of the Company's natural gas production in 2005
was committed to aggregators, compared to an average of 11% in 2004. The
average aggregator price realized in 2005 was $1.25/MCF less than the
non-aggregator prices realized during the year.
Compton's 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. The Company
sells crude oil and natural gas liquids primarily to refineries and marketers
of crude oil and natural gas liquids.
From time to time, Compton may enter into hedging arrangements to mitigate
commodity price risk. In accordance with the Company's policy, hedging
programs will not exceed 50% of non-contracted production. Commodity hedge
gains and losses are reflected in "Risk Management" on the consolidated income
statements.
ROYALTIES
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s, except where noted) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Crown royalties $ 106,253 $ 75,859 $ 68,360
Other royalties 26,890 17,939 14,706
- -----------------------------------------------------------------------------------------------------------
Total royalties 133,143 93,798 83,066
Alberta royalty tax credit (426) (382) (500)
- -----------------------------------------------------------------------------------------------------------
Net royalties $ 132,717 $ 93,416 $ 82,566
Percentage of revenues 23.8% 23.9% 23.8%
- -----------------------------------------------------------------------------------------------------------
The Alberta royalty structure is based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. In 2005, the increased in the rate associated with increased
prices is offset by increased oil production and an increase in the number of
lower productivity gas wells, both which attract lower royalty rates.
OPERATING EXPENSES
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Operating expenses ($000s) $ 66,802 $ 55,655 $ 49,916
Operating expenses per boe ($/BOE) $ 6.22 $ 5.66 $ 5.35
- -----------------------------------------------------------------------------------------------------------
Operating costs per boe increased year over year due to an overall rise in
industry costs and the additional lifting costs associated with increased oil
production. High commodity prices in 2005 accelerated activity throughout the
oil and gas industry, increasing the demand for and cost of goods and
services. Particular increases of note include salaries for additional field
staff and contract operators, rising electricity prices in the latter half of
2005, salt water disposal, and emulsion processing.
-4-
TRANSPORTATION
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Transportation costs ($000s) $ 10,858 $ 8,595 $ 8,447
Transportation costs per boe ($/BOE) $ 1.01 $ 0.87 $ 0.91
- -----------------------------------------------------------------------------------------------------------
Compton incurs charges on the transportation of its 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.
Higher transportation costs in 2005 result from a combination of trucking
costs associated with increased crude oil production and surcharges associated
with rising fuel costs.
GENERAL AND ADMINISTRATIVE EXPENSES
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s, except where noted) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
General and administrative expenses $ 31,451 $ 24,663 $ 20,355
Capitalized general and administrative expenses (3,647) (2,683) (3,321)
Operator recoveries (6,581) (6,765) (4,828)
- -----------------------------------------------------------------------------------------------------------
Total general and administrative expenses $ 21,223 $ 15,215 $ 12,206
General and administrative per boe ($/BOE) $ 1.98 $ 1.55 $ 1.31
- -----------------------------------------------------------------------------------------------------------
As budgeted, general and administrative costs increased 39% in the last year.
The major component in this year over year increase, contributing 32%, was
additional employee costs associated with increased personnel levels and a
general increase in salaries necessary to attract and retain qualified
personnel in a very competitive industry. Other increases result from the
current regulatory environment including Sarbanes Oxley compliance and the
resulting increase in legal, audit, and reserve evaluation costs.
INTEREST EXPENSE
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Interest on bank debt, net $ 11,520 $ 9,662 $ 6,611
Interest on Senior Notes 20,912 21,281 21,711
- -----------------------------------------------------------------------------------------------------------
Interest expense 32,432 30,943 28,322
Finance charges 2,519 2,790 2,273
- -----------------------------------------------------------------------------------------------------------
Total interest and finance charges $ 34,951 $ 33,733 $ 30,595
- -----------------------------------------------------------------------------------------------------------
Interest costs in 2005 increased from the prior period due to higher debt
levels, precipitated by capital expenditures exceeding cash flow throughout
2005. Interest costs have also been affected by rising interest rates. The
impact on interest expense of issuing U.S.$300 million of 7 5/8% Senior Notes
late in the year was minimal.
-5-
TENDER COSTS
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s) 2005
- -----------------------------------------------------------------------------------------------------------
Premium payment $ 7,814
Consent solicitation fee 5,883
Pro-forma reduction of deferred financing charges on repayment of 9.90% Senior Notes 7,053
- -----------------------------------------------------------------------------------------------------------
Total tender costs $ 20,750
- -----------------------------------------------------------------------------------------------------------
In November 2005, the Company and a wholly owned subsidiary of the Company
completed a tender offer and consent solicitation to purchase Compton's 9.90%
Senior Notes due in 2009. Holders of U.S.$158.25 million (approximately 96%)
of the outstanding 9.90% Notes tendered the notes and delivered consents to
amend the Indenture. The premium payment for notes tendered was 104.195% plus
accrued and unpaid interest, and the note holders that delivered consents
received 103% for a total consideration of 107.195%.
The unamortized portion of deferred financing charges related to the tendered
portion of the 9.90% Senior Notes of $7.1 million was also included in tender
costs.
NETBACKS
- ----------------------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31, ($/BOE) 2005 2004 2003
- ----------------------------------------------------------------------------------------------------------
Realized price $ 51.95 $ 39.82 $ 37.16
Royalties, net (12.36) (9.50) (8.85)
Operating expenses (6.22) (5.66) (5.35)
Transportation (1.01) (0.87) (0.91)
- ----------------------------------------------------------------------------------------------------------
Field operating netback $ 32.36 $ 23.79 $ 22.05
- ----------------------------------------------------------------------------------------------------------
General and administrative (1.98) (1.55) (1.31)
Interest (3.25) (3.43) (3.28)
Current taxes (0.47) (0.28) (0.35)
- ----------------------------------------------------------------------------------------------------------
Cash flow netback $ 26.66 $ 18.53 $ 17.11
- ----------------------------------------------------------------------------------------------------------
RISK MANAGEMENT
Compton's financial results are impacted by external market risks associated
with fluctuations in commodity prices, interest rates, and the Canadian/U.S.
exchange rate. The Company utilizes various financial instruments for
non-trading purposes to manage and mitigate its exposure to these risks. The
Company records financial instruments, not designated or not qualifying for
hedge accounting, 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 to the Company which is recognized as a realized Risk
Management gain or loss at the time of settlement.
The mark-to-market fair value of a financial instrument outstanding at the end
of a reporting period, reflects the value of the instrument based upon the
market conditions existing as of that date. Any change in the fair value of
the instrument 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 so recognized may or may not be realized in
subsequent periods depending upon subsequent moves in commodity prices,
interest rates, or exchange rates affecting the financial instrument.
-6-
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 in earnings that may not be
particularly meaningful in assessing the Company's financial performance
between periods.
Risk management gains and losses recognized in 2005 are outlined below.
- ----------------------------------------------------------------------------------------------------------
Year ended December 31, ($000s) 2005 2004 2003
- ----------------------------------------------------------------------------------------------------------
Commodity contracts
Realized loss $ 9,663 $ 9,151 $ 5,497
Unrealized loss (gain) 5,136 (1,985) -
Cross currency interest rate swap
Realized (gain) (532) (2,522) (1,365)
Unrealized loss 5,035 4,164 -
- ----------------------------------------------------------------------------------------------------------
Total risk management loss $ 19,302 $ 8,808 $ 4,132
- ----------------------------------------------------------------------------------------------------------
Realized loss $ 9,131 $ 6,629 $ 4,132
Unrealized loss 10,171 2,179 -
- ----------------------------------------------------------------------------------------------------------
Total risk management loss $ 19,302 $ 8,808 $ 4,132
- ----------------------------------------------------------------------------------------------------------
DEPLETION AND DEPRECIATION
- ----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- ----------------------------------------------------------------------------------------------------------
Total depletion and depreciation ($000s) $ 105,504 $ 82,554 $ 61,749
Depletion and depreciation per boe ($/BOE) $ 9.82 $ 8.39 $ 6.62
- ----------------------------------------------------------------------------------------------------------
The Company's 2005 provision for depletion and depreciation increased $23
million or 28% over 2004. Approximately one third of this increase was due to
the increase in 2005 production over that of 2004 with the balance being the
result of an overall increase in the depletion and depreciation rate as
determined on a boe basis. The depletion and depreciation rate on a boe basis
reflects increased costs relating to exploration and development activities as
discussed in capital expenditures.
FOREIGN EXCHANGE
The foreign exchange gain recognized on the consolidated statements of
earnings results primarily from the translation of the Company's U.S. dollar
denominated Senior Notes into Canadian dollars. The Senior Notes are
translated and recorded in the financial statements at the year end exchange
rate, with any differences from prior measurements recorded as unrealized
foreign exchange gain or loss.
-7-
The Canadian/U.S. exchange rate increased to one Canadian Dollar being equal
to U.S.$0.8577 on December 31, 2005 from one Canadian Dollar being equal to
U.S.$0.8308 at December 31, 2004, resulting in the Company recording a $7
million foreign exchange gain in 2005.
On November 22, 2005, pursuant to a tender offer, the Company repurchased
U.S.$158.25 million of the 9.90% Senior Notes issued in 2002. As a result of
the repurchase, the Company crystallized $62.2 million of the accumulated
unrealized foreign exchange gains that had been previously recognized with the
strengthening of the Canadian dollar subsequent to the note issuance.
STOCK-BASED COMPENSATION
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Options granted (000s) 2,930 2,549 1,503
Weighted average fair value of options granted ($/share) $ 5.45 $ 3.70 $ 3.01
Stock-based compensation expense recognized ($000s) $ 5,903 $ 3,410 $ 760
- -----------------------------------------------------------------------------------------------------------
Compton has a stock option plan for Directors, Officers, and employees. The
plan is designed to attract, motivate, and retain outstanding individuals and
to align their success with that of the Shareholders through achieving
corporate objectives. 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.
TAXES
CURRENT TAXES
Current taxes include federal capital tax which decreased to $1.9 million in
2005 from $2.5 million in 2004 (2003 - $2.5 million) due mainly to a tax rate
reduction from 0.200% to 0.175%, as part of the phased elimination of federal
capital tax by 2008.
Current taxes in 2005 also include $3.2 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 have been added to Compton's tax pools.
FUTURE INCOME TAXES
The Company's future income taxes were $52.3 million in 2005, compared to
$33.4 million in 2004 and $20.0 million in 2003. Future taxes in 2004
benefited from an $8 million recovery due to a reduction in the Alberta tax
rate from 12.5% to 11.5%. Future taxes in 2003 reflected a recovery of $37
million due to reductions in Canadian federal and Alberta corporate tax rates
and related changes to the Canadian federal resource allowance and
deductibility of provincial crown charges paid.
-8-
CORPORATE TAX RATES
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Statutory rate 37.6% 38.6% 40.6%
Effective rate 39.5% 35.0% 16.4%
- -----------------------------------------------------------------------------------------------------------
A reconciliation of the Company's effective tax rate to the statutory rate may
be found in Note 15(a) to the consolidated financial statements.
TAX POOLS
The following table summarizes Compton's estimated tax pool balances by
classification.
- -----------------------------------------------------------------------------------------------------------
AVAILABLE MAXIMUM
BALANCE ANNUAL
As at January 1, 2006 ($000S) DEDUCTION
- -----------------------------------------------------------------------------------------------------------
Canadian exploration expense $ 87,748 100%
Canadian development expense 322,165 30%
Canadian oil and natural gas property expense 217,203 10%
Undepreciated capital cost and financing costs 222,540 ~25%
- -----------------------------------------------------------------------------------------------------------
Total $ 849,656
- -----------------------------------------------------------------------------------------------------------
A significant portion of the Company's taxable income is generated by a wholly
owned partnership. Consolidated earnings before income taxes include $263
million (2004 - $178 million) of partnership earnings that will be included in
the following year's income for income tax purposes. Future income taxes
include $94 million (2004 - $67 million) as a result of this deferral of
partnership earnings.
Based upon planned capital expenditure programs and current commodity price
assumptions, it appears the Company will not be cash taxable until 2009.
CAPITAL EXPENDITURES
SUMMARY OF CAPITAL EXPENDITURE ALLOCATION
- -----------------------------------------------------------------------------------------------------------
Years ended December 31, 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
($000S) % ($000s) % ($000s) %
- -----------------------------------------------------------------------------------------------------------
Drilling and completions $318,502 62 $175,003 57 $126,308 57
Land and seismic 55,469 11 38,326 12 37,128 17
Facilities 109,729 21 68,861 23 46,068 21
Acquisitions, net 28,575 6 22,825 8 11,224 5
- -----------------------------------------------------------------------------------------------------------
Sub-total 512,275 100 305,015 100 220,728 100
MPP 1,261 11,386 64,755
- -----------------------------------------------------------------------------------------------------------
Total capital expenditures $513,536 $316,401 $285,483
- -----------------------------------------------------------------------------------------------------------
-9-
In 2005, Compton significantly increased its drilling program over that of
previous years with the express objective of realizing on its unbooked
resource potential. The Company drilled 334 net wells (392 gross) in 2005 as
compared to 146 net wells (186 gross) in 2004. The number of net wells drilled
in 2005 increased 129% over the number of net wells drilled in 2004.
Reflecting this growth in activity, total 2005 capital expenditures, excluding
MPP related expenditures, increased $207 million, or 68%, from $305 million in
2004 to $512 million in 2005.
As would be expected with the increased well count, 70% of the increase in
capital expenditures relates to drilling and completion costs which increased
$143 million from $175 million in 2004 to $319 million in 2005. On a per well
basis, drilling and completion costs actually decreased 21% to an average of
$0.95 million per net well in 2005 from an average of $1.2 million per net
well in 2004. The decrease in the average cost per well reflects the Company's
drilling focus during 2005. The Company's 2005 drill program included an
additional 80 wells targeting Charlie Lake oil at Cecil and Worsley and an
additional 110 wells targeting shallower Belly River gas in Southern Alberta
as compared to 2004. These wells, and particularly the Belly River wells, are
lower cost as compared to the deeper targets that comprise a greater
percentage of the 2004 drill count.
Facility expenditures, which included processing facilities, gathering
systems, compression and well equipment, comprised 21% of total capital
expenditures and increased in relation to the Company's increased level of
activity.
Strong commodity prices have accelerated capital programs and competition
throughout the oil and gas industry, raising the demand and costs of land,
drilling rigs, completion services, and supplies. During 2005, Compton
experienced cost increases ranging as high as 20% for certain services over
2004 levels. In addition to the increased level of activity in 2005, capital
expenditures for the year reflect this overall increase in the cost of goods
and services.
LIQUIDITY AND CAPITAL RESOURCES
- -----------------------------------------------------------------------------------------------------------
As at December 31, ($000s, except where noted) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Working capital (1) $ 62,431 $ 603 $ (21,843)
Bank debt 177,900 220,000 164,500
Senior term notes 357,640 198,594 213,246
- -----------------------------------------------------------------------------------------------------------
Total indebtedness $ 597,971 $ 419,197 $ 355,903
Capital stock $ 226,444 $ 135,526 $ 131,577
Contributed surplus 9,173 3,840 760
Retained earnings 360,719 284,712 224,569
- -----------------------------------------------------------------------------------------------------------
Shareholders' equity $ 596,336 $ 424,078 $ 356,906
Debt to cash flow from operations (2) (3) 1.93 2.36 2.44
Debt to book capitalization (2) 47% 50% 51%
Debt to market capitalization (2) 20% 25% 35%
- -----------------------------------------------------------------------------------------------------------
(1) Working capital excludes unrealized risk management items.
(2) Debt includes current and long term portion and excludes unrealized risk
management items.
(3) Based on trailing 12 month cash flow from operations.
Working capital at December 31, 2005 decreased from the prior year due to the
Company's extremely active fourth quarter and the resulting increase in trade
payables. At year end, Compton had drawn $178 million on its available $289
million syndicated credit facility.
-10-
In November 2005, a wholly owned subsidiary of the Company issued U.S.$300
million of 7 5/8% Senior Notes due in 2013. The proceeds were used to repay a
portion of the Company's debt under its senior secured credit facilities and to
fund the purchase of a portion of the 9.90% Senior Notes due in 2009, by a
wholly owned subsidiary of the Company. At December 31, 2005, U.S.$6.75 million
of the 9.90% Notes remain outstanding but can be called, at a premium, anytime
after May 15, 2006. The purchase of the 9.90% Notes eliminated the restrictive
covenants of the Indenture agreement and have provided the Company with greater
financial flexibility.
The principal amount of the Senior Notes remains fixed at U.S. $300 million.
The value of the notes shown on the consolidated balance sheets varies in
response to movement in the Canadian/U.S. dollar exchange rate. Standards &
Poor's Rating Services ("S&P") and Moody's Corporation ("Moody's") have rated
the Company as B+ stable and B1 stable respectively, as at December 31, 2005.
The U.S. $300 million 7 5/8% Senior Notes are rated as B stable and B2 stable.
The Company expects internally generated operating cash flow together with
other available financing options, including debt financing, readily
accessible equity markets, and potential minor non-core property dispositions,
will fund its planned 2006 capital program while maintaining fiscal
responsibility.
CONTRACTUAL OBLIGATIONS
As part of normal business, Compton has 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 the Company's contractual obligations as at
December 31, 2005.
- -----------------------------------------------------------------------------------------------------------
PAYMENTS DUE BY PERIOD
($000s) LESS THAN 1 YEAR 1-3 YEARS 4-5 YEARS AFTER 5 YEARS
- -----------------------------------------------------------------------------------------------------------
Partnership distributions $ 9,172 $ 21,401 $ - $ -
Operating leases 11,277 7,418 - -
Office rent 1,356 249 - -
Senior Notes - 7,870 - 349,770
Other 52 - - -
- -----------------------------------------------------------------------------------------------------------
Total $ 21,857 $ 36,938 $ - $ 349,770
- -----------------------------------------------------------------------------------------------------------
The Company has the ability and intends to extend the term of its current
borrowings of $178 million on an ongoing basis under its syndicated credit
facility and therefore repayment of the facility is not included in the
schedule of contractual obligations above.
COMMITMENTS
To prevent the expiration of undeveloped lands, the Company anticipates $65
million of work commitments will be required in 2006. These commitments have
been included in our 2006 capital expenditure budget.
-11-
GUIDANCE FOR 2006
Compton's 2006 budget was prepared in December 2005, and reflected commodity
price forecasts at that time. With the recent decline in natural gas prices,
the Company has reassessed its budget in relation to current prices. Current
lower prices will reduce cash flow by $80 million from that originally
projected if sustained over the remainder of the year. At this juncture, the
Company has not revised its drilling and capital programs.
In 2006, Compton will continue to focus on the development of its five natural
gas resource plays and conventional crude oil property to maximize reserve
recognition and production growth.
SUMMARY OF 2006 GUIDANCE
- -----------------------------------------------------------------------------------------------
2006 BUDGET RANGE
- -----------------------------------------------------------------------------------------------
Capital expenditures ($MILLIONS) $575
Gross wells 480
Average production
Natural gas (MMCF/D) 155 to 160
Liquids (BBLS/D) 11,000 to 11,300
- -----------------------------------------------------------------------------------------------
Total (BOE/D) 37,000 to 38,000
Cash flow from operations ($MILLIONS) $375 to $390
- -----------------------------------------------------------------------------------------------
The Company's revised 2006 projected cash flow from operations projection is
based upon the following pricing assumptions:
- -----------------------------------------------------------------------------------------------
BENCHMARK REALIZED
- -----------------------------------------------------------------------------------------------
Natural gas AECO Cdn $7.90/GJ Cdn $8.15/MCF
Crude oil ($/BBL) WTI U.S. $62.00 Cdn $65.00
- -----------------------------------------------------------------------------------------------
The average Canadian/U.S. exchange rate is budgeted at $0.85 U.S. = $1.00 Cdn.
CASH FLOW SENSITIVITIES FOR 2006
- -----------------------------------------------------------------------------------------------
($millions)
- -----------------------------------------------------------------------------------------------
Change of Cdn $0.10/MCF in the benchmark AECO natural gas price $4.5
Change of U.S. $1.00/barrel in the benchmark WTI oil price $3.0
- -----------------------------------------------------------------------------------------------
In the event of significant decreases in commodity prices, increases in
exploration costs, or an overall economic downturn, the Company's capital
expenditure program can be readily modified.
ADDITIONAL DISCLOSURES
EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
Compton has carried out an evaluation under the supervision and with the
participation of its Management, including its President & CEO and VP Finance
& CFO, of the effectiveness of the design and operation of the Company's
disclosure controls and procedures. Based upon its evaluation, Compton has
concluded that, as of December 31, 2005, the disclosure controls and
procedures were effective in all material respects. The term "disclosure
controls and procedures" is defined under the Security and Exchange
Commission's Exchange Act Rule 13a-15(d) as controls and other procedures of a
public company that are designed to ensure both non-financial and financial
information required to be disclosed by the company in its periodic reports is
recorded, processed, summarized, and reported in a timely fashion.
-12-
SARBANES OXLEY SECTION 404 UPDATE
Compton is required to comply with Section 404 of the Sarbanes Oxley Act of
2002. Section 404, together with the Security and Exchange Commission's
Exchange Act and other Rules and Regulations, requires Compton to evaluate and
certify its internal controls over financial reporting as at December 31,
2006, and have its evaluation and report thereto audited by its independent
external auditors.
Compton has developed a plan for meeting these requirements and is working
toward the execution of that plan. The Company is currently in the controls
remediation phase of the plan and is confident it will meet all the
requirements of Section 404 in the time required.
ACCOUNTING ESTIMATES
Accounting estimates require Management to make assumptions regarding matters
that are uncertain at the time the estimate is made and may have a material
impact on the financial condition of the Company. A comprehensive discussion
of Compton's significant accounting policies may be found in Note 1 to the
consolidated financial statements.
OIL AND NATURAL GAS RESERVES
The independent petroleum engineering and geological consulting firm of
Netherland Sewell evaluated and reported on 100% of Compton's oil and natural
gas reserves.
The estimation of reserves is a subjective process. Forecasts are based on
engineering data, projected future rates of production, and the timing of
future expenditures, all of which are subject to numerous uncertainties and
various interpretations. The Company expects that its estimates of reserves
will change with updated information from the results of future drilling,
testing, or production levels. Such revisions could be upwards or downwards.
Reserve estimates have a material impact on the depletion and depreciation,
asset retirement obligations, and impairment costs, all of which could
possibly have a material impact on consolidated net earnings.
DEPLETION
Capitalized costs and estimated future expenditures to develop proved
reserves, including abandonment costs, are depleted based on the proportion of
estimated proved oil and natural gas reserves produced during the year
compared to total proved reserves. Investments in unproved properties and
major development projects are not amortized until proved reserves associated
with the projects can be determined or until impairment occurs. If it is
determined that properties are impaired, the amount of the impairment is added
to the capitalized costs to be amortized.
In 2005, Compton incurred $106 million of depletion and depreciation. If the
proved reserves of the Company were to increase by 5%, the depletion and
depreciation expense would decrease by $0.8 million and consolidated net
earnings after tax would increase by $0.5 million. If the proved reserves of
the Company were to decrease by 5%, the depletion and depreciation expense
would increase by $1.9 million and consolidated net earnings after tax would
decrease by $1.2 million.
-13-
IMPAIRMENT
In applying the full cost method of accounting, Compton periodically
calculates a ceiling or limitation on the amount that property and equipment
may be carried for on the consolidated balance sheets. An impairment exists if
the undiscounted future net cash flows from proved reserves at future
commodity prices plus the cost of undeveloped properties is less than the
carrying value of the capitalized costs. As at December 31, 2005 the ceiling
amount calculated was $2.5 billion in excess of the carrying value of the
costs capitalized.
If an impairment is found to exist, the impaired properties are written down
to their fair value. The fair value of the assets is calculated based on
future net cash flows from proved plus probable reserves, discounted at a risk
free interest rate using future commodity prices, plus the cost of undeveloped
properties. An impairment may result in a material loss for a particular
period; however, future depletion and depreciation expense would be reduced as
a result.
Assumptions about reserves and future prices are required to calculate future
net cash flows. The assumptions made to estimate reserves have been discussed
above. There is significant uncertainty regarding forecasting future commodity
prices due to economic and political uncertainties. Future prices are derived
from a consensus of price forecasts among recognized reserve evaluators.
Estimates of future cash flows assume a long term price forecast and current
operating costs per boe plus an inflation factor.
It is difficult to determine and assess the impact of a decrease in proved
reserves on impairment. The relationship between reserve estimates and the
estimated undiscounted cash flows, and the nature of the property-by-property
impairment test is complex. As a result, it is not possible to provide a
reasonable sensitivity analysis of the impact that a reserve estimate decrease
would have on impairment. No material downward revisions to the Company's
reserves are anticipated.
ASSET RETIREMENT OBLIGATION
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 term
assets such as well sites, pipelines, and facilities. The asset retirement
cost, equal to the initially estimated fair value of the asset retirement
obligation, is capitalized as part of the cost of the related long term
assets. Increases in the asset retirement obligations resulting from the
passage of time are recorded as accretion of asset retirement obligations in
the consolidated statement of earnings. Amounts recorded for asset retirement
obligations are subject to uncertainty associated with the method, timing, and
extent of future retirement activities. Actual payments to settle the
obligations may differ from estimated amounts.
RISK MANAGEMENT
Compton's operations are subject to risks inherent to the oil and natural gas
industry. The Company is exposed to financial risks including fluctuations in
commodity prices, currency exchange rates, interest rates, credit ratings, and
changing expenditure costs due to shifts in market conditions. The Company
takes specific measures to manage these risks, particularly those that impact
cash flow from operations.
A more detailed discussion of risk factors is presented in the Company's most
recent Annual Information Form, filed with securities regulatory authorities
on www.sedar.com.
-14-
COMMODITY PRICE RISK MANAGEMENT
Compton enters into commodity price contracts to manage risk associated with
price volatility to protect cash flow from operations required to fund the
Company's capital program. Commodity price risk is actively managed by using
costless collars and by balancing physical and financial contracts in terms of
volumes, timing of performance, and delivery obligations. Net open positions
may exist or may be established to take advantage of market conditions. Net
earnings for the year ended December 31, 2005 include realized and unrealized
losses of $15 million (2004 - $7 million loss) on these transactions.
The following table outlines commodity hedge transactions which are currently
outstanding.
- -----------------------------------------------------------------------------------------------------------
COMMODITY TERM AMOUNT AVERAGE PRICE INDEX
- -----------------------------------------------------------------------------------------------------------
Natural gas
Collar Nov. 2005 - Mar. 2006 40,000 GJ/d Cdn$8.56 - $12.79 AECO
Fixed Nov. 2005 - Mar. 2006 10,000 GJ/d Cdn$8.60 AECO
Collar Apr. 2006 - Oct. 2006 45,000 GJ/d Cdn$8.33 - $12.23 AECO
Crude oil
Collar Jan. 2006 - Dec. 2006 3,000 bbls/d U.S.$55.00 - $75.17 WTI
- -----------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
Compton is exposed to fluctuations in the exchange rate between the Canadian
dollar and the U.S. dollar. Commodity prices are based on U.S. dollar
benchmarks that result in Compton's realized price being influenced by the
Canadian/U.S. currency exchange rate. Should the Canadian dollar strengthen
compared to the U.S. dollar, the negative effect on net earnings would be
partially offset by foreign exchange gains on the Company's U.S. dollar
denominated Senior Notes. Conversely, should the Canadian dollar weaken
compared to the U.S. dollar, the positive effect on net earnings would be
partially offset by foreign exchange losses on the Company's U.S. dollar
denominated Senior Notes. Cash flow from operations is not impacted by the
effects of currency fluctuations on the Company's U.S. dollar denominated
Senior Notes.
INTEREST RATE RISK MANAGEMENT
Concurrent with the closing of the Company's 9.90% Senior Notes offering in
May of 2002, Compton entered into a cross currency interest rate swap. The
swap, which converted fixed rate U.S. dollar interest obligations into
floating rate Canadian dollar interest obligations, was entered into to fix
the exchange rate on interest payments and take advantage of lower floating
interest rates. On repurchase of the majority of 9.90% Senior Notes in
November 2005, the Company elected not to collapse the swap and incur the
associated costs of $12.2 million. The swap remains outstanding and at
December 31, 2005 the Company valued the liability relating to future
unrealized losses on the swap arrangement to be $14.8 million (2004 - $11.4
million) determined on a mark-to-market basis. The loss associated with the
swap has resulted primarily from the strengthening of the Canadian dollar.
Should the Canadian dollar continue to increase against the U.S. dollar, the
loss could increase further; alternatively if the Canadian dollar were to
weaken the loss would be reduced. Cash settlements of the swap positions are
made semi-annual and losses realized will be recorded over the remaining term
of the swap agreement which expires in May 2009.
-15-
SELECTED QUARTERLY INFORMATION
The following tables set out selected quarterly financial information of the
Company for the last two fiscal years.
- ----------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED YEAR ENDED
- ----------------------------------------------------------------------------------------------------------
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, DEC. 31,
($000s, except where noted) 2005 2005 2005 2005 2005
- ----------------------------------------------------------------------------------------------------------
Average production (BOE/D) 28,714 28,877 29,041 31,042 29,424
Average pricing ($/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 $ 0.17 $ 0.09 $ 0.30 $ 0.65
diluted $ 0.08 $ 0.17 $ 0.08 $ 0.28 $ 0.62
- ----------------------------------------------------------------------------------------------------------
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.
FOURTH QUARTER 2005
Average fourth quarter 2005 production increased 7% from the third quarter of
2005, with production in December 2005 reaching approximately 35,500 boe/d.
Due to the abnormally wet weather in Southern Alberta during the summer
months, well completions, tie-ins, and pipeline constructions were postponed
until the fourth quarter. Revenue and net earnings for the quarter benefited
from increased production and high commodity prices.
-16-
- -------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED YEAR ENDED
- -------------------------------------------------------------------------------------------------------
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, DEC. 31,
($000s, except where noted) 2004 2004 2004 2004 2004
- -------------------------------------------------------------------------------------------------------
Average production (BOE/D) 25,717 26,295 27,268 28,204 26,876
Average pricing ($/BOE) $ 38.04 $ 41.43 $ 40.78 $ 39.00 $ 39.82
Total revenue $ 89,031 $ 99,140 $ 102,299 $ 101,189 $ 391,659
Cash flow from operations $ 40,860 $ 47,698 $ 46,844 $ 41,729 $ 177,131
Per share: basic $ 0.35 $ 0.41 $ 0.40 $ 0.35 $ 1.51
diluted $ 0.33 $ 0.39 $ 0.38 $ 0.33 $ 1.43
Operating earnings $ 14,235 $ 15,428 $ 10,863 $ 6,359 $ 46,885
Net earnings $ 22,301 $ 2,978 $ 21,977 $ 16,377 $ 63,633
Per share: basic $ 0.19 $ 0.03 $ 0.19 $ 0.14 $ 0.54
diluted $ 0.18 $ 0.02 $ 0.18 $ 0.13 $ 0.51
- -------------------------------------------------------------------------------------------------------
In 2004, strong overall commodity prices and increasing production improved
total revenue on a quarterly basis. Average production in 2004 grew as a
result of the Company's ongoing drilling program and the resolution of
facility and pipeline restrictions in Southern Alberta. Net earnings in the
second quarter of 2004 was impacted by an unrealized risk management loss of
$7 million after tax and an unrealized foreign exchange loss of $4 million
after tax. Net earnings in the first, third, and fourth quarters in 2004
benefited from unrealized risk management gains.
SELECTED ANNUAL INFORMATION
- ------------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s) 2005 2004 2003
- ------------------------------------------------------------------------------------------------------------
Total revenue $ 557,879 $ 391,659 $ 346,565
Net earnings $ 81,326 $ 63,633 $ 118,880
Per share: basic $ 0.65 $ 0.54 $ 1.02
diluted $ 0.62 $ 0.51 $ 0.97
Total assets $ 1,755,489 $ 1,330,611 $ 1,064,320
Total long term financial liabilities $ 535,540 $ 198,594 $ 213,246
- ------------------------------------------------------------------------------------------------------------
Total revenue in 2005 was higher than in the two previous years due to a
combination of increased production and higher commodity prices. Net earnings
in 2005 increased $18 million, 28%, from 2004 and were reduced by
non-recurring one-time costs of $14.4 million ($20.8 million before taxes)
relating to the repurchase of U.S.$158.25 million of 9.90% Senior Notes.
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 the Company issuing U.S.$300 million Senior
Notes and reclassifying bank debt as long term.
-17-
Net earnings in 2004 decreased from the prior year as 2003 benefited from a
$38 million after tax unrealized foreign exchange gain on the Company's U.S.
dollar denominated debt and a $37 million recovery of future income taxes
relating to statutory income tax rate changes.
Total assets were $1.3 billion at December 31, 2004, an increase of 25% from
the prior year due to capital expenditures of $316 million. The change in long
term financial liabilities at December 31, 2004 resulted from an unrealized
gain due to the translation of the Company's U.S. $165 million Senior Notes.
TRADING AND SHARE STATISTICS
As at March 15, 2006 there were 127,272,451 common shares outstanding,
including 12,505,627 stock options outstanding.
- -----------------------------------------------------------------------------------------------------------
2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Average daily trading volume (000s) 736,416 674,764 686,100
Share price ($/share)
High $ 18.66 $ 11.43 $ 6.35
Low $ 9.80 $ 5.89 $ 4.40
Close $ 17.10 $ 10.85 $ 6.00
Market capitalization at December 31 ($000s) $ 2,176,205 $ 1,273,282 $ 698,535
Shares outstanding (000s) 127,263 117,354 116,423
- -----------------------------------------------------------------------------------------------------------
FURTHER INFORMATION
Additional information about Compton, including the Company's Annual
Information Form, is available on the Canadian Securities Administrators'
System for Electronic Document Analysis and Retrieval ("SEDAR") at
www.sedar.com.
FORWARD LOOKING STATEMENTS
CERTAIN INFORMATION REGARDING THE COMPANY CONTAINED HEREIN CONSTITUTES FORWARD
LOOKING STATEMENTS UNDER THE MEANING OF APPLICABLE SECURITIES LAWS, INCLUDING
THE UNITED STATES PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. FORWARD
LOOKING STATEMENTS INCLUDE ESTIMATES, PLANS, EXPECTATIONS, OPINIONS,
FORECASTS, PROJECTIONS, GUIDANCE OR OTHER STATEMENTS THAT ARE NOT STATEMENTS
OF FACT, INCLUDING STATEMENTS REGARDING (I) CASH FLOW, PRODUCTION, CAPITAL
EXPENDITURES AND PLANNED WELLS IN 2006, AND (II) OTHER RISKS AND UNCERTAINTIES
DESCRIBED FROM TIME TO TIME IN THE REPORTS AND FILINGS MADE BY COMPTON WITH
SECURITIES REGULATORY AUTHORITIES. ALTHOUGH COMPTON BELIEVES THAT THE
EXPECTATIONS REFLECTED IN SUCH FORWARD LOOKING STATEMENTS ARE REASONABLE, IT
CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO HAVE BEEN CORRECT.
THERE ARE MANY FACTORS THAT COULD CAUSE FORWARD LOOKING STATEMENTS NOT TO BE
CORRECT, INCLUDING RISKS AND UNCERTAINTIES INHERENT IN THE COMPANY BUSINESS.
THESE RISKS INCLUDE, BUT ARE NOT LIMITED TO: CRUDE OIL AND NATURAL GAS PRICE
VOLATILITY, EXCHANGE RATE FLUCTUATIONS, AVAILABILITY OF SERVICES AND SUPPLIES,
OPERATING HAZARDS AND MECHANICAL FAILURES, UNCERTAINTIES IN THE ESTIMATES OF
RESERVES AND IN 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. COMPTON MAY,
AS CONSIDERED NECESSARY IN THE CIRCUMSTANCES, UPDATE OR REVISE FORWARD LOOKING
INFORMATION, WHETHER AS A RESULT OF NEW INFORMATION, FUTURE EVENTS, OR
OTHERWISE. THE COMPANY'S FORWARD LOOKING STATEMENTS ARE EXPRESSLY QUALIFIED IN
THEIR ENTIRETY BY THIS CAUTIONARY STATEMENT.
-18-
NON-GAAP FINANCIAL MEASURES
INCLUDED IN THE MD&A AND ELSEWHERE IN THIS REPORT 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 THE COMPANY'S PERFORMANCE OR LIQUIDITY. CASH FLOW FROM
OPERATIONS IS USED BY COMPTON TO EVALUATE OPERATING RESULTS AND THE COMPANY'S
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 THE COMPANY 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. COMPTON HAS USED 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 COMPTON SELLS ITS
PRODUCTION VOLUMES AND THEREFORE MAY BE A MISLEADING MEASURE IF USED IN
ISOLATION.
-19-