EXHIBIT 20.3
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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, 2005 AND SHOULD BE READ IN CONJUNCTION WITH THE AUDITED
CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES FOR THE YEAR ENDED DECEMBER
31, 2004. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE
WITH CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP"). A
RECONCILIATION TO UNITED STATES GAAP IS INCLUDED IN NOTE 18 TO THE CONSOLIDATED
FINANCIAL STATEMENTS.
FORWARD LOOKING STATEMENTS
MANAGEMENT'S DISCUSSION AND ANALYSIS MAY CONTAIN CERTAIN FORWARD LOOKING
STATEMENTS UNDER THE MEANING OF APPLICABLE SECURITIES LAWS. FORWARD LOOKING
STATEMENTS INCLUDE ESTIMATES, PLANS, EXPECTATIONS, OPINIONS, FORECASTS,
PROJECTIONS, GUIDANCE OR OTHER STATEMENTS THAT ARE NOT STATEMENTS OF FACT.
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'S BUSINESS. THESE RISKS INCLUDE, BUT ARE
NOT LIMITED TO: CRUDE OIL AND NATURAL GAS PRICE VOLATILITY, EXCHANGE RATE
FLUCTUATIONS, AVAILABILITY OF SERVICES AND SUPPLIES, OPERATING HAZARDS,
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 OPERATOR AND REGULATORY PRONOUNCEMENTS. THE COMPANY'S FORWARD
LOOKING STATEMENTS ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THIS ADVISORY.
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, CASH FLOW PER SHARE AND ADJUSTED
NET EARNINGS FROM OPERATIONS. THESE TERMS ARE NOT DEFINED BY GAAP IN CANADA AND
CONSEQUENTLY ARE REFERRED TO AS NON-GAAP MEASURES. REPORTED AMOUNTS MAY NOT BE
COMPARABLE TO SIMILARLY TITLED MEASURES REPORTED BY OTHER COMPANIES.
CASH FLOW 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 IS USED BY COMPTON TO EVALUATE OPERATING
RESULTS AND THE COMPANY'S ABILITY TO GENERATE CASH TO FUND CAPITAL EXPENDITURES
AND REPAY DEBT.
ADJUSTED NET EARNINGS FROM OPERATIONS REPRESENTS NET INCOME EXCLUDING CERTAIN
ITEMS THAT ARE LARGELY NON-OPERATIONAL IN NATURE AND SHOULD NOT BE CONSIDERED AN
ALTERNATIVE TO, OR MORE MEANINGFUL THAN, NET EARNINGS AS DETERMINED IN
ACCORDANCE WITH CANADIAN GAAP. ADJUSTED NET EARNINGS FROM OPERATIONS IS USED BY
THE COMPANY TO INCREASE COMPARABILITY OF NET 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. IN SEVERAL SECTIONS THAT FOLLOW, 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.
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 Canadian Sedimentary Basin. Compton's growth and reserves base have
resulted 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 emphasis on natural gas with a particular focus on unconventional tight
gas reserves;
o concentration of activities in a limited number of core areas;
o development of technical expertise;
o growth and maintenance of a dominant land position and high working
interests in core areas;
o control of infrastructure and operatorship;
o full-cycle exploration; and
o strategic acquisitions.
RESULTS OF OPERATIONS
CASH FLOW AND NET EARNINGS
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Years ended December 31, 2004 2003 2002
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Cash flow ($000S) $ 177,131 $ $154,893 $ 96,072
Per share: basic $ 1.51 $ 1.33 $ 0.85
diluted $ 1.43 $ 1.27 $ 0.81
Net earnings ($000S) $ 63,633 $ 118,880 $ 18,312
Per share: basic $ 0.54 $ 1.02 $ 0.16
diluted $ 0.51 $ 0.97 $ 0.16
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2
Cash flow in 2004 rose from 2003 due to higher realized oil and natural gas
prices and increased production volumes, somewhat offset by an increase in
operating, general and administrative and interest expenses.
Cash flow, as commonly used in the oil and gas industry represents net income
before depletion and depreciation, future income taxes and other non-cash
expenses. The following table reconciles cash flow from operating activities to
cash flow.
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Years ended December 31, ($000s) 2004 2003 2002
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Cash flow from operating activities, as reported $164,537 $156,211 $90,906
Changes in non-cash operating working capital items 12,594 (1,318) 5,166
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Cash flow $177,131 $154,893 $96,072
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ADJUSTED NET EARNINGS FROM OPERATIONS
Net earnings are affected by items of a non-operational nature. To assist in the
comparability of net earnings between periods, the Company calculates adjusted
net earnings from operations, which eliminates the after tax effect of these
items.
The following reconciliation presents the after tax effects of items of a
non-operational nature that are included in the Company's financial results.
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Years ended December 31, ($000s, except per share amounts) 2004 2003 2002
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Net earnings, as reported $ 63,633 $ 118,880 $ 18,312
Non-operational items, after tax
Foreign exchange (gain) loss (11,821) (39,186) 1,249
Unrealized risk management loss 1,338 -- --
Stock-based compensation 2,094 451 --
Effect of statutory tax rate changes on future
income tax liabilities (8,359) (37,130) (1,340)
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Adjusted net earnings from operations $ 46,885 $ 44,440 $ 18,221
Per share - basic $ 0.40 $ 0.38 $ 0.16
- diluted $ 0.38 $ 0.36 $ 0.15
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3
REVENUE
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Years ended December 31, 2004 2003 2002
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AVERAGE PRODUCTION
Natural gas (MMCF/D) 123 118 112
Liquids (light oil & ngls) (BBLS/D) 6,330 5,924 6,503
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Total (BOE/D) 26,876 25,552 25,137
BENCHMARK PRICES
NYMEX (U.S.$/MMBTU) $ 6.09 $ 5.60 $ 3.37
AECO ($/MCF) $ 6.44 $ 6.35 $ 3.84
WTI (U.S.$/BBL) $ 41.40 $ 31.04 $ 26.09
Edmonton Par ($/BBL) $ 52.37 $ 43.14 $ 39.94
REALIZED PRICES (1)
Natural gas ($/MCF) $ 6.46 $ 6.27 $ 3.80
Liquids ($/BBL) 43.21 35.59 30.06
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Total ($/BOE) $ 39.82 $ 37.16 $ 24.70
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REVENUE (1) ($000S)
Natural gas revenue $ 291,565 $ 269,622 $ 155,234
Crude oil and ngls revenue 100,094 76,943 71,363
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Total $ 391,659 $ 346,565 $ 226,597
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(1) Restated to exclude realized hedge losses and transportation charges.
Revenue in 2004 increased from comparable periods due to a combination of
increased production volumes and higher realized prices.
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Natural Gas Oil & Ngls Total
Revenue Revenue Revenue
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Reported 2003 revenue (1) $269,622 $ 76,943 $346,565
Increase in production volumes 13,790 6,674 20,464
Increase in prices 8,153 16,477 24,630
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Reported 2004 revenue $291,565 $100,094 $391,659
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(1) Restated to exclude realized hedge losses and transportation charges.
Average production in 2004 increased 5% from 2003 as a result of the Company's
ongoing drilling program and the resolution of facility and pipeline restraints
in Southern Alberta. Production growth in Southern Alberta, which accounts for
approximately 60% of Compton's total volumes, was constrained by insufficient
compression, pipeline and processing capacity in the first half of 2004 and
throughout 2003. The expansion of the Mazeppa gas plant was completed on June 1,
2004, resulting in the elimination of these constraints. Production in December
2004 reached approximately 30,000 boe/d, before the disposition of 600 boe/d of
production at year end.
4
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 12% of the Company's natural gas production in 2004 was
committed to aggregators, compared to an average of 16% in 2003. The average
aggregator price realized in 2004 was approximately $0.32/mcf less than the
non-aggregator prices realized during the year.
Compton's crude oil sales are priced at 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 favorable 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 Compton'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
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Years ended December 31, ($000s, except where noted) 2004 2003 2002
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Crown royalties $75,859 $68,360 $38,902
Other royalties 17,939 14,706 9,095
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Total royalties 93,798 83,066 47,997
Alberta royalty tax credit (382) (500) (500)
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Net royalties $93,416 $82,566 $47,497
Percentage of revenues 23.9% 23.8% 21.0%
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The Alberta Crown royalty structure imposes higher royalty rates at higher
commodity prices and conversely, lower royalty rates at lower commodity prices.
Despite higher realized prices in 2004, the Company's average royalty rate was
only marginally higher than in 2003 due to a gas cost allowance adjustment
recorded in the second quarter of 2004.
OPERATING EXPENSES
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Years ended December 31, 2004 2003 (1) 2002 (1)
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Operating expenses ($000S) $55,655 $49,916 $45,546
Operating expenses per boe ($/BOE) $ 5.67 $ 5.35 $ 4.96
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(1) Restated to exclude transportation charges.
Operating costs per boe increased from 2003 due to an overall rise in the cost
of goods and services in the oil and gas industry and additional field staff
required for expanding operations.
TRANSPORTATION
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Years ended December 31, 2004 2003 2002
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Transportation costs ($000S) $ 8,595 $ 8,447 $8,167
Transportation costs per boe ($/BOE) $ 0.88 $ 0.91 $ 0.89
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5
Effective for 2004, Compton's transportation costs are disclosed separately in
the consolidated statements of earnings. Previously, transportation was
partially recorded as a reduction of revenue and partially as an increase in
operating expenses. For comparative purposes, 2003 and 2002 amounts have been
reclassified.
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.
Government regulated pipeline tolls dictate transportation rates for natural gas
in Alberta. Compton's transportation rates in 2004 have remained relatively
consistent with prior years on a per boe basis.
GENERAL AND ADMINISTRATIVE EXPENSES
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Years ended December 31, ($000s, except where noted) 2004 2003 2002
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General and administrative expenses $24,663 $20,355 $16,145
Capitalized general and administrative expenses (2,683) (3,321) (2,689)
Operator recoveries (6,765) (4,828) (3,611)
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Total general and administrative expenses $15,215 $12,206 $ 9,845
General and administrative per boe ($/BOE) $ 1.55 $ 1.31 $ 1.07
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Additional full time employees required due to the expanded activities of the
Company, additional regulatory and reporting related costs and higher insurance
costs contributed to increased G&A in 2004.
INTEREST EXPENSE
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Years ended December 31, ($000s) 2004 2003 2002
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Interest expense $ 33,733 $ 30,595 $ 23,197
Less: Finance charges (2,790) (2,273) (1,926)
Realized gain on interest rate swap (2,522) (1,365) (3,067)
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$ 28,421 $ 26,957 $ 18,204
Average debt $398,170 $339,190 $265,605
Average interest rate 7.1% 7.9% 6.9%
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Interest expense in 2004, excluding finance charges and gains realized on the
Company's interest rate swap, was consistent with the prior year. Compton
incurred higher average debt throughout 2004, however the impact on interest
expense was offset by lower interest rates. Debt levels in 2004 were elevated as
total capital expenditures in 2004 exceeded the current year's cash flow.
6
NETBACKS
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Years ended December 31, 2004 2003 (1) 2002
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NATURAL GAS LIQUIDS TOTAL Total Total
($/MCF) ($/BBL) ($/BOE) ($/boe) ($/boe)
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Realized price (2) $ 6.46 $43.21 $39.82 $37.16 $24.70
Royalties, net (1.58) (9.50) (9.50) (8.85) (5.18)
Operating expenses (3) (0.94) (5.66) (5.66) (5.35) (4.96)
Transportation (0.15) (0.87) (0.87) (0.91) (0.89)
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Field operating netback $ 3.79 $27.18 $23.79 $22.05 $13.67
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General and administrative (1.55) (1.31) (1.07)
Interest (3.43) (3.28) (2.53)
Current taxes (0.28) (0.35) (0.16)
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Cash flow netback $18.53 $17.11 $9.91
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(1) Restated to include the impact of MPP.
(2) Restated to exclude realized hedge gains and losses and transportation
charges.
(3) Restated to exclude transportation charges.
RISK MANAGEMENT
The Company'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 partially mitigate its exposure to these
risks. Commodity price contracts are employed to manage risk associated with
price volatility in order to protect cash flow for the Company's capital
expenditure program.
Concurrent with the closing of the senior notes offering in May of 2002, the
Company negotiated 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 also to take advantage of lower floating interest
rates.
On January 1, 2004, the Company adopted the CICA's Accounting Guideline 13,
"Hedging Relationships" (the "Guideline") and EIC 128, "Accounting for Trading,
Speculative or Non-Hedging Derivative Financial Instruments". Financial
instruments that are not designated or do not qualify as hedges under the
Guideline are recorded at fair value on the Company's consolidated balance
sheets, with subsequent changes recognized in consolidated net earnings. Fair
value is determined on a mark-to-market basis utilizing quoted market prices.
Previously, gains and losses resulting from financial instruments were
recognized only when realized.
Under EIC 128, unrealized gains or losses relating to contracts in effect at the
end of a period are recognized and included in risk management activity together
with realized gains and losses. Compton elected to not designate any financial
instruments as hedges and therefore follows EIC 128 accounting.
7
Adoption of EIC 128 resulted in the following:
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Year ended December 31, ($000s) 2004 2003 2002
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Commodity contracts
Realized loss (gain) $ 9,151 $ 5,497 $ (1,357)
Unrealized (gain) (1,985) -- --
Cross currency interest rate swap
Realized (gain) (2,522) (1,365) (3,067)
Unrealized loss 4,164 -- --
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Total risk management loss (gain) $ 8,808 $ 4,132 $ (4,424)
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Realized loss (gain) $ 6,629 $ 4,132 $ (4,424)
Unrealized loss 2,179 -- --
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Total risk management loss (gain) $ 8,808 $ 4,132 $ (4,424)
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DEPLETION AND DEPRECIATION
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Years ended December 31, 2004 2003 2002
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Total depletion and depreciation ($000S) $ 82,554 $ 61,749 $ 55,473
Depletion and depreciation per boe ($/BOE) $ 8.39 $ 6.62 $ 6.05
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Depletion and depreciation rates have risen in 2004 as the result of higher
capital expenditures incurred for the exploration for probable reserves and
optimization of proved developed reserves, resulting in an overall increase in
FD&A costs.
FOREIGN EXCHANGE
The foreign exchange gain on the consolidated statements of income is primarily
an unrealized gain resulting from the translation of the Company's U.S. $165
million senior term notes. The notes are recorded on the consolidated balance
sheets at the year end exchange rate with any differences booked as an
unrealized foreign exchange gain or loss. The Canadian dollar closed in 2004 at
U.S. $0.8308 compared to U.S. $0.7738 at December 31, 2003, resulting in a $15
million foreign exchange gain in 2004. The cumulative unrealized gain from the
date of issue of the notes in May 2002 is $61 million. The Company is currently
considering options to crystallize the unrealized gain.
STOCK-BASED COMPENSATION
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Years ended December 31, 2004 2003
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Options granted (000S) 2,549 1,503
Weighted average fair value of options granted ($/share) $ 3.70 $ 3.01
Stock-based compensation expense recognized ($000s) $ 3,410 $ 760
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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
8
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 income taxes include federal capital tax. This tax is non-deductible and
increases as the capital resources of the Company increase. In 2004, federal
capital tax remained relatively consistent with 2003. The higher capital
resources of the Company were offset by a rate reduction from 0.225% to 0.200%,
as part of the phased elimination of federal capital tax by 2008.
FUTURE INCOME TAXES
The Company's future income taxes were $33 million in 2004, compared to $20
million in 2003. Future taxes in 2003 benefited from a $37 million recovery due
to statutory rate reductions compared to an $8 million recovery in 2004.
CORPORATE TAX RATES
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Years ended December 31, 2004 2003 2003
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Statutory rate 38.6% 40.6% 42.1%
Effective rate 35.0% 16.4% 52.2%
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A reconciliation of the Company's effective tax rate to the statutory rate may
be found in Note 14(a) to the consolidated financial statements.
TAX POOLS
The following table summarizes Compton's estimated tax pool balances by
classification.
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AVAILABLE MAXIMUM
BALANCE ANNUAL
As at January 1, 2005 ($000S) DEDUCTION
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Canadian exploration expense $ 35,585 100%
Canadian development expense 159,127 30%
Canadian oil and natural gas property expense 182,399 10%
Undepreciated capital cost 129,047 4%-100%
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Total $506,158
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A significant portion of the Company's taxable income is generated by a wholly
owned partnership incurred on the partnership's earnings in the year following
its inclusion in the Company's consolidated net earnings.
Consolidated earnings before income taxes include $178 million (2003 - $166
million) of partnership earnings that will be included in the following year's
income for income tax purposes. Future income taxes include $67 million (2003 -
$63 million) as a result of this deferral of partnership earnings.
9
Based upon planed capital expenditure programs and current commodity price
assumptions, the Company will not be cash taxable until 2007.
CAPITAL EXPENDITURES
In 2004, the Company continued to invest in land and production facilities
together with exploratory and development drilling necessary for future growth.
Total capital expenditures in the current year were $316 million, including the
acquisition of Redwood Energy, Ltd. and Mayfair Energy Ltd.
Drilling and completions expenditures rose from the prior year due to an
increase in net wells drilled. Compton drilled 146 net wells compared to 134
wells in 2003. Drilling in the current year included additional wells at Hooker
and Callum, which are more costly due to their depth. Additionally, drilling
costs are increasing across the industry due to high demand for rigs, services
and materials.
Facilities expenditures in 2004 included an expansion of the Niton gas plant
from 10 mmcf/d to 20 mmcf/d; the installation of a 10 mmcf/d booster compressor
at Niton; expansion of pipelines and a battery in the Worsley area; installation
of compression plus a six inch pipeline from Brant to the Shouldice Gas Plant;
and debottlenecking and expansion of the Hooker pipeline system.
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Years ended December 31, 2004 2003 2002
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($000S) % ($000s) % ($000s) %
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Drilling and completions $175,003 57 $126,308 57 $ 75,369 48
Land and seismic 38,326 12 37,128 17 29,096 19
Facilities 68,861 23 46,068 21 21,714 14
Acquisitions, net 1,938 1 11,224 5 28,929 19
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Sub-total 284,128 93 220,728 100 155,108 100
Corporate acquisitions 20,887 7 -- -- -- --
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Sub-total 305,015 100 220,728 100 155,108 100
MPP 11,386 64,755 --
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Total capital expenditures $316,401 $285,483 $155,108
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10
LIQUIDITY AND CAPITAL RESOURCES
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As at December 31, ($000s, except where noted) 2004 2003 2002
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Working capital $ (1,382) $ (21,843) $ (32,139)
Current bank debt 220,000 164,500 40,000
Senior term notes 198,594 213,246 260,634
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$417,212 $355,903 $268,495
Shareholders' equity
Capital stock $135,526 $131,577 $128,079
Contributed surplus 3,840 760 --
Retained earnings 284,712 224,569 112,039
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$424,078 $356,906 $240,118
Debt to cash flow (1) (2) 2.36 2.44 3.13
Debt to EBITDA (3) 2.44 2.02 2.54
Debt to book capitalization (1) 50% 51% 56%
Debt to market capitalization (1) 25% 35% 34%
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(1) Debt includes current and long term portion.
(2) Based on trailing 12 month cash flow.
(3) EBITDA represents earnings from operations before interest, taxes,
depletion and depreciation and unrealized foreign exchange gain.
At year end, the Company had drawn $220 million on its available $240 million
syndicated credit facility. Debt levels at December 31, 2004 increased over 2003
as total capital expenditures exceeded the current year's cash flow.
The principal of the senior term notes remains fixed at U.S. $165 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.
The Company targets a debt to cash flow ratio of less than 2:1. Based upon the
company's 2005 budget, the equity issue noted below and proceeds of $50 million
from planned property sales, the Company projects a debt to cash flow ratio of
1.8:1 at December 31, 2005.
On February 18, 2005, Compton issued 7.5 million common shares at a price of
$12.00 per share for gross proceeds of $90 million. Funds from the issue were
used initially to repay a portion of the Company's current indebtedness and
thereafter to expand and accelerate our 2005 capital expenditure program.
Additionally, Compton plans to dispose of a number of minor, non-core property
interests in 2005. Proceeds are expected to be in the range of $50 to $60
million.
The Company is considering replacing up to $100 million of revolving, secured
borrowing based debt with longer fixed term subordinated debt. This will provide
additional availability under existing credit facilities and reduce Compton's
dependence on revolving demand bank debt. Various options are being considered
with the goal of finalizing the restructuring in conjunction with the annual
review of our existing credit facilities in the second quarter of 2005.
11
Compton expects funds generated from operations, proceeds from the common share
equity issue in February 2005, minor non-operated property dispositions and
funds available under the Company's existing bank credit facilities, will be
sufficient to finance operations and planned capital expenditures of $390
million in 2005.
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, 2004.
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PAYMENTS DUE BY PERIOD
($000s) LESS THAN 1 YEAR 1-3 YEARS 4-5 YEARS AFTER 5 YEARS
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Payment of senior notes $ -- $ -- $198,594 $ --
Partnership distributions 9,172 27,516 3,057 --
Operating leases 5,025 15,533 -- --
Office rent 1,268 1,605 -- --
Capital lease obligations 38 50 -- --
Other long term obligations 98 193 --
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Total $15,601 $44,897 $201,651 $ --
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The Company has the ability and intends to extend the term of its current
borrowings of $220 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
approximately $9 million of work commitments will be required in 2005. These
commitments have been included in our 2005 capital expenditure budget.
GUIDANCE FOR 2005
Compton's budget for 2005 is based upon the following:
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2005 BUDGET RANGE
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Capital expenditures ($MILLIONS) $390
Gross wells 390
Average production
Natural gas (MMCF/D) 144 - 148
Liquids (BBLS/D) 7,500 - 7,900
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Total (BOE/D) 31,500 - 32,500
Cash flow ($MILLIONS) $230 - $240
Per share- basic (1) $1.84 - $1.92
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(1) Based on shares outstanding as at March 15, 2005.
12
The Company's budgeted cash flow for 2005 is based upon the following
assumptions:
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BENCHMARK REALIZED CDN.
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Natural gas ($/MCF) AECO $ 6.25 Cdn $ 6.47
Crude oil ($/BBL) WTI $40.00 U.S. $42.07
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The average Canadian/U.S. exchange rate was budgeted at $0.83 U.S. = $1.00 Cdn.
CASH FLOW SENSITIVITIES FOR 2005
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($millions)
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Change of Cdn $0.25/mcf in the benchmark AECO natural gas price $11
Change of U.S. $1.00/barrel in the benchmark WTI oil price $ 2
Change of $0.01 in the Canadian/U.S. exchange rate $ 1
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2005 CAPITAL EXPENDITURES
Compton has budgeted for $390 million of capital expenditures in 2005, to be
funded through a combination of cash flow, equity, minor property sales and debt
as follows:
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($millions)
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Cash flow $230 - $240
Equity issue - net proceeds $86
Property sales $50 - $60
Debt $5 - $25
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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 quickly adjusted to reduce capital spending.
ADDITIONAL DISCLOSURES
CRITICAL ACCOUNTING ESTIMATES
Critical 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 Notes 1
and 2 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
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production levels. Such revisions could be upwards or downwards. Reserve
estimates have a material impact on depletion and depreciation, asset retirement
expenses and impairment costs which could possibly have a material impact on
consolidated net income.
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 2004, Compton incurred $83 million of depletion and depreciation. If the
proved reserves of the Company were to vary by 5%, the depletion and
depreciation expense would change by approximately $1 million and consolidated
net income after tax would change by approximately $780,000.
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, 2004 the ceiling amount calculated was
approximately $1.0 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
Compton is required to remove production equipment, batteries, pipelines, gas
plants and restore land at the end of oil and natural gas operations. The
Company estimates these costs in accordance with existing laws, contracts and
other policies. These obligations are initially
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measured at fair value, which is the discounted future value of the liability.
This fair value is capitalized as part of the cost of the related assets and
amortized over the useful life of the assets.
An annual increase to the liability is recorded to recognize the passage of time
and the impending settlement of the obligation. The liability is impacted by any
changes in the assumptions used in the asset retirement obligation ("ARO")
calculation. Adjustments to the estimate will be recorded as an accretion
expense on the consolidated statements of earnings.
In the future, the Company's depletion expense will be reduced since the
discounted value of the liability on the future consolidated financial
statements will be depleted, rather than the undiscounted value previously
depleted. The lower depletion expense will be offset by the addition of the
accretion expense.
An independent environmental consulting firm was hired to assist Management in
the estimation of asset removal costs. The ARO cost calculations were derived
from a combination of actual third party cost quotes, Alberta Energy and
Utilities Board cost models and typical industry experience and practices. The
deemed ARO liability for wells and facilities is the sum of the calculated
abandonment and reclamation liabilities adjusted for designated status as
active, inactive, abandoned or problem site. Information regarding environmental
remediation costs and other liability issues for site specific concerns were
derived from a review of historical audits and assessment reports for sites and
facilities. An inflation rate of 2.0% and a credit adjusted risk free interest
rate of 10.8% was used in Compton's fair value calculation.
Estimating future asset removal costs is difficult and requires Management to
make estimates and judgments because most of the removal obligations are many
years in the future and contracts and regulations often have vague descriptions
of what constitutes removal. Asset removal technologies and costs are constantly
changing, as well as regulatory, political, environmental, safety and public
relations considerations. As a result, it is not possible to provide a
reasonable analysis of the impact that changes in removal costs would have on
the asset retirement obligation. If the inflation rate assumed in the ARO
calculation changed by 1%, the ARO obligation would vary by $3 million.
Additionally, a 1% change in the credit adjusted risk free interest discount
rate would result in a $2 million change to the ARO liability.
CHANGES IN ACCOUNTING POLICY
The Canadian Institute of Chartered Accountants adopted several new accounting
standards that became effective in 2004. Compton chose to early adopt the Stock
Based Compensation, Asset Retirement Obligations and Oil & Gas Full Cost
Accounting standards in the preparation of its 2003 consolidated financial
statements. The only new standard affecting the preparation of the 2004
consolidated financial statements is Hedge Accounting.
HEDGE ACCOUNTING
In December 2001, the CICA modified Accounting Guideline 13, "Hedging
Relationships" ("AcG-13"). The Guideline establishes certain conditions where
hedge accounting may be applied, effective for fiscal years beginning on or
after July 1, 2003. Additionally, the CICA's Emerging Issues Committee ("EIC")
amended their guidance in EIC 128, "Accounting for Trading, Speculative or
Non-Trading Derivative Financial Instruments," to require that all derivative
instruments that do not qualify for hedge accounting or are not designated as
hedges, be recorded on the consolidated balance sheets with changes in fair
value recognized in earnings.
15
Compton adopted the modified Guideline effective January 1, 2004 and elected not
to designate any of its current risk management activities as accounting hedges
under AcG-13. The Company currently accounts for all derivatives using the
mark-to-market accounting method. The impact on the Company's consolidated
financial statements at January 1, 2004 was an increase in liabilities of $11
million and a deferred loss of $11 million, which will be recognized as the
contracts expire.
FINANCIAL CONDITIONS AND RISKS
Compton's operations are subject to risks normally associated with the oil and
natural gas industry. The Company is exposed to financial risks including
commodity price fluctuations and changing expenditure costs due to shifts in
market conditions. Commodity prices are driven by supply, demand and market
forces outside our influence. However, our product mix is diversified to
minimize exposure to any one commodity's price movements. Sales of oil and
natural gas are aimed at various markets to avoid undue exposure to any one
market. When appropriate, we ensure that parental guarantees or letters of
credit are in place to minimize the impact in the event of default.
Compton monitors and focuses its expenditures to reflect commodity prices and
production changes, as well as continuously scrutinizing market conditions and
opportunities. From time to time the Company will employ financial instruments
to manage exposure related to Canadian/U.S. dollar exchange rates and commodity
prices.
The Company has commodity and fixed-price contracts outstanding, as outlined
below.
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COMMODITY TYPE TERM VOLUME AVERAGE PRICE INDEX
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NATURAL GAS
Collars Nov. 2004 - March 2005 25,000 GJ/d Cdn.$7.15 - $11.01 AECO
Collars Apr. 2005 - Oct. 2005 15,000 GJ/d Cdn$5.92 - $8.45 AECO
CRUDE OIL
Collars Jan. 2005 - Dec. 2005 1,000 bbls/d U.S.$35.00 - $48.75 WTI
Collars Feb. 2005 - Dec. 2005 500 bbls/d U.S.$43.00 - $49.51 WTI
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The Company considers longer term contracts with suppliers where appropriate, to
mitigate shifts in costs resulting from changes in industry and market
conditions. Compton has no control over government intervention or taxation
levels on the industry.
In the future, it is likely that we will be required to raise additional capital
via debt and/or equity financings in order to fully realize our strategic goals
and business plans. Compton's ability to raise additional capital will depend
upon a number of factors, such as general economic and market conditions that
are beyond our control. If we are unable to obtain additional financing or to
obtain it on favorable terms, the Company might be required to forego attractive
business opportunities. Compton is committed to maintaining a strong balance
sheet, combined with a flexible capital expenditure program that can be adjusted
to capitalize on or reflect acquisition opportunities or a tightening of
liquidity sources.
RISK MANAGEMENT
From time to time, Compton enters into hedge transactions to manage fluctuations
in commodity prices and foreign currency. The Company does not participate in
derivative or other financial instruments for trading purposes and commodity
price contracts may not exceed 50% of non-
contracted production. Management considers an abundance of information from a
variety of sources before entering into a financial transaction. The Audit,
Finance and Risk Committee of the Board of Directors regularly reviews the
Company's hedging strategies and transactions.
INTEREST RATE RISK MANAGEMENT
Concurrent with the closing of the senior notes offering in May of 2002, the
Company negotiated 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 to take advantage of lower floating interest rates.
The terms of the swap correlates with the terms of the debt agreement and has
resulted in an effective interest rate of 7.24% (2003 - 7.85%). At December 31,
2004 there was an unrealized hedge loss of $4 million (2003 - $9 million), as
calculated on a mark-to-market basis by the issuer of the instrument.
FOREIGN CURRENCY EXCHANGE RATE 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 large extent natural gas prices
are based upon reference prices denominated in U.S. dollars, while the majority
of our expenses are denominated in Canadian dollars. When appropriate, Compton
enters into agreements to fix the Canadian/U.S. dollar exchange rate in order to
manage the risk. No foreign currency agreements were in place in 2004. In 2003,
a $2 million gain was realized and included in revenue as a result of foreign
currency contracts.
COMMODITY PRICE RISK MANAGEMENT
Compton enters into commodity price contracts to hedge anticipated sales of oil
and natural gas production to protect cash flows for our capital expenditure
programs. 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 income for the year
ended December 31, 2004 include losses of $7 million (2003 - $5 million loss;
2002 - $1 million gain) on these transactions.
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SELECTED QUARTERLY INFORMATION
The following tables set out selected quarterly financial information of the
Company for the last two fiscal years.
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THREE MONTHS ENDED YEAR ENDED
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MARCH 31, JUNE 30, SEPT. 30, DEC. 31, DEC. 31,
($000s, except where noted) 2004 2004 2004 2004 2004
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Average production (BOE/D) 25,717 26,295 27,268 28,204 26,876
Average pricing (2) ($/BOE) $ 38.04 $ 41.43 $ 40.78 $ 39.00 $ 39.82
Total revenue (1) $89,031 $99,140 $102,299 $101,189 $391,659
Cash flow $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
Net income $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
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(1) Restated to exclude transportation and realized hedging gains and losses.
(2) Restated to exclude realized hedge gains and losses.
In 2004, strong overall commodity prices and increasing production increased
total revenue.
Net income 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 income for the year was lower than in 2003 as the
prior year benefited from a $39 million after tax, unrealized foreign exchange
gain on the translation of the Company's U.S. denominated debt, compared to a
$14 million after tax gain in 2004. Net income in 2003 also included a $37
million future income tax recovery in the second quarter due statutory income
tax rate changes compared to an $8 million gain in the current year.
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THREE MONTHS ENDED YEAR ENDED
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MARCH 31, JUNE 30, SEPT. 30, DEC. 31, DEC. 31,
($000s, except where noted) 2003 2003 2003 (1) 2003 2003
- -----------------------------------------------------------------------------------------------------------
Average production (BOE/D) 25,853 25,659 24,219 26,484 25,552
Average pricing (3) ($/BOE) $ 42.25 $ 37.29 $ 35.07 $ 34.08 $ 37.16
Total revenue (2) $98,306 $87,063 $78,150 $83,047 $346,565
Cash flow $48,038 $39,610 $34,525 $32,635 $154,893
Per share: basic $ 0.41 $ 0.34 $ 0.29 $ 0.28 $ 1.33
diluted $ 0.39 $ 0.33 $ 0.28 $ 0.27 $ 1.27
Net income $31,817 $64,686 $10,498 $11,880 $118,880
Per share: basic $ 0.27 $ 0.56 $ 0.09 $ 0.10 $ 1.02
diluted $ 0.26 $ 0.53 $ 0.09 $ 0.10 $ 0.97
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(1) Restated for inclusion of Mazeppa Processing Partnership.
(2) Restated to exclude transportation and realized hedging gains and losses.
(3) Restated to exclude realized hedge gains and losses.
Production in the third quarter of 2003 was unusally low due to the shut-in of
the Mazeppa gas plant for turnaround in September 2003. Third quarter revenue
also declined as a result of the turnaround.
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An unrealized foreign exchange gain on the translation of the Company's U.S.
denominated debt in the first and second quarters of 2003 and a recovery of
future income taxes in the second quarter, due to a reduction in federal and
provincial income tax rates on income earned from resource activities,
significantly increased quarterly net income in the first half of the year.
FOURTH QUARTER 2004
Average fourth quarter 2004 production increased 3% from the third quarter of
2004. Production in December 2004 reached approximately 30,000 boe/d, before the
disposition of 600 boe/d of production at year end.
Total revenue in the fourth quarter decreased slightly due to lower realized
prices, despite higher production than in the third quarter. After the
elimination of non-operational items, net income in the fourth quarter was lower
than in the prior quarter due to lower realized prices, additional interest
expense and depreciation and depletion charges.
SELECTED ANNUAL INFORMATION
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Years ended December 31, ($000s) 2004 2003 2002
- ------------------------------------------------------------------------------------------------
Total revenue $ 391,659 $ 346,565 $226,597
Net income $ 63,633 $ 118,880 $ 18,312
Per share: basic $ 0.54 $ 1.02 $ 0.16
diluted $ 0.51 $ 0.97 $ 0.16
Total assets $1,330,611 $1,064,320 $823,859
Total long term financial liabilities $ 198,594 $ 213,246 $260,634
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Total revenue in 2004 was higher than in the two previous years due to a
combination of increased production and higher prices.
Net income in 2004 decreased from the prior year as 2003 was impacted by a $39
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. Net income in 2002 was lower due to
significantly lower realized prices and decreased production levels.
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. Capital expenditures of
$221 million in 2003 increased total assets by 29% from 2002.
The change in long term financial liabilities results from an unrealized gain
due to the translation of the Company's U.S. $165 million senior term notes. The
principal of the senior term notes remains fixed at U.S.$165 million while the
value of the notes shown on the consolidated balance sheets varies in response
to movement in the Canadian/U.S. exchange rate.
TRADING AND SHARE STATISTICS
As at March 15, 2005 there were 124,961,986 common shares outstanding, including
the 7.5 million common share issued on February 18, 2005 and 12,522,717 stock
options outstanding.
19
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2004 2003 2002
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Average daily trading volume (000S) 674,764 686,100 324,865
Share price ($/SHARE)
High $ 11.43 $ 6.35 $ 5.35
Low $ 5.89 $ 4.40 $ 3.20
Close $ 10.85 $ 6.00 $ 5.09
Market capitalization at December 31 ($000S) $1,273,282 $ 698,535 $ 591,819
Shares outstanding (000S) 117,354 116,423 116,271
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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.
20