EXHIBIT 99.3
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MANAGEMENT'S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's discussion and analysis ("MD&A") should be read in conjunction
with the audited consolidated financial statements for the year ended December
31, 2005 and the audited consolidated financial statements and MD&A for the
year ended December 31, 2004 and MD&A for the three quarters ended March 31,
2005, June 30, 2005 and September 30, 2005.
This MD&A is dated February 8, 2006.
Management uses cash flow, cash flow from operations and cash flow from
operations per unit derived from cash flow from operating activities (before
changes in non-cash working capital and expenditures on site reclamation and
restoration) to analyze operating performance and leverage. Cash flow as
presented does not have any standardized meaning prescribed by Canadian
generally accepted accounting principles, ("GAAP") and therefore it may not be
comparable with the calculation of similar measures for other entities. Cash
flow as presented is not intended to represent operating cash flow or
operating profits for the period nor should it be viewed as an alternative to
cash flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian GAAP.
The following table reconciles the cash flow from operating activities to cash
flow from operations which is used frequently in this MD&A:
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($ thousands) 2005 2004
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Cash flow from operating activities 616,711 446,418
Changes in non-cash working capital 17,919 (1,617)
Expenditures on site reclamation and restoration 4,881 3,232
Cash flow from operations 639,511 448,033
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Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as operating netbacks ("netbacks"), total capitalization and
finding, development and acquisition costs to analyze financial and operating
performance. These KPI's and benchmarks as presented do not have any
standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities.
This discussion and analysis contains forward-looking statements as to the
Trusts internal projections, expectations or beliefs relating to future events
or future performance within the meaning of the "safe harbour" provisions of
the United States Private Securities Litigation Reform Act of 1995 and the
Securities Act (Ontario). In some cases, forward-looking statements can be
identified by terminology such as "may", "will", "should", "expects",
"projects", "plans", "anticipates" and similar expressions. These statements
represent management's expectations or beliefs concerning, among other things,
future operating results and various components thereof or the economic
performance of ARC Energy Trust ("ARC" or "the Trust"). The projections,
estimates and beliefs contained in such forward-looking statements are based
on management's assumptions relating to the production performance of ARC's
oil and gas assets, the cost and competition for services throughout the oil
and gas industry in 2006 and the continuation of the current regulatory and
tax regime in Canada, and necessarily involve known and unknown risks and
uncertainties, including the business risks discussed in this MD&A, which may
cause actual performance and financial results in future periods to differ
materially from any projections of future performance or results expressed or
implied by such forward-looking statements. Accordingly, readers are cautioned
that events or circumstances could cause results to differ materially from
those predicted. The Trust does not undertake to update any forward looking
information in this document whether as to new information, future events or
otherwise.
-1-
HIGHLIGHTS
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(Cdn$ millions, except per unit and volume data) 2005 2004 % Change
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Cash flow from operations 639.5 448.0 43
Cash flow from operations per unit (1) 3.35 2.41 39
Net income 356.9 241.7 48
Distributions per unit (4) 1.99 1.80 11
Payout ratio per cent (2) 59 74 (20)
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Total daily production (boe/d) (3) 6,254 6,870 (1)
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(1) Per unit amounts are based on weighted average units plus units issuable
for exhangeable shares at year end.
(2) Based on cash distributions divided by cash flow from operations.
(3) Reported production amount is based on company interest before royalty
burdens. Where applicable in this MD&A natural gas has been converted to
barrels of oil equivalent ("boe") based on 6 mcf:1 bbl. The boe rate is
based on an energy equivalent conversion method primarily applicable at
the burner tip and does not represent a value equivalent at the well
head. Use of boe in isolation may be misleading.
(4) Based on number of trust units outstanding at each cash distribution
date.
CASH FLOW FROM OPERATIONS
Cash flow from operations increased by 43 per cent in 2005 to $640 million
from $448 million in 2004. This increase was primarily the result of higher
commodity prices. The cash flow from operations per unit increased 39 per cent
to $3.35 per unit from $2.41 per unit in 2004. The 2005 cash flow from
operations included a cash loss of $87.6 million on commodity and foreign
currency contracts while 2004 cash flow included a loss of $86.9 million on
commodity and foreign currency contracts.
The following table summarizes the variances in cash flow from operations and
in cash flow from operations per unit between 2004 and 2005. It shows the
variance is due mainly to increased commodity pricing, with some of the price
increase being paid out in increased royalties and a small decrease in revenue
because of the one per cent decrease in the volumes produced.
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($ millions) ($ per trust unit) (% variance)
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2004 CASH FLOW FROM OPERATIONS $ 448.0 $ 2.41
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Volume variance (12.2) (0.07) (3)
Price variance 275.6 1.48 62
Cash losses on commodity and foreign currency contracts (1) (0.6) -- --
Royalties (58.3) (0.31) (13)
Expenses:
Transportation 0.5 -- --
Operating (2.5) (0.01) (1)
Cash G&A (6.0) (0.03) (1)
Interest (3.6) (0.02) (1)
Taxes (1.0) (0.01) --
Realized foreign exchange gain (2.2) (0.01) --
Other 1.8 0.01 --
Weighted average trust units -- (0.09) (4)
2005 CASH FLOW FROM OPERATIONS $ 639.5 $ 3.35 39
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(1) Represents cash losses on commodity and foreign currency contracts
including cash settlements on termination of commodity and foreign
currency contracts.
-2-
PRODUCTION
Production volumes averaged 56,254 boe per day in 2005 compared to 56,870 boe
per day in 2004. Production from the Redwater and North Pembina Cardium Unit
("NPCU") acquisitions were included starting on December 16, 2005 (these areas
contributed 5,460 boe per day for the last 16 days of December 2005). The
Trust exited 2005 with average daily production for the month of December in
excess of 61,000 boe per day.
The Trust expects 2006 production to average 61,000 boe per day, an eight per
cent increase over 2005.
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PRODUCTION 2005 2004 % Change
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Crude oil (bbl/d) 23,282 22,961 1
Natural gas (mcf/d) 173,800 178,309 (3)
NGL (bbl/d) 4,005 4,191 (4)
Total production (boe/d) (1) 56,254 56,870 (1)
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% Natural gas production 51 52
% Crude oil and liquids production 49 48
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(1) Reported production for a period may include minor adjustments from
previous production periods.
The following table summarizes the Trust's production by core area:
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2005 2004
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TOTAL OIL GAS (2) NGL Total Oil Gas NGL
CORE AREA (1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
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Central AB 8,041 1,364 30.2 1,641 9,295 2,003 32.6 1,856
Northern AB & BC 18,286 6,026 65.3 1,381 19,026 5,733 71.1 1,441
Pembina & Redwater 7,953 4,166 17.7 832 7,433 3,742 17.5 772
S.E. AB & S.W. Sask. 11,298 1,499 58.7 15 10,871 1,658 55.2 14
S.E. Sask. 10,676 10,227 1.9 136 10,245 9,825 1.9 108
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TOTAL 56,254 23,282 173.8 4,005 56,870 22,961 178.3 4,191
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(1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is
Saskatchewan, S.E. is southeast, S.W. is southwest. (2) Rounding of the
gas conversion at 6:1 mmcf can result in totals not summing exactly.
COMMODITY PRICES
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BENCHMARK PRICES 2005 2004 % Change
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AECO gas ($/mcf) (1) 8.45 6.79 24
WTI oil (US$/bbl) (2) 56.61 41.43 37
US$/Cdn$ foreign exchange rate 0.83 0.77 8
WTI oil (Cdn$/bbl) 68.52 53.81 27
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(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
Oil and gas prices reached historic highs in 2005. The strength of the
Canadian dollar served to partially offset the impact of higher US denominated
oil prices. The Trust's oil production consists predominantly of light and
medium crude oil while heavy oil accounts for less than five per cent of the
Trust's liquids production. Overall the price of WTI oil in Canadian dollars
increased by 27 per cent over the prior year to $68.52 versus $53.81 in 2004.
-3-
Alberta AECO Hub natural gas prices, which are commonly used as an industry
reference, averaged $8.45 per mcf in 2005 compared to $6.79 per mcf in 2004.
ARC's realized gas price, before hedging, increased by 32 per cent to $8.96
per mcf compared to $6.78 per mcf in 2004. ARC's realized gas price is based
on prices received at the various markets in which the Trust sells its natural
gas. ARC's natural gas sales portfolio consists of gas sales priced at the
AECO monthly index, the AECO daily spot market, eastern and mid-west United
States markets and a portion to aggregators.
Prior to hedging activities, ARC realized $56.54 per boe in 2005, a 31 per
cent increase over the $43.13 per boe received prior to hedging in 2004.
The following is a summary of realized prices :
ARC REALIZED PRICES
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2005 2004 % Change
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Oil ($/bbl) 61.11 47.03 30
Natural gas ($/mcf) 8.96 6.78 32
NGL ($/bbl) 49.92 39.04 28
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Total commodity revenue before hedging ($/boe) 56.54 43.13 31
Other revenue ($/boe) 0.21 0.19 11
TOTAL REVENUE BEFORE HEDGING ($/boe) 56.75 43.32 31
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REVENUE
Revenue increased to $1.2 billion in 2005, an increase of 29 per cent compared
to 2004 revenue of $902 million. Significantly higher commodity prices caused
this higher revenue.
A breakdown of revenue is as follows:
REVENUE
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($ thousands) 2005 2004 % Change
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Oil revenue 519,272 395,203 31
Natural gas revenue 568,710 442,537 29
NGL revenue 72,973 59,886 22
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Total commodity revenue 1,160,955 897,626 29
Other revenue 4,242 4,156 2
TOTAL REVENUE 1,165,197 901,782 29
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RISK MANAGEMENT
The Trust's risk management activities are conducted by an internal Risk
Management Committee, based upon guidelines approved by the Board. The Risk
Management Committee has the following mandate:
o protect unitholder return on investment;
o provide for minimum monthly cash distributions to unitholders;
o employ a portfolio approach to risk management by entering into a number
of small positions that build upon each other;
o participate in commodity price upturns to the greatest extent possible
while limiting exposure to price downturns; and,
o ensure profitability of specific oil and gas properties that are more
sensitive to changes in market conditions.
The Trust realized cash hedging losses of $87.6 million for the year
attributed primarily to capped contracts that expired on December 31, 2005. At
the date of this MD&A the Trust had upside participation for 2006 on all
produced volumes with the exception of those noted below, with downside price
protection on 39 per cent of liquids production and 14 per cent of natural gas
production (26 per cent of produced boes).
-4-
The Trust continues to execute a risk management strategy focused on put and
put spread structures to manage commodity prices and continues to use fixed
rate swaps to manage foreign exchange and interest rate exposures. The
purchase of a put involves paying a premium to limit the exposure to downturns
in commodity prices while participating in commodity price appreciation. At
year end the Trust had bought puts with an average floor on oil production of
US$52.68 per bbl and Cdn$8.16 per GJ on natural gas. The Trust also entered
into sold put transactions that offset the cost of the bought put premiums.
The $12.4 million cost of the put premiums has been incurred to protect a
portion of 2006 revenue.
In addition to the above contracts, the Trust entered into long-term risk
management structures to lock in returns on production acquired through the
Redwater and NPCU acquisitions announced in December 2005. ARC has protected
5,000 barrels per day through 2009 with a three-way collar by partially
financing the purchase of a US$55 floor with a sold US$40 put and US$90 call.
ARC felt it prudent to sell the out-of-the-money put and call in order to
reduce the cost of the US$55 floor and minimize its long-term premium
commitments. As a result, ARC has US$55 price protection (down to US$40) on
the acquired volumes costing an average of $1.9 million per year through 2009.
If oil trades above US$90 in any one month, ARC will be limited to US$90 for
that month, if WTI falls below US$40, ARC receives market price plus US$15
under the three-way collar. For a complete summary of the Trust's oil and
natural gas hedges, please refer to "Hedging Program" under the "Investor
Relations" section of the Trust's website at www.arcenergytrust.com.
The Trust considers its risk management contracts to be effective economic
hedges as they meet the objectives of the Trust's risk management mandate. In
order to mitigate credit risk, the Trust executes commodity and foreign
currency hedging risk management with financially sound, credit worthy
counterparties. All contracts require approval of the Trust's Risk Management
Committee prior to execution. Deferred premiums payable will be recorded as a
realized cash hedging loss when payment is made in a future period. These
premiums may be partially offset if ARC sells any short-term options. The
Trust's oil contracts are based on the WTI index and the majority of the
Trust's natural gas contracts are based on the AECO monthly index.
GAIN OR LOSS ON COMMODITY AND FOREIGN CURRENCY CONTRACTS
Gain or loss on commodity and foreign currency contracts comprise realized and
unrealized gains or losses on commodity and foreign currency contracts that do
not meet the accounting definition of the requirements of an effective hedge,
even though the Trust considers all commodity and foreign currency contracts
to be effective economic hedges. Accordingly, gains and losses on such
contracts are shown as a separate expense in the statement of income.
The Trust recorded a realized loss on commodity and foreign currency contracts
of $87.6 million in 2005, which is virtually the same amount as realized in
2004.
The following is a summary of the gain (loss) on commodity and foreign
currency contracts for 2005:
COMMODITY AND FOREIGN CURRENCY CONTRACTS
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CRUDE OIL & NATURAL FOREIGN 2005 2004
($ thousands) LIQUIDS GAS CURRENCY TOTAL Total
- ---------------------------------------------------------------------------------------------------
Realized cash (loss) gain
on contracts (1) (75,816) (12,491) 749 (87,558) (86,909)
Non-cash gain on contracts -- -- -- -- 4,883
Non-cash amortization of
opening deferred hedge loss -- -- -- -- (14,575)
Unrealized (loss) gain on
contracts, change in
fair value (2) 16,465 (17,531) 1,066 -- 10,533
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TOTAL GAIN (LOSS) ON
COMMODITY AND FOREIGN
CURRENCY CONTRACTS (59,351) (30,022) 1,815 (87,558) (86,068)
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(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
-5-
OPERATING NETBACKS
The Trust's operating netback, prior to realized hedging losses, increased 37
per cent to $37.66 per boe in 2005 compared to $27.39 per boe in 2004. The
increase in netbacks in 2005 is due to higher commodity prices.
The netback was reduced by realized losses on commodity and foreign currency
contracts of $4.26 per boe for 2005, very similar to losses of $3.94 per boe
in 2004.
The components of operating netbacks are shown below:
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2005 2004
Oil Gas NGL TOTAL Total
NETBACK ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
- ---------------------------------------------------------------------------------------
Weighted average sales price 61.11 8.96 49.91 56.54 43.13
Other revenue -- -- -- 0.21 0.19
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Total revenue 61.11 8.96 49.91 56.75 43.32
Royalties (11.58) (1.85) (13.18) (11.46) (8.51)
Transportation (0.13) (0.21) -- (0.70) (0.71)
Operating costs (1) (8.62) (0.98) (4.69) (6.93) (6.71)
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Netback prior to hedging 40.78 5.92 32.04 37.66 27.39
Realized loss on commodity and
foreign currency contracts (8.83) (0.20) -- (4.26) (3.94)
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Netback after hedging 31.95 5.72 32.04 33.40 23.45
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(1) Operating expenses are composed of direct costs incurred to operate oil
and gas wells. A number of assumptions have been made in allocating these
costs between oil, natural gas and natural gas liquids production.
Royalties increased to $11.46 per boe in 2005 compared to $8.51 per boe in
2004, up 35 per cent as a result of higher commodity prices. Royalties are
calculated and paid based on commodity revenue net of associated
transportation costs and before any commodity hedging gains or losses.
Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs remained unchanged at approximately 20 per cent.
Operating costs, net of processing income, remained relatively consistent at
$142.2 million in 2005 compared to $139.7 million in 2004. Operating costs per
boe increased three per cent to $6.93 per boe in 2005 compared to $6.71 per
boe in 2004. The higher costs of services throughout the industry,
particularly for service rigs, trucking costs and mechanical services, has
caused the increase in operating costs.
In 2006 it is expected that base operating costs (before Redwater and NPCU)
will increase over 10 per cent to $7.70 per boe. With the addition of the
higher cost Redwater and NPCU properties it is estimated that average
operating costs will increase to $8.65 per boe in 2006.
GENERAL AND ADMINISTRATIVE EXPENSES AND TRUST UNIT INCENTIVE COMPENSATION
Cash general and administrative expenses ("G&A"), net of overhead recoveries
on operated properties, increased to $27.4 million ($1.34 per boe) in 2005
from $21.4 million ($1.03 per boe) in 2004. Increases in cash G&A expenses in
total and per boe were the result of the increasing costs to manage the
business associated with increased staff levels and increased compensation.
Due to unprecedented levels of activity for ARC and for the industry as a
whole in 2005, the costs associated with hiring, compensating and retaining
employees and consultants has risen. It is essential for the Trust to maintain
competitive compensation levels to ensure that we continue to attract and
retain the most qualified individuals.
-6-
The following is a breakdown of G&A and trust unit incentive compensation
expense:
G&A AND TRUST UNIT INCENTIVE COMPENSATION EXPENSE
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($ thousands except per boe) 2005 2004 % Change
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G&A expenses 35,044 30,733 14
Whole Unit Plan compensation expense (1) 1,062 -- 100
Operating recoveries (8,659) (9,307) (7)
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Cash G&A expenses 27,447 21,426 28
Accrued compensation - Rights Plan 6,525 5,171 26
Accrued compensation - Whole Unit Plan 8,774 2,915 201
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Total G&A and trust unit incentive compensation expense 42,746 29,512 45
Cash G&A expenses per boe 1.34 1.03 30
Total G&A and trust unit incentive
compensation expense per boe 2.08 1.42 46
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(1) Plan started in 2004 with the first cash payment made in April 2005.
A non-cash trust unit incentive compensation expense ("non-cash compensation
expense") of $15.3 million ($0.74 per boe) was recorded in 2005 compared to
$8.1 million ($0.39 per boe) in 2004. This non-cash amount relates to
estimated costs of the Trust Unit Incentive Rights Plan ("Rights Plan") and
the Whole Trust Unit Incentive Plan to December 31, 2005 and reflects the
strong market performance of ARC's units during the year.
RIGHTS PLAN
The Rights Plan provided employees, officers and independent directors the
right to purchase units at a specified price. In general, the rights had a
five year term and vested equally over three years. The exercise price of the
rights is adjusted downwards from time to time by the amount that
distributions to unitholders, in any calendar quarter exceeds 2.5 per cent of
the Trust's net book value of property, plant and equipment. The rights plan
was replaced by a Whole Unit Plan during 2004 after which no further rights
under the rights plan were issued. The number of rights outstanding declined
by 1.7 million in the year from exercises or cancellations, to end the year at
1.3 million outstanding.
For the year ended December 31, 2005, the compensation expense for the rights
plan based on the fair value calculation resulted in an expense of $6.5
million compared to $5.2 million in 2004.
WHOLE TRUST UNIT INCENTIVE PLAN ("WHOLE UNIT PLAN")
In March 2004, the Board of Directors approved a new Whole Unit Plan to
replace the Rights Plan for new awards granted subsequent to the first quarter
of 2004. The new Whole Unit Plan results in employees, officers and directors
(the "plan participants") receiving cash compensation in relation to the value
of a specified number of underlying units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
Upon vesting, the plan participant is entitled to receive a cash payment based
on the fair value of the underlying trust units plus accrued distributions.
The cash compensation issued upon vesting of the PTUs is dependent upon the
performance of the Trust compared to its peers. The PTU grant is adjusted by a
performance multiplier. The performance multiplier is based on the percentile
rank of the Trust's total unitholder return, which is the sum of the increase
in market price of the units over the period plus the amount of distributions
over the period, compared to its peers. The performance multiplier can range
from zero to two.
The value associated with the RTUs and PTUs is expensed in the statement of
income over the vesting period with the expense amount being determined by the
unit price, the number of PTUs to be issued on vesting, and distributions.
Therefore, the expense recorded in the statement of income fluctuates over
time.
-7-
The following table shows the changes during the year of RTUs and PTUs
outstanding:
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(in thousands of units) number of RTUs number of PTUs
- --------------------------------------------------------------------------------
Balance, beginning of year 225 128
Vested (79) --
Granted 367 305
Forfeited (34) (42)
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Balance, end of year 479 391
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Under the Whole Unit Plan $13.6 million was paid or accrued during the year
versus $2.9 million in 2004. The large increase in the accrued value of the
RTUs and PTUs outstanding is attributed to the considerable increase in the
Trust's unit value in the market, and the increase in the performance
multiplier on the PTUs to two reflecting ARC's top quartile returns compared
to other midsized oil and gas producers.
The Trust expects 2006 G&A costs, excluding non-cash G&A associated with the
Trust's Rights Plan and Whole Unit Plan, to be approximately $1.70 per boe. In
addition, the Trust expects 2006 non-cash G&A of approximately $0.65 per boe
for the non-cash trust unit incentive compensation expense associated with the
Rights Plan and Whole Unit Plan. The increasing G&A costs in 2006 are the
result of higher compensation levels associated with hiring and retaining
qualified employees and consultants in a competitive environment.
INTEREST EXPENSE
Interest expense increased to $16.9 million in 2005 from $13.3 million in
2004. The increase is attributed to increased interest rates and to a higher
average debt balance in 2005 compared to 2004 as a result of acquisitions
funded by debt. Also during the year the Trust paid out an 8.05 per cent,
US$21 million note and refinanced it at a lower interest rate. The amount paid
to settle the note early was Cdn$1.3 million and was included as interest
expense.
The following is a summary of the debt balance and interest expense:
INTEREST EXPENSE
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($ thousands) 2005 2004 % Change
- --------------------------------------------------------------------------------
Year end debt balance (1) 526,636 220,549 139
Fixed rate debt 268,156 220,259
Floating rate debt 258,480 290
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Interest expense before interest rate swaps (2) 17,420 14,675 19
Gain on interest rate hedge (474) (1,355)
Net interest expense 16,946 13,320 27
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(1) Includes both long-term and current portions of debt.
(2) The interest rate swap was designated as an effective hedge for
accounting purposes whereby actual realized gains and losses are netted
against interest expense.
FOREIGN EXCHANGE GAINS AND LOSSES
The Trust recorded a gain of $6.4 million ($0.31 per boe) on foreign exchange
transactions compared to a gain of $20.7 million ($1.00 per boe) in 2004.
These amounts include both realized and unrealized foreign exchange gains and
losses. Unrealized foreign exchange gains and losses are due to revaluation of
US denominated debt balances. The volatility of the Canadian dollar during the
reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow as it is a non-cash amount. Realized foreign
exchange gains or losses arise from US denominated transactions such as
interest payments, debt repayments and hedging settlements.
-8-
TAXES
Capital taxes paid or payable by ARC, based on debt and equity levels at the
end of the year, amounted to $3.9 million in 2005 compared to $2.8 million in
2004. The increase in 2005 capital taxes was attributed to the higher taxable
capital base as a result of asset acquisitions, partially offset by a decrease
in the capital tax rate, as well as a $0.9 million reassessment on prior years
tax return filings by Star Oil & Gas Ltd. ("Star"), which ARC purchased in
2003.
Corporate acquisitions completed in 2005 resulted in the Trust recording a
future income tax liability of $213.8 million due to the difference between
the tax basis and the fair value assigned to the acquired assets. The amount
of tax pools versus asset value is one of the parameters that impacts the
Trust's acquisition bid levels.
In the Trust's structure, payments are made between ARC Resources Ltd.
("ARL"), the operating subsidiary of the Trust, and the Trust, transferring
both income and future tax liability to the unitholders. At the current time,
ARC does not anticipate any cash taxes will be paid by ARL.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION
The depletion, depreciation and accretion ("DD&A") rate increased to $12.88
per boe in 2005 from $11.51 per boe in 2004. The higher DD&A rate is due to
the Redwater and NPCU property acquisition in the fourth quarter of 2005 for
which the Trust recorded a higher proportionate cost per barrel of proved
reserves of the acquired properties compared to the existing ARC properties.
In addition, the higher asset retirement obligation recorded in 2005 has
resulted in higher accretion expense in 2005.
A breakdown of the DD&A rate is a follows:
DD&A RATE
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($ thousands except per boe amounts) 2005 2004 % Change
- ------------------------------------------------------------------------------
Depletion of oil & gas assets (1) 259,308 235,094 10
Accretion of asset retirement obligation (2) 5,207 4,580 14
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Total DD&A 264,515 239,674 10
DD&A rate per boe 12.88 11.51 12
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(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
("PP&E") balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
The costs subject to depletion included $61.9 million relating to the
capitalized portion of the asset retirement obligation as at December 31, 2005
($42.3 million as at December 31, 2004), net of accumulated depletion.
GOODWILL
The goodwill balance of $157.6 million arose as a result of the acquisition of
Star in 2003. The goodwill balance was determined based on the excess of total
consideration paid plus the future income tax liability less the fair value of
the assets for accounting purposes acquired in the transaction.
Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such an
impairment exists, it would be charged to income in the period in which the
impairment occurs. The Trust has determined that there was no goodwill
impairment as of December 31, 2005.
CAPITAL EXPENDITURES AND NET ACQUISITIONS
Total capital expenditures, excluding acquisitions and dispositions, totaled
$268.8 million in 2005 compared to $193.8 million in 2004. This amount was
incurred on drilling and completions, geological, geophysical and facilities
expenditures, as ARC continues to develop its asset base. The significant
increase in 2005 capital expenditures is due to the costs of the capital
development program needed to replace production in the year.
During the year, the Trust drilled 250 gross wells (220 net wells) on operated
properties; consisting of 68 gross oil wells and 180 gross natural gas wells
most of which were shallow gas wells, and two dry holes for a total success
rate of 99 per cent in 2005. In addition, the Trust participated in 402 gross
wells drilled by other operators.
In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $91.3 million in 2005. Major property
acquisitions were in the following areas: Berrymoor and Buck Creek in Alberta
and Weirhill and Steelman in Saskatchewan.
-9-
The Trust also completed a number of corporate acquisitions including Romulus
Exploration Inc. in June 2005 for total consideration of $42 million and
companies holding the Redwater and NPCU properties in December 2005 for total
consideration of $463 million.
Capital expenditures on development activities and acquisitions resulted in an
increase in proved plus probable oil and gas reserves from 244 mmboe at year
end 2004 to 287 mmboe at year end 2005.
Approximately 95 per cent of the $269 million capital program was financed
from cash flow from operations in 2005 versus 57 per cent in 2004. Property
and corporate acquisitions were financed through a combination of debt and
equity.
A breakdown of capital expenditures and net acquisitions is shown below:
CAPITAL EXPENDITURES
- -----------------------------------------------------------------------------------------------------------
($ thousands) 2005 2004 % Change
- -----------------------------------------------------------------------------------------------------------
Geological and geophysical 9,219 5,388 71
Drilling and completions 200,873 144,487 39
Plant and facilities 55,032 41,089 34
Other capital 3,710 2,820 32
Total capital expenditures 268,834 193,784 39
- -----------------------------------------------------------------------------------------------------------
Producing property acquisitions (1) 111,324 (529)
Producing property dispositions (1) (20,038) (57,691)
Corporate acquisitions (2) 504,996 72,009
Total capital expenditures and net acquisitions 865,116 207,573 318
- -----------------------------------------------------------------------------------------------------------
Total capital expenditures and net acquisitions financed with cash flow 256,104 110,846
Total capital expenditures and net acquisitions financed with debt 609,012 96,727
- -----------------------------------------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
(2) Represents total consideration for the transactions, including fees but
is prior to the related future income tax liability, asset retirement
obligation and working capital assumed on acquisition.
ARC expects to undertake significant development activities again in 2006
resulting in a $340 million capital budget. New activities include spending
$25 million on a commercial scale Natural Gas from Coal ("NGC") project and
incurring a $17 million increase in capital allocated to moderate risk
exploration.
ASSET RETIREMENT OBLIGATION AND RECLAMATION FUND
At December 31, 2005, the Trust has recorded an Asset Retirement Obligation
("ARO") of $165.1 million ($73 million at December 31, 2004) for future
abandonment and reclamation of the Trust's properties. The ARO increased by
$76.2 million during 2005 as a result of additional liabilities associated
with the acquisitions of Redwater and NPCU, and the wells drilled in 2005.
Also the ARO increased because the inflation factor used to calculate the
future retirement obligation was increased from 1.5 per cent to two per cent
in 2005. The ARO further increased by $5.2 million for accretion expense in
2005 ($4.6 million in 2004) and was reduced by $4.9 million ($3.2 million in
2004) for actual abandonment expenditures incurred in 2005. The Trust did not
record a gain or loss on actual abandonment expenditures incurred as the costs
closely approximated the liability value included in the ARO.
ARC contributed $6 million cash to its reclamation fund in 2005 ($6 million in
2004) and earned interest of $0.8 million ($1.2 million in 2004) on the fund
balance. The fund balance was reduced by $4.6 million for cash-funded
abandonment expenditures in 2005 ($3.1 million in 2004). This fund, invested
in money market instruments, is established to provide for future abandonment
and reclamation liabilities. Future contributions are currently set at
approximately $6 million per year over 20 years in order to provide for the
total estimated future abandonment and reclamation costs that are to be
incurred over the next 61 years. In addition, as a result of the Redwater/NPCU
acquisition the Trust has committed to additional yearly contributions
starting at $6.1 million per year (resulting in a total 2006 contribution of
$12.1 million). Currently, the fund balance stands at $23.5 million.
-10-
CAPITAL STRUCTURE
A breakdown of the Trust's capital structure is as follows:
CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY
- -----------------------------------------------------------------------------------------------
($ thousands except per unit and per cent amounts) 2005 2004
- -----------------------------------------------------------------------------------------------
Revolving credit facilities 258,480 290
Senior secured notes 268,156 220,259
Working capital deficit excluding short-term debt (1) 51,450 44,293
- -----------------------------------------------------------------------------------------------
Net debt obligations 578,086 264,842
Units outstanding and issuable for exchangeable shares (thousands) 202,039 188,804
Market price per unit at end of year 26.49 17.90
Market value of units and exchangeable shares 5,352,013 3,379,592
Total capitalization (2) 5,930,099 3,644,434
- -----------------------------------------------------------------------------------------------
Net debt as a percentage of total capitalization 9.7% 7.3%
Net debt obligations 578,086 264,842
Cash flow from operations 639,511 448,033
Net debt to cash flow 0.9 0.6
- -----------------------------------------------------------------------------------------------
(1) The working capital deficit excludes the balances for commodity and
foreign currency contracts.
(2) Total capitalization as presented does not have any standardized meaning
prescribed by Canadian GAAP and therefore it may not be comparable with
the calculation of similar measures for other entities. Total
capitalization is not intended to represent the total funds from equity
and debt received by the Trust.
On December 15, 2005 the Trust repaid the remaining US$21 million outstanding
on its 8.05 per cent senior secured notes originally issued in November 2000
pursuant to an Uncommitted Master Shelf Agreement. The Trust paid US$1.1
million in order to retire this note based upon the discounted value of
interest payable at the 8.05 per cent rate and current market interest rates.
Concurrent with the repayment, US$75 million of senior secured notes were
issued under an Amended Uncommitted Master Shelf Agreement. This note pays a
quarterly coupon of 5.42 per cent per annum and requires equal principal
payments of US$9,375,000 over an eight year period commencing in 2010.
In conjunction with the December acquisition of Redwater and the NPCU, the
Trust increased its syndicated credit facility to $700 million and its working
capital facility to $25 million resulting in a total borrowing base of $950
million. The increase in the borrowing base did not impact any key terms in
the credit facility such as security or covenants. The next annual credit
review will occur during the first quarter of 2006 at which time the Trust
will reduce its available credit facilities to reduce fees on credit
facilities it does not expect to utilize in the near future.
The Trust intends to finance its $340 million 2006 capital program with cash
flow and the proceeds of the distribution reinvestment program with any
remainder being financed with debt.
-11-
UNITHOLDERS' EQUITY
At December 31, 2005, there were 199.1 million trust units issued and 2.9
million units issuable for exchangeable shares, a seven per cent increase from
the 185.8 million units issued and three million units issuable for
exchangeable shares at December 31, 2004.
The increase in the number of units outstanding is attributable to the
following:
- ----------------------------------------------------------------------------------------------------------
Average Price Proceeds # of Units
(per unit) ($ millions) (millions)
- ----------------------------------------------------------------------------------------------------------
Units Issued at December 31, 2004 -- -- 185.8
December 2005 equity offering $ 26.65 239.9 9.0
Units issued from treasury pursuant to DRIP program $ 19.92 48.8 2.5
Units issued on exercise of employee rights $ 16.03 24.1 1.5
Units issued pursuant to exchange of ARL exchangeable shares $ 11.04 4.0 0.3
- ----------------------------------------------------------------------------------------------------------
UNITS ISSUED AT DECEMBER 31, 2005 199.1
- ----------------------------------------------------------------------------------------------------------
The Trust issued nine million units at $26.65 in December 2005 for proceeds of
$239.9 million less underwriter's fees of $12 million for net proceeds of
$227.9 million. Proceeds from the offering were used to partially repay debt
associated with the Redwater and NPCU acquisitions.
The Trust made its final issuance of rights under the Rights Plan during 2004.
There will be no future issuances of rights as the rights plan was replaced
with a new Whole Unit Plan in 2004. The existing rights plan will be in place
until the remaining 1.3 million rights outstanding as of December 31, 2005 are
exercised or cancelled. These rights have an adjusted exercise price of $10.22
and have an average remaining contractual life of 3.3 years and expire at
various dates to March 22, 2009. Of the rights outstanding at December 31,
2005, a total of 0.6 million were exercisable at that time.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees
may elect to have units purchased for them on the market with the cash
received upon vesting.
CASH DISTRIBUTIONS
ARC declared cash distributions of $377 million ($1.99 per unit), representing
59 per cent of 2005 cash flow from operations compared to cash distributions
of $330 million ($1.80 per unit), representing 74 per cent of cash flow from
operations in 2004. The remaining 41 per cent of 2005 cash flow ($263 million)
was used to fund 95 per cent of ARC's 2005 capital expenditures and make
contributions, including interest, to the reclamation fund ($6.8 million). The
actual amount of cash flow withheld to fund the Trust's capital expenditure
program is dependent on the commodity price environment and is at the
discretion of the Board of Directors.
Cash flow and cash distributions in total and per unit were as follows:
CASH FLOW AND DISTRIBUTIONS ($ millions) ($ per unit)
- --------------------------------------------------------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
- --------------------------------------------------------------------------------------------------------
Cash flow from operations 639.5 448.0 43 3.35 2.41 39
Reclamation fund contributions (1) (6.8) (7.2) (6) (0.04) (0.04) --
Capital expenditures funded with cash flow (256.1) (110.8) 131 (1.34) (0.60) 123
Other (2) -- -- -- 0.02 0.03 (33)
- --------------------------------------------------------------------------------------------------------
Cash distributions 376.6 330.0 14 1.99 1.80 11
- --------------------------------------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balance that is
retained in the reclamation fund.
(2) Other represents the difference due to cash distributions paid being
based on actual units at each distribution date whereas per unit cash
flow, reclamation fund contributions and capital expenditures funded with
cash flow are based on weighted average trust units in the year plus
units issuable for exchangeable shares at year end.
-12-
Monthly cash distributions for the first quarter of 2006 have been set at
$0.20 per unit subject to monthly review based on commodity price
fluctuations. Revisions, if any, to the monthly distribution are normally
announced on a quarterly basis in the context of prevailing and anticipated
commodity prices at that time.
HISTORICAL CASH DISTRIBUTIONS BY CALENDAR YEAR
The following table presents cash distributions paid in each calendar period.
- -------------------------------------------------------------------------------------------------
Taxable Return of
Calendar Year Distributions (1) Portion Capital
- -------------------------------------------------------------------------------------------------
2006 YTD (2) 0.40 0.39 (2) 0.01 (2)
2005 1.94 1.90 (3) 0.04 (3)
2004 1.80 1.69 0.11
2003 1.78 1.51 0.27
2002 1.58 1.07 0.51
2001 2.41 1.64 0.77
2000 1.86 0.84 1.02
1999 1.25 0.26 0.99
1998 1.20 0.12 1.08
1997 1.40 0.31 1.09
1996 0.81 -- 0.81
CUMULATIVE $ 16.43 $ 9.73 $ 6.70
- -------------------------------------------------------------------------------------------------
(1) Based on cash distributions paid in the calendar year.
(2) Based on cash distributions paid in 2006 up to and including February 15,
2006 and estimated taxable portion of 2006 distributions of 98 per cent.
(3) Based on taxable portion of 2005 distributions of 98 per cent.
2005 MONTHLY CASH DISTRIBUTIONS
Actual cash distributions paid along with relevant payment dates are as
follows:
- -----------------------------------------------------------------------------------------------------------
Distribution Total Taxable Return of
Ex-Distribution Date Record Date Payment Date Distribution Portion Capital
- -----------------------------------------------------------------------------------------------------------
December 29, 2004 December 31, 2004 January 17, 2005 0.15 0.1470 0.0030
January 27, 2005 January 31, 2005 February 15, 2005 0.15 0.1470 0.0030
February 24, 2005 February 28, 2005 March 15, 2005 0.15 0.1470 0.0030
March 29, 2005 March 31, 2005 April 15, 2005 0.15 0.1470 0.0030
April 27, 2005 April 30, 2005 May 16, 2005 0.15 0.1470 0.0030
May 27, 2005 May 31, 2005 June 15, 2005 0.15 0.1470 0.0030
June 28, 2005 June 30, 2005 July 15, 2005 0.15 0.1470 0.0030
July 27, 2005 July 31, 2005 August 15, 2005 0.15 0.1470 0.0030
August 28, 2005 August 31, 2005 September 15, 2005 0.17 0.1666 0.0034
September 28, 2005 September 30, 2005 October 17, 2005 0.17 0.1666 0.0034
October 27, 2005 October 31, 2005 November 15, 2005 0.20 0.1960 0.0040
November 28, 2005 November 30, 2005 December 15, 2005 0.20 0.1960 0.0040
TOTAL 2005 1.94 1.9012 0.0388
- -----------------------------------------------------------------------------------------------------------
TAXATION OF CASH DISTRIBUTIONS
Cash distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces
the cost basis of the units held. For a more detailed breakdown, please visit
our website at www.arcenergytrust.com.
-13-
For 2005, cash distributions paid in the calendar year will be 98 per cent
return on capital (taxable) and two per cent return of capital (tax deferred).
The increase in the taxable portion of distributions to 98 per cent is the
result of increasing commodity prices and in turn increasing cash flow of the
Trust.
The exchangeable shares of ARL, a corporate subsidiary of the Trust, may
provide a more tax-effective basis for investment in the Trust. The ARL
exchangeable shares are traded on the TSX under the symbol "ARX" and are
convertible into units, at the option of the shareholder, based on the then
current exchange ratio. Exchangeable shareholders are not eligible to receive
monthly cash distributions, however the exchange ratio increases on a monthly
basis by an amount equal to the current month's unit distribution multiplied
by the then current exchange ratio and divided by the 10 day weighted average
trading price of the units at the end of each month. The gain realized as a
result of the monthly increase in the exchange ratio is taxed, in most
circumstances, as a capital gain rather than income and is therefore subject
to a lower effective tax rate. Tax on the exchangeable shares is deferred
until the exchangeable share is sold or converted into a unit.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, and lease
rental obligations. These obligations are of a recurring and consistent nature
and impact cash flow in an ongoing manner. The Trust also has contractual
obligations and commitments that are of a less routine nature as disclosed in
the following table.
- -----------------------------------------------------------------------------------------------
Payments Due by Period
($ millions) 2006 2007-2008 2009-2010 Thereafter Total
- -----------------------------------------------------------------------------------------------
Debt repayments -- 279.4 49.2 198.0 526.6
Reclamation fund contributions (1) 6.1 11.8 10.2 80.9 109.0
Purchase commitments 2.4 3.4 3.2 8.0 17.0
Operating leases 4.1 8.1 7.3 -- 19.5
Derivative contract premiums (2) 12.4 -- -- -- 12.4
Retention bonuses 1.0 1.0 -- -- 2.0
TOTAL CONTRACTUAL OBLIGATIONS 26.0 303.7 69.9 286.9 686.5
- -----------------------------------------------------------------------------------------------
(1) Contribution commitments to a restricted reclamation fund associated with
the Redwater property acquired in the Redwater and NPCU acquisition
(2) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
The Trust enters into commitments for capital expenditures in advance of the
expenditures being made. At any given point in time, it is estimated that the
Trust has committed to approximately $40 to $60 million of capital
expenditures by means of giving the necessary authorizations to incur the
capital in a future period. This commitment has not been disclosed in the
above referenced commitment table as it is of a routine nature and is part of
normal course of operations for active oil and gas companies and trusts.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator.
The Trust is involved in litigation and claims arising in the normal course of
operations. Management is of the opinion that pending litigation will not have
a material adverse impact on the Trust's financial position or results of
operations.
OFF BALANCE SHEET ARRANGEMENTS
The Trust has certain lease agreements that are entered into in the normal
course of operations. All leases are treated as operating leases whereby the
lease payments are included in operating expenses or G&A expenses depending on
the nature of the lease. No asset or liability value has been assigned to
these leases in the balance sheet as of December 31, 2005. The total
obligation for future lease payments under all operating leases is disclosed
in the "Commitments and Contingencies" section of this MD&A.
The Trust entered into agreements to pay premiums pursuant to certain crude
oil derivative put contracts. Premiums of approximately $12.4 million will be
paid in 2006 for the put contracts in place at year end. As the premiums are
part of the underlying derivative contract, they have been recorded at fair
market value at December 31, 2005 on the balance sheet. The total obligation
for future premium payments is disclosed in the "Commitments and
Contingencies" section of this MD&A.
-14-
FINANCIAL REPORTING UPDATE
The following new standard has been reviewed by the Trust during 2005:
Financial Instruments - Recognition and Measurement - On January 27,
2005, the Accounting Standard's Board ("AcSB") issued CICA Handbook
section 3855 "Financial Instruments - Recognition and Measurement", CICA
Handbook section 1530 "Comprehensive Income" and CICA Handbook section
3865 "Hedges" that deal with the recognition and measurement of financial
instruments and comprehensive income. The new standards are intended to
harmonize Canadian standards with United States and international
accounting standards. The new standards are effective for annual and
interim periods in fiscal years beginning on or after October 1, 2006.
These new standards will impact the Trust in future periods and the
resulting impact will be assessed at that time.
CRITICAL ACCOUNTING ESTIMATES
The Trust has continuously evolved and documented its management and internal
reporting systems to provide assurance that accurate, timely internal and
external information is gathered and disseminated.
The Trust's financial and operating results incorporate certain estimates
including:
a) estimated revenues, royalties and operating costs on production as at
a specific reporting date but for which actual revenues and costs
have not yet been received;
b) estimated capital expenditures on projects that are in progress;
c) estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves that the Trust expects to recover
in the future;
d) estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and
foreign exchange rates;
e) estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
f) estimated future recoverable value of property, plant and equipment
and goodwill.
The Trust has hired individuals and consultants who have the skills required
to make such estimates and ensures individuals or departments with the most
knowledge of the activity are responsible for the estimates. Further, past
estimates are reviewed and compared to actual results, and actual results are
compared to budgets in order to make more informed decisions on future
estimates.
The ARC leadership team's mandate includes ongoing development of procedures,
standards and systems to allow ARC staff to make the best decisions possible
and ensuring those decisions are in compliance with the Trust's environmental,
health and safety policies.
FINANCIAL REPORTING AND INTERNAL CONTROLS UPDATE
On July 31, 2002, the United States Congress enacted the Sarbanes Oxley Act
("SOX"). SOX applies to all companies registered with the Securities and
Exchange Commission ("SEC"). Although ARC is not listed on a US stock
exchange, the Trust is registered with the SEC as a result of having acquired
Startech Energy Inc. in 2001 and therefore is required to comply with certain
portions of the SOX legislation. There are various components to the SOX
legislation, however the most comprehensive is Section 404 "Internal Controls
Over Financial Reporting". Section 404 requires that management undertake the
following:
o identify and document internal controls that impact financial
reporting;
o assess the effectiveness of those internal controls;
o remediate any deficiencies in internal controls and/or implement any
required controls that are not already in place;
o test the internal controls to ensure that they are operating
effectively; and
o issue a report, to be signed by the CEO and CFO, on management's
assessment of the effectiveness of internal controls and communicate
any material weaknesses.
ARC is currently required to comply with section 404 of the SOX legislation on
December 31, 2006. In conjunction with the 2006 year end audit, ARC's external
auditors will audit the Trust's internal controls and will issue two opinions,
one on the auditor's assessment of the effectiveness of internal controls over
financial reporting and one on the auditor's opinion on management's
assessment of the internal controls over financial reporting.
The Trust currently has a comprehensive plan and a dedicated team of
individuals in place to execute the plan of meeting the SOX Section 404
compliance date.
-15-
As of December 31, 2005, an internal evaluation was carried out of the
effectiveness of the Trust's disclosure controls and procedures as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934. Based on that
evaluation, the President and Chief Executive Officer and Chief Financial
Officer concluded that the design and operation of these disclosure controls
and procedures were effective to ensure that material information relating to
the Trust is made known to management on a timely basis and is included in
this report. No changes were made to our internal control over financial
reporting during the year ended December 31, 2005, that have materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
In addition to SOX, ARC is required to comply with Multilateral Instrument
52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings",
otherwise referred to as Canadian SOX ("C-Sox"). ARC is currently complying
with this legislation by filing bare interim and annual certificates. It is
expected that ARC will be required to file a full annual certificate in
conjunction with the December 31, 2006 year end. The Canadian requirements
closely parallel the SEC's certification rules, however, currently there is no
requirement to have external auditor's opinion on the Trust's internal
controls or management's assessment thereof.
OBJECTIVES AND 2006 OUTLOOK
It is the Trust's objective to provide superior long-term returns to
unitholders by focusing on the key strategic objectives of the business plan.
The Trust has provided unitholders with the following one, three and five year
returns (assuming the reinvestment of distributions):
TOTAL RETURNS
- --------------------------------------------------------------------------------------------
($ per unit except for per cent) One Year Three Year Five Year
- --------------------------------------------------------------------------------------------
Distributions per unit $ 1.99 $ 5.59 $ 9.46
Capital appreciation per unit 8.59 14.59 15.19
- --------------------------------------------------------------------------------------------
Total return per unit $ 10.58 $ 20.18 $ 24.65
Annualized total return per unit 62.4% 46.5% 38.8%
- --------------------------------------------------------------------------------------------
To the end of 2005, the Trust has provided cumulative cash distributions of
$16.23 per unit and capital appreciation of $16.49 per unit for a total return
of $32.72 per unit (27.9 per cent annualized total return) for unitholders who
invested in the Trust at inception in 1996.
The key future objectives of the Trust's business plan, as identified below,
are reviewed annually by the Board. The Trust was successful in meeting all of
its objectives in 2005 as individually addressed below. They continue to be
key objectives for 2006.
o ANNUAL RESERVES REPLACEMENT - The Trust increased its proved plus
probable reserves from 244 mmboe at year end 2004 to 287 mmboe at
year end 2005 through a combination of the reserves additions
associated with the Trust's $269 million 2005 capital budget and
reserves purchased in corporate and property acquisitions (net of
dispositions) for $598 million.
o ENSURING ACQUISITIONS ARE STRATEGIC AND ENHANCE UNITHOLDER RETURNS -
The Trust added significant assets in its core Pembina and southeast
Saskatchewan areas in 2005. In addition, the Trust added another
long-life, light oil property to its portfolio with the acquisition
of a controlling interest in the Redwater field. ARC believes that
long-life, light oil properties will provide future opportunities to
enhance unitholder value through the application of tertiary recovery
methods.
o CONTROLLING COSTS - Due to the diligence of field and office
operating staff, the Trust's operating costs per boe in 2005
increased less than three per cent over 2004 costs. Cash G&A costs in
2005 increased 30 per cent to $1.34 per boe from $1.03 per boe in
2004 as a result of both increased staff count and increased
compensation costs due to the extremely competitive marketplace for
experienced staff with oil and gas expertise. The Trust believes the
$1.34 per boe cash G&A costs will be "middle of the pack" for
mid-sized oil and gas producers, representing an appropriate balance
of the Trust's objective to develop and retain the best staff in the
industry, discussed below, and the desire to keep costs as low as
possible. The Trust's three year average FD&A costs of $11 per boe
prior to incorporating future development costs "FDC" and $13.50 per
boe with FDC, ARC believes will be better than the industry average
and demonstrates ARC's effective use of retained cash.
o CONSERVATIVE UTILIZATION OF DEBT - The Trust's debt levels were under
10 per cent of total capitalization and debt to 2005 cash flow was
0.7 times for the year ended 2005 taking into account full year cash
flow on properties acquired later in the year.
o CONTINUOUSLY DEVELOPING THE EXPERTISE OF OUR STAFF AND SEEKING TO
HIRE AND RETAIN THE BEST IN THE INDUSTRY - the Trust runs an active
training and development program for its employees and encourages
personal development. The Trust continues to assess compensation
levels in the industry to ensure that the Trust's compensation is
competitive so as to attract and retain the best employees. The
Trust's long-term incentive plan's payouts are directly tied to the
Trust's performance providing alignment between employees and
investors. Since ARC's 62 per cent total return in 2005 was one of
the top returns in our sector, total non-cash long-term compensation
expense increased to $0.74 per boe in 2005.
-16-
o BUILDING RELATIONSHIPS AND CONDUCTING BUSINESS IN A WAY THAT IS
VIEWED AS FAIR AND EQUITABLE - ARC employees, leadership team and
directors work hard to build the ARC "franchise value" through
honest, transparent dealings with our business partners. "Treating
all people with respect" is a key message inside and outside the
organization. This basic business fundamental allows us to build
enduring relationships with joint venture partners, land owners,
investors, banks and lending institutions, governments and the
investment community.
o PROMOTING THE USE OF PROVEN AND EFFECTIVE TECHNOLOGIES - The Trust
continues to research new technologies in an effort to conduct its
operations in the most efficient and cost effective manner. With the
Trust's purchase of Redwater and additional interest in Pembina, the
Trust will be increasing its research into tertiary recovery methods.
o BEING AN INDUSTRY LEADER IN HEALTH, SAFETY AND ENVIRONMENTAL
PERFORMANCE - The Trust's primary focus continues to be on operating
in a safe, reliable and responsible fashion. The Trust is committed
to the platinum level of CAPP Stewardship reporting and continues to
achieve reductions in greenhouse gas emissions under the Canada
Climate Change VCR initiative.
o CONTINUING TO ACTIVELY SUPPORT LOCAL INITIATIVES IN THE COMMUNITIES
IN WHICH WE LIVE AND WORK - The Trust is very actively involved in
charitable and philanthropic causes both in Calgary and in the rural
communities in which it operates. ARC continued to be a strong
supporter of the United Way, Alberta Cancer Foundation, Alberta
Children's Hospital and many community organizations in rural
centres.
Following is a summary of the Trust's 2006 Guidance issued by way of news
release on December 6, 2005:
- ----------------------------------------------------------------------------------------------------
2005 Revised 2006
Guidance Actual 2005 % Change GUIDANCE
- ----------------------------------------------------------------------------------------------------
PRODUCTION (boe/d) 56,000 56,254 -- 61,000
- ----------------------------------------------------------------------------------------------------
EXPENSES ($/boe):
Operating costs 7.00 6.93 (1) 8.65
Transportation 0.70 0.70 -- 0.70
G&A expenses - cash 1.25 1.34 7 1.70
G&A expenses - stock compensation plans 0.60 0.74 23 0.65
Interest 0.75 0.83 11 1.40
Taxes 0.15 0.19 -- 0.15
CAPITAL EXPENDITURES ($ millions) 270 269 -- 340
- ----------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE TRUST UNITS
AND UNITS ISSUABLE (millions) 191.3 191.2 -- 205.5
- ----------------------------------------------------------------------------------------------------
Actual 2005 results were in line with 2005 guidance except for G&A expenses,
which were higher because of increased staff compensation costs and expected
payments under the Long-term Employee Incentive Plan. Interest costs increased
because of acquisitions, which were made during the year and partially funded
by debt.
-17-
2006 CASH FLOW AND HEDGING SENSITIVITY
Below is a table that illustrates sensitivities to pre-hedged cash flow with
operational changes and changes to the business environment:
- -----------------------------------------------------------------------------------------------------
Impact On Annual
Cash Flow
BUSINESS ENVIRONMENT Assumption Change $/Unit
- -----------------------------------------------------------------------------------------------------
Oil price (US$WTI/bbl) (1) $ 55.00 $ 1.00 $ 0.05
Natural gas price (Cdn$AECO/mcf) (1) $ 10.55 $ 0.10 $ 0.03
CAD/USD exchange rate $ 0.87 $ 0.01 $ 0.06
Interest rate on debt 4.1% 1.0% $ 0.03
- -----------------------------------------------------------------------------------------------------
OPERATIONAL
Liquids production volume (bbl/d) 31,000 1.0% $ 0.02
Gas production volumes (mmcf/d) 181.0 1.0% $ 0.02
Operating expenses per boe $ 8.60 1.0% $ 0.01
Cash G&A expenses per boe $ 1.70 10.0% $ 0.02
- -----------------------------------------------------------------------------------------------------
(1) Analysis does not include the effect of derivative contracts.
ASSESSMENT OF BUSINESS RISKS
The ARC management team is focused on long-term strategic planning and has
identified the key risks, uncertainties and opportunities associated with the
Trust's business that can impact the financial results as follows:
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Trust's operational results and financial condition, and therefore the
amount of distributions paid to the unitholders will be dependent on the
prices received for oil and natural gas production. Oil and gas prices have
fluctuated widely during recent years and are determined by economic and in
the case of oil prices, political factors. Supply and demand factors,
including weather and general economic conditions as well as conditions in
other oil and natural gas regions impact prices. Any movement in oil and
natural gas prices could have an effect on the Trust's financial condition and
therefore on the distributions to the holders of trust units. ARC may manage
the risk associated with changes in commodity prices by entering into oil or
natural gas price derivative contracts. If ARC engages in activities to manage
its commodity price exposure, the Trust may forego the benefits it would
otherwise experience if commodity prices were to increase. In addition,
commodity derivative contracts activities could expose ARC to losses. To the
extent that ARC engages in risk management activities related to commodity
prices, it will be subject to credit risks associated with counterparties with
which it contracts.
VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES
Variations in interest rates could result in a significant increase in the
amount the Trust pays to service debt, resulting in a decrease in
distributions to unitholders. World oil prices are quoted in US dollars and
the price received by Canadian producers is therefore affected by the
Canadian/US dollar exchange rate that may fluctuate over time. A material
increase in the value of the Canadian dollar may negatively impact the Trust's
net production revenue. In addition, the exchange rate for the Canadian dollar
versus the US dollar has increased significantly over the last 12 months,
resulting in the receipt by the Trust of fewer Canadian dollars for its
production, which may affect future distributions. ARC has initiated certain
derivative contracts to attempt to mitigate these risks. To the extent that
ARC engages in risk management activities related to foreign exchange rates,
it will be subject to credit risk associated with counterparties with which it
contracts. The increase in the exchange rate for the Canadian dollar and
future Canadian/US exchange rates may impact future distributions and the
future value of the Trust's reserves as determined by independent evaluators.
RESERVES ESTIMATES
The reserves and recovery information contained in ARC's independent reserves
evaluation is only an estimate. The actual production and ultimate reserves
from the properties may be greater or less than the estimates prepared by the
independent reserves evaluator. The reserves report was prepared using certain
commodity price assumptions that are described in the notes to the reserves
tables. If lower prices for crude oil, natural gas liquids and natural gas are
realized by the Trust and substituted for the price assumptions utilized in
those reserves reports, the present value of estimated future net cash flows
for the Trust's reserves would be reduced and the reduction could be
significant, particularly based on the constant price case assumptions.
DEPLETION OF RESERVES AND MAINTENANCE OF DISTRIBUTION
ARC's future oil and natural gas reserves and production, and therefore its
cash flows, will be highly dependent on ARC's success in exploiting its
reserves base and acquiring additional reserves. Without reserves additions
through acquisition or development activities, the
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Trust's reserves and production will decline over time as the oil and natural
gas reserves are produced out.
There can be no assurance that the Trust will make sufficient capital
expenditures to maintain production at current levels; nor as a consequence,
that the amount of distributions by the Trust to unitholders can be maintained
at current levels.
To the extent that external sources of capital, including the issuance of
additional trust units become limited or unavailable, ARC's ability to make
the necessary capital investments to maintain or expand its oil and natural
gas reserves could be impaired. To the extent that ARC is required to use cash
flow to finance capital expenditures or property acquisitions, the level of
distributions could be reduced.
There can be no assurance that ARC will be successful in developing or
acquiring additional reserves on terms that meet the Trust's investment
objectives.
ACQUISITIONS
The price paid for reserves acquisitions is based on engineering and economic
estimates of the reserves made by independent engineers modified to reflect
the technical views of management. These assessments include a number of
material assumptions regarding such factors as recoverability and
marketability of oil, natural gas, natural gas liquids and sulphur, future
prices of oil, natural gas, natural gas liquids and sulphur and operating
costs, future capital expenditures and royalties and other government levies
that will be imposed over the producing life of the reserves. Many of these
factors are subject to change and are beyond the control of the operators of
the working interests, management and the Trust. In particular, changes in the
prices of and markets for oil, natural gas, natural gas liquids and sulphur
from those anticipated at the time of making such assessments will affect the
amount of future distributions and as such the value of the units. In
addition, all such estimates involve a measure of geological and engineering
uncertainty that could result in lower production and reserves than attributed
to the working interests. Actual reserves could vary materially from these
estimates. Consequently, the reserves acquired may be less than expected,
which could adversely impact cash flows and distributions to unitholders.
OPERATIONAL AND RESERVE RISKS RELATING TO THE ACQUISITION OF ASSETS
Risk factors set forth in this MD&A relating to the oil and natural gas
business and the operations and reserves of the Trust apply equally in respect
of the acquisitions that the Trust makes over time. Reserve and recovery
information contained in this MD&A in respect of acquisitions is only an
estimate and the actual production from and ultimate reserves of the
acquisitions, particularly the NPCU and Redwater properties may be greater or
less than the estimates contained in such reports. There are significant
environmental reclamation liabilities attributable to the NPCU and Redwater
properties.
COMPETITION
There is strong competition relating to all aspects of the oil and gas
industry. There are numerous trusts in the oil and gas industry that are
competing for the acquisition of properties with longer life reserves and
properties with exploitation and development opportunities. As a result of
such increasing competition, it will be more difficult to acquire reserves on
beneficial terms. ARC competes for reserve acquisitions and skilled industry
personnel with a substantial number of other oil and gas companies, many of
which have significantly greater financial and other resources than the Trust.
NATURE OF UNITS
Units will have no value when the oil and gas reserves from the properties can
no longer be economically produced and, as a result, cash distributions do not
represent a "yield" in the traditional sense as they represent both a return
of capital and a return on investment.
The units do not represent a traditional investment in the oil and natural gas
sector and should not be viewed by investors as shares in a corporation. The
units represent a fractional interest in the Trust. As holders of units,
unitholders will not have the statutory rights normally associated with
ownership of shares of a corporation. The Trust's sole assets will be the
royalty interests in the properties. The price per unit is a function of
anticipated distributable income, the properties acquired by ARC and ARC's
ability to effect long-term growth in the value of the Trust. The market price
of the units will be sensitive to a variety of market conditions including,
but not limited to, interest rates and the ability of the Trust to acquire
suitable oil and natural gas properties. Changes in market conditions may
adversely affect the trading price of the units.
The net asset value, utilizing assumptions by independent engineers, of the
assets of the Trust will vary from time to time dependent upon a number of
factors beyond the control of management, including oil and gas prices. The
trading prices of the units from time to time are also determined by a number
of factors that are beyond the control of management and such trading prices
may be greater than the net asset value of the Trust's assets.
ENVIRONMENTAL CONCERNS
The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. A breach of such
legislation may result in the imposition of fines or issuance of clean up
orders in respect of ARC or its working interests. Such legislation may be
changed to impose higher standards and potentially more costly obligations on
ARC. Although ARC has established a reclamation fund for the purpose of
funding its currently estimated future environmental and reclamation
obligations based on its current knowledge, there can be no assurance that the
Trust will be able to satisfy its actual future environmental and reclamation
obligations. Additionally, the
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potential impact on the Trust's operations and business of the December 1997
Kyoto Protocol, which has been ratified by Canada, with respect to instituting
reductions of greenhouse gases, is difficult to quantify at this time as
specific measures for meeting Canada's commitments have not been developed.
CHANGES IN LEGISLATION
Income tax laws, or other laws or government incentive programs relating to
the oil and gas industry, such as the treatment of mutual fund trusts and
resource taxation, may in the future be changed or interpreted in a manner
that adversely affects the Trust and its unitholders. Tax authorities having
jurisdiction over the Trust or the unitholders may disagree with how the Trust
calculates its income for tax purposes or could change administrative
practices to the detriment of the Trust or the detriment of its unitholders.
ARC intends that the Trust will continue to qualify as a mutual fund trust for
purposes of the Tax Act. The Trust may not, however, always be able to satisfy
any future requirements for the maintenance of mutual fund trust status.
Should the status of the Trust as a mutual fund trust be lost or successfully
challenged by a relevant tax authority, certain adverse consequences may arise
for the Trust and its unitholders.
OPERATIONAL MATTERS
The operation of oil and gas wells involves a number of operating and natural
hazards that may result in blowouts, environmental damage and other unexpected
or dangerous conditions resulting in damage to operating subsidiaries of the
Trust and possible liability to third parties. ARC will maintain liability
insurance, where available, in amounts consistent with industry standards.
Business interruption insurance may also be purchased for selected facilities,
to the extent that such insurance is available. ARC may become liable for
damages arising from such events against which it cannot insure or against
which it may elect not to insure because of high premium costs or other
reasons. Costs incurred to repair such damage or pay such liabilities will
reduce distributable cash.
Continuing production from a property, and to some extent the marketing of
production therefrom, are largely dependent upon the ability of the operator
of the property. Operating costs on most properties have increased steadily
over recent years. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although
satisfactory title reviews are generally conducted in accordance with industry
standards, such reviews do not guarantee or certify that a defect in the chain
of title may not arise to defeat the claim of the Trust to certain properties.
A reduction of the distributions could result in such circumstances.
NON-RESIDENT OWNERSHIP OF TRUST UNITS
In order for the Trust to maintain its status as a mutual fund trust under the
Tax Act, the Trust intends to comply with the requirements of the Tax Act for
"mutual fund trusts" at all relevant times. In this regard, the Trust shall
among other things, monitor the ownership of the units to carry out such
intentions. The Trust Indenture provides that if at any time the Trust becomes
aware that the beneficial owners of 50 per cent or more of the units then
outstanding are or may be non-residents or that such a situation is imminent,
the Trust shall take such action as it is able and as may be necessary to
carry out the foregoing intention.
DEBT SERVICE AND ADDITIONAL FINANCING
Amounts paid in respect of interest and principal on debt will reduce
distributions. Variations in interest rates and scheduled principal repayments
could result in significant changes in the amount required to be applied to
debt service before payment of distributions. Certain covenants of the
agreements with ARC's lenders may also limit distributions. Although ARC
believes the credit facilities will be sufficient for the Trust's immediate
requirements, there can be no assurance that the amount will be adequate for
the future financial obligations of the Trust or that additional funds will be
able to be obtained.
The lenders will be provided with security over substantially all of the
assets of ARC. If ARC becomes unable to pay its debt service charges or
otherwise commits an event of default such as bankruptcy, the lender may
foreclose on or sell the working interests.
In the normal course of making capital investments to maintain and expand the
oil and gas reserves of the Trust, additional units are issued from treasury
that may result in a decline in production per unit and reserves per unit.
Additionally, from time to time the Trust issues units from treasury in order
to reduce debt and maintain a more optimal capital structure. Conversely, to
the extent that external sources of capital, including the issuance of
additional units, become limited or unavailable, the Trust's ability to make
the necessary capital investments to maintain or expand its oil and gas
reserves will be impaired. To the extent that ARC is required to use cash flow
to finance capital expenditures or property acquisitions, to pay debt service
charges or to reduce debt, the level of distributable income will be reduced.
EXPANSION OF OPERATIONS
The operations and expertise of management of the Trust are currently focused
on conventional oil and gas production and development in the western Canadian
sedimentary basin. In the future, the Trust may acquire oil and gas properties
outside this geographic area. In addition, the Trust Indenture does not limit
the activities of the Trust to oil and gas production and development, and the
Trust could acquire other energy related assets, such as oil and natural gas
processing plants or pipelines, or an interest in an oil sands project.
Expansion of our activities into new areas may present new additional risks or
alternatively, significantly increase the exposure to one or more of the
present risk factors, which may result in future operational and financial
conditions of the Trust being adversely affected.
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ADDITIONAL INFORMATION
Additional information relating to ARC can be found on SEDAR at WWW.SEDAR.COM.
ANNUAL HISTORICAL REVIEW
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For the year ended December 31
(Cdn$ thousands, except per unit amounts) 2005 2004 2003 2002 2001
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FINANCIAL
Revenue before royalties 1,165,197 901,782 743,182 444,835 515,596
Per unit (1) 6.10 4.85 4.80 3.72 5.00
Cash flow 639,511 448,033 396,180 223,969 260,270
Per unit - basic (1) 3.35 2.41 2.56 1.87 2.53
Per unit - diluted 3.32 2.38 2.48 1.86 2.54
Net income 356,935 241,690 284,559 69,981 130,993
Per unit - basic (5) 1.90 1.32 1.88 0.60 1.30
Per unit - diluted 1.88 1.31 1.82 0.59 1.32
Cash distributions 376,566 329,977 279,328 183,617 234,053
Per unit (2) 1.99 1.80 1.80 1.56 2.31
Total assets 3,251,161 2,304,998 2,281,775 1,467,918 1,380,004
Total liabilities 1,415,519 755,650 730,039 599,252 563,882
Net debt outstanding (4) 578,086 264,842 262,071 347,795 288,684
Weighted
average units (thousands) (3) 191,172 186,105 154,695 119,613 103,062
Units outstanding and issuable
at period end (thousands) (3) 202,039 188,804 182,777 126,444 111,692
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CAPITAL EXPENDITURES
Geological and geophysical 9,219 5,388 5,671 1,966 2,215
Drilling and completions 200,873 144,487 110,277 70,074 73,147
Plant and facilities 55,032 41,089 36,457 14,357 22,970
Other capital 3,710 2,820 3,359 1,881 3,886
Total capital expenditures 268,834 193,784 155,764 88,278 102,218
Property acquisitions
(dispositions), net 91,286 (58,219) (161,609) 119,113 12,911
Corporate acquisitions (6) 504,996 72,009 721,590 -- 509,748
Total capital expenditures
and net acquisitions 865,116 207,574 715,745 207,391 624,877
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OPERATING
Production
Crude oil (bbl/d) 23,282 22,961 22,886 20,655 20,408
Natural gas (mmcf/d) 173.8 178.3 164.2 109.8 115.2
Natural gas liquids (bbl/d) 4,005 4,191 4,086 3,479 3,511
Total (boe per day 6:1) 56,254 56,870 54,335 42,425 43,111
Average prices
Crude oil ($/bbl) 61.11 47.03 36.90 31.63 31.70
Natural gas ($/mcf) 8.96 6.78 6.40 4.41 5.72
Natural gas liquids ($/bbl) 49.92 39.04 32.19 24.01 31.03
Oil equivalent ($/boe) 56.54 43.13 37.29 28.73 32.76
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RESERVES (7)
(company interest)
Proved plus probable reserves
Crude oil and NGL (mbbl) 163,385 123,226 129,663 117,241 114,243
Natural gas (bcf) 741.7 724.5 720.2 408.8 385.5
Total (mboe) 286,997 243,974 249,704 185,371 178,496
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TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 27.58 17.98 14.87 13.44 13.54
Low 16.55 13.50 10.89 11.04 10.25
Close 26.49 17.90 14.74 11.90 12.10
Average daily volume (thousands) 656 420 430 305 414
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(1) Based on weighted average trust units plus units issuable for
exchangeable shares.
(2) Based on number of trust units outstanding at each cash distribution
date.
(3) Includes trust units issuable for outstanding exchangeable shares based
on the period end exchange ratio.
(4) Total current and long-term debt net of working capital.
(5) Net income in the basic per trust unit calculation has been reduced by
interest on the convertible debentures.
(6) Represents total consideration for the corporate acquisition including
fees but prior to working capital, asset retirement obligation and future
income tax liability assumed on acquisition.
(7) Established reserves for 2002 and 2001.
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QUARTERLY REVIEW
- ---------------------------------------------------------------------------------------------------------------------------------
(Cdn$ thousands, except per unit amounts) 2005 2004
- ---------------------------------------------------------------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
Revenue before royalties 365,298 310,249 251,596 238,054 232,112 230,769 233,307 205,594
Per unit (1) 1.89 1.62 1.32 1.26 1.23 1.23 1.26 1.12
Cash flow 207,621 168,117 121,808 141,965 106,935 110,835 122,249 108,014
Per unit - basic (1) 1.07 0.88 0.64 0.75 0.57 0.59 0.66 0.59
Per unit - diluted 1.07 0.87 0.63 0.74 0.56 0.59 0.65 0.58
Net income 130,474 114,600 73,215 38,646 112,995 38,897 50,338 39,460
Per unit - basic (5) 0.68 0.61 0.39 0.21 0.61 0.21 0.28 0.22
Per unit - diluted 0.68 0.59 0.38 0.20 0.60 0.21 0.27 0.22
Cash distributions 115,671 92,559 84,468 83,867 83,531 83,178 82,053 81,215
Per unit (2) 0.60 0.49 0.45 0.45 0.45 0.45 0.45 0.45
Total assets 3,251,161 2,483,540 2,427,463 2,303,948 2,304,998 2,316,297 2,309,599 2,278,608
Total liabilities 1,415,519 912,160 895,179 785,776 755,650 804,603 768,073 752,166
Net debt outstanding (4) 578,086 357,560 366,216 254,252 264,842 220,500 220,074 284,001
Weighted average units (thousands) (3) 193,445 191,709 190,315 189,210 188,521 187,629 184,998 183,314
Units outstanding and issuable at
period end (thousands) (3) 202,039 192,089 191,329 189,609 188,804 188,185 187,296 183,980
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CAPITAL EXPENDITURES
Geological and geophysical 3,040 2,258 2,659 1,262 867 828 1,373 2,320
Drilling and completions 65,690 65,676 33,465 36,042 39,125 42,553 24,867 37,942
Plant and facilities 17,031 14,803 8,703 14,495 6,183 11,668 7,282 15,956
Other capital 2,020 317 652 721 1,480 394 605 341
Total capital expenditures 87,781 83,054 45,479 52,520 47,655 55,443 34,127 56,559
Property acquisitions
(dispositions), net 3,037 5,860 78,721 3,668 (1,036) (5,345) (53,412) 1,574
Corporate acquisitions (6) 462,814 -- 42,182 -- 41,449 -- 30,560 --
Total capital expenditures
and net acquisitions 553,632 88,914 166,382 56,188 88,068 50,098 11,275 58,133
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OPERATING
Production
Crude oil (bbl/d) 25,534 23,513 22,046 21,993 22,969 22,496 22,720 23,663
Natural gas (mmcf/d) 177.9 168.2 173.1 176.1 174.7 177.4 186.7 174.5
Natural gas liquids (bbl/d) 3,943 4,047 3,962 4,072 4,097 4,034 4,313 4,323
Total (boe per day 6:1) 59,120 55,592 54,860 55,410 56,179 56,096 58,147 57,075
Average prices
Crude oil ($/bbl) 62.12 69.37 58.37 53.63 49.48 51.00 47.43 40.41
Natural gas ($/mcf) 12.05 9.08 7.42 7.20 6.82 6.65 6.99 6.64
Natural gas liquids ($/bbl) 57.14 50.43 46.13 46.57 43.72 42.30 38.22 32.30
Oil equivalent ($/boe) 67.16 60.66 50.40 47.74 44.62 44.54 43.82 39.58
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TRUST UNIT TRADING
(BASED ON INTRA-DAY TRADING)
Unit prices
High 27.58 24.20 20.30 20.40 17.98 17.38 15.74 15.74
Low 20.45 19.94 16.88 16.55 14.80 15.02 14.28 13.50
Close 26.49 24.10 19.94 18.15 17.90 16.85 15.35 15.64
Average daily volume (thousands) 653 599 605 895 456 384 337 502
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(1) Based on weighted average trust units plus units issuable for
exchangeable shares.
(2) Based on number of trust units outstanding at each cash distribution
date.
(3) Includes trust units issuable for outstanding exchangeable shares based
on the period end exchange ratio.
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(4) Total current and long-term debt net of working capital.
(5) Net income in the basic per trust unit calculation has been reduced by
interest on the convertible debentures.
(6) Represents total consideration for the corporate acquisition including
fees but prior to working capital, asset retirement obligation and future
income tax liability assumed on acquisition.
(7) Established reserves for 2002 and 2001.
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