EXHIBIT 99.1
------------
------------------------------------------------------------------------------------------------------------------
Three Months ended Six Months Ended
June 30 June 30
2004 2003 2004 2003 (5)
------------------------------------------------------------------------------------------------------------------
FINANCIAL
($CDN thousands, except per unit and per boe amounts)
Revenue before royalties (5) 233,307 198,542 438,901 376,459
Per unit (1) 1.26 1.36 2.38 2.72
Per boe (7) 44.09 37.77 41.86 40.72
Cash flow (3) 122,249 116,546 230,263 219,053
Per unit (1) 0.66 0.80 1.25 1.58
Per boe (7) 23.10 22.17 27.96 23.70
Net income (6) (8) 51,181 128,159 91,303 194,201
Per unit (1) (6) 0.28 0.85 0.50 1.37
Cash distributions 82,053 67,495 163,268 126,836
Per unit (1) 0.45 0.45 0.90 0.90
Net debt outstanding (4) 220,074 466,988 220,074 466,988
OPERATING
Production
Crude oil (bbl/d) 22,720 24,078 23,191 22,580
Natural gas (mcf/d) 186,681 175,706 180,607 146,669
Natural gas liquids (bbl/d) 4,313 4,397 4,318 4,049
Total (boe/d) (7) 58,147 57,759 57,611 51,074
Average prices (5)
Crude oil ($/bbl) 47.43 36.61 43.85 38.61
Natural gas ($/mcf) 6.99 6.59 6.83 7.21
Natural gas liquids ($/bbl) 38.22 28.83 35.26 33.89
Oil equivalent ($/boe) (7) 44.09 37.77 41.86 40.72
------------------------------------------------------------------------------------------------------------------
TRUST UNITS
(thousands)
Units outstanding, end of period 184,247 160,165 184,247 160,165
Units issuable for exchangeable shares 3,049 3,019 3,049 3,019
Total units outstanding and issuable for
exchangeable shares, end of period 187,296 163,184 187,296 163,184
Weighted average units (2) 184,998 145,546 184,167 138,486
------------------------------------------------------------------------------------------------------------------
TRUST UNIT TRADING STATISTICS
($CDN, except volumes) based on intra-day trading
High 15.74 12.84 15.74 12.84
Low 14.28 11.29 13.50 10.89
Close 15.35 12.50 15.35 12.50
Average daily volume 336,965 502,784 420,668 407,973
==================================================================================================================
(1) Per unit amounts (with the exception of per unit distributions) are based
on weighted average units.
(2) Includes exchangeable shares converted at the end of period exchange ratio.
(3) Management uses cash flow (before changes in non-cash working capital) to
analyze operating performance and leverage. Cash flow 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. 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. All references to cash flow throughout this report are based on cash
flow before changes in non-cash working capital.
(4) The 2004 net debt outstanding excludes unrealized commodity and foreign
exchange contracts asset and liability, the deferred hedge loss and
deferred commodity and foreign currency contracts.
(5) 2003 prices and revenue have been reclassified to reflect prices prior to
transportation charges in accordance with CICA section 1100 that was
implemented on January 1, 2004. 2003 average prices are inclusive of gains
and losses on commodity and foreign currency contracts while 2004 average
prices are prior to gains and losses on commodity and foreign currency
contracts, pursuant to a new policy for hedge accounting.
(6) Net income and net income per unit for 2003 have been restated for the
adoption of new accounting standards for asset retirement obligations and
stock based compensation. See Note 2 of the unaudited interim consolidated
financial statements for details of the restatement.
(7) Barrels of oil equivalent (BOE's) may be misleading, particularly if used
in isolation. In accordance with NI 51-101, a BOE conversion ratio for
natural gas of 6 Mcf:1bbl has been used, which is based on an energy
equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. References to BOE's
throughout this quarterly report are based on a conversion ratio of 6:1.
(8) Net income before non-recurring, non-cash items increased to $58.5 million
in the second quarter of 2004 compared to $55.5 million in the second
quarter of 2003. Net income of $51.2 million in the second quarter of 2004
included an after-tax non-cash loss of $6.5 million for unrealized losses
on derivative contracts and a non-cash unrealized foreign exchange loss of
$0.8 million on translation of U.S. denominated debt balances. Net income
of $128.2 million in the second quarter of 2003 included a non-cash future
income tax recovery of $65 million due to change in future income tax rates
and a non-cash unrealized foreign exchange gain of $7.7 million on
translation of U.S. denominated debt balances
--------------------------------------------------------------------------------
MESSAGE TO UNITHOLDERS
--------------------------------------------------------------------------------
The oil and gas sector continued to perform strongly in the second quarter as
commodity prices remained high with an average WTI price of US$38.34/bbl and an
average Alberta AECO natural gas price of $6.80 per mcf. Several fundamental
factors account for commodity prices remaining at all time highs. Demand spurred
by strong U.S. and Asian economies, political instability in many oil producing
countries and tight, just-in-time global supply have all contributed to the
current state of the commodity markets. The inability of OPEC to increase
production in response to rising demand has contributed to concerns about oil
supply. Natural gas prices have risen in tandem with oil prices. Several factors
contributed to higher natural gas prices during the quarter including increased
demand for gas generated electricity and increased industrial consumption.
ARC Energy Trust ("ARC" or "the Trust") is taking advantage of the elevated
commodity prices by expanding its hedging program for 2004 and 2005 at favorable
prices. The Trust currently has xxxxxx in place in the $34 to $40 band with
approximately 63 per cent of its liquids production hedged for the remainder of
2004 and approximately 46 per cent of oil production hedged for 2005. The Trust
is less hedged in natural gas with only 38 per cent of production hedged in the
third quarter of 2004 and 27 per cent in the last quarter of 2004. It is the
Trust's view that oil prices will be subject to more volatility due to the
political premium that currently exists in the market and therefore it is
prudent to lock-in current high prices through hedging.
In the past year a major challenge for the sector has been the increasing costs
of assets available for acquisition. ARC is in a strong position as it has a
portfolio of high quality properties with development opportunities that allow
it to be extremely selective in the acquisition market and still maintain
production at current levels. The trust industry anticipates substantial
acquisition opportunities this year with approximately 150,000 barrels of
production per day expected to become available in the market. ARC consistently
reviews all acquisition opportunities and with our excellent balance sheet is in
a position to compete for appropriate assets that will enhance our current
portfolio of assets.
The oil and gas industry is experiencing increases in the cost of industry
services and supplies, particularly in the cost of steel, resulting in higher
drilling costs. ARC's Board of Directors has approved a $25 million increase in
the capital budget for 2004 to $200 million to cover the increased costs and to
participate in additional development opportunities. In the current high
commodity price environment, the rate of return ARC is achieving on its internal
development program significantly exceeds its targeted rate of return on other
investment opportunities.
On July 1, 2004, the Alberta Government passed limited liability legislation for
unitholders of income trusts. XXX undertook a leadership role in lobbying
government politicians for this legislation. Limited liability should remove any
remaining barriers for inclusion of trust units in pension funds and for
inclusion of some trusts in the S&P index. Unitholders now share similar
liability protection as shareholders of public corporations.
/s/ Xxxx X. Xxxxxxxx
Xxxx X. Xxxxxxxx
Director, President and
Chief Executive Officer
2 ARC Energy Trust
--------------------------------------------------------------------------------
ACCOMPLISHMENTS
--------------------------------------------------------------------------------
o Second quarter production averaged 58,147 boe per day compared to 57,759 boe
per day in the second quarter of 2003. Production was above forecast due to
incremental production from ARC's internal development program and initial
high production rates from drilling projects in the Ante Creek and Xxxxxx
areas. These initial high rates are expected to taper off in the latter part
of the year. ARC's field and operational staff also played a key role in
delivering higher than expected production in the quarter by minimizing
downtime due to plant turnarounds. With continued internal development and
optimization activities on ARC's properties, production volumes for 2004 are
expected to average approximately 55,000 boe per day despite a disposition of
1,800 boe per day that occurred during the second quarter.
o ARC realized record cash flow of $122.2 million compared to $116.5 million in
the second quarter of 2003 due to continued high commodity prices and
increased production. ARC directed $82.1 million of cash flow toward
distributions, $34.1 million toward the second quarter capital program, $4.2
million to debt reduction and $1.8 million (including interest) to the
reclamation fund.
o Net income before non-recurring, non-cash items increased to $58.5 million in
the second quarter of 2004 compared to $55.5 million in the second quarter of
2003. Net income of $51.2 million in the second quarter of 2004 included an
after-tax non-cash loss of $6.5 million for unrealized losses on derivative
contracts and a non-cash unrealized foreign exchange loss of $0.8 million on
translation of U.S. denominated debt balances. Net income of $128.2 million
in the second quarter of 2003 included a non-cash future income tax recovery
of $65 million due to change in future income tax rates and a non-cash
unrealized foreign exchange gain of $7.7 million on translation of U.S.
denominated debt balances.
o The Trust declared distributions of $82.1 million ($0.45 per unit)
representing a payout ratio of 67 per cent with the remainder of cash flow
directed toward funding 100 per cent of ARC's internal development program
for the quarter, debt repayment and the reclamation fund. Year-to-date, ARC
has funded 65 per cent of its internal development capital program from cash
flow.
o The Trust's balance sheet continued to strengthen in the second quarter. The
Trust's net debt to annualized cash flow was 0.5 as at June 30, 2004.
o Operating costs were $6.64 per boe in the second quarter of 2004, up slightly
from $6.57 per boe in the second quarter of 2003. Per unit operating costs
are below forecast for the first half of 2004 due to high production rates
along with ARC's ongoing cost reduction initiatives. ARC expects operating
costs for the second half of 2004 to come in on-track at approximately $7.00
per boe.
ARC Energy Trust 3
--------------------------------------------------------------------------------
ACCOMPLISHMENTS (cont'd)
--------------------------------------------------------------------------------
o ARC acquired the remaining 30 per cent ownership of the Cranberry Slave Point
D Pool in the Prestville area in northern Alberta through the purchase of a
private company. The purchase was completed by issuing 2,032,358 ARC Energy
Trust units to the vendor for total consideration of $30.6 million.
o ARC closed previously announced dispositions of approximately 1,800 boe per
day of production in the Sundre and Bow Island areas for total consideration
of $55 million. The disposition of these properties will enable the Trust to
focus on development opportunities in its core areas.
o On April 27, the Trust announced the closing of a US$125 million private
placement of long-term debt in the form of senior secured notes to a group of
U.S. and Canadian institutional investors. The notes were offered in two
tranches with an all-in interest rate of 4.86 per cent and an average life of
8.8 years. Concurrently, ARC entered into an agreement to swap the fixed rate
of 4.62 per cent on a notional amount of US$62.5 million into a variable
three month U.S. LIBOR rate plus 38.25 basis points, resulting in a current
floating rate of two per cent. Proceeds from the offering were used to repay
the Company's outstanding bank debt.
o ARC's foreign ownership level currently stands at approximately 22 per cent,
well below the level that would jeopardize the Trust's status as a mutual
fund trust.
4 ARC Energy Trust
--------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
--------------------------------------------------------------------------------
Management's discussion and analysis ("MD&A") should be read in conjunction with
the unaudited interim consolidated financial statements for the period ended
June 30, 2004 and the audited consolidated financial statements and MD&A for the
year-ended December 31, 2003.
This MD&A was written on July 30, 2004.
Management uses cash flow (before changes in non-cash working capital) 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. All references to cash flow throughout this MD&A are based
on cash flow before changes in non-cash working capital.
Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as operating netbacks ("netbacks") and total capitalization 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 relating to
future events or future performance. 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 necessarily
involve known and unknown risks and uncertainties, including the business risks
discussed in the MD&A as at and for the year ended December 31, 2003, 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 implemented new accounting policies in the first quarter of 2004 and
fourth quarter of 2003 pursuant to requirements of the Canadian Institute of
Chartered Accountants ("CICA"). The 2004 reported results were impacted as a
result of differing presentation and disclosure under the new policies and
instruments. In addition, certain amounts presented for comparative purposes
have been restated as a result of the retroactive application of these new
policies and instruments. See "Impact of New Accounting Policies" in this MD&A
for a detailed description of the impact on reported results.
ARC Energy Trust 5
HIGHLIGHTS
-------------------------------------------------------------------------------------------------------------------
Three Months ended Six Months Ended
June 30 June 30
CDN$ millions, except per unit and volume data 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------
Cash flow from operations (2) 122.2 116.5 230.3 219.1
Cash flow from operations per unit (2) 0.66 0.80 1.25 1.58
Net income (1) (3) 51.2 128.2 91.3 194.2
Net income before non-cash fair value adjustments (1) (3) 57.7 128.2 113.2 194.2
Distributions per unit 0.45 0.45 0.90 0.90
Daily production (boe/d) (4) 58,147 57,759 57,611 51,074
===================================================================================================================
(1) 2003 net income has been restated for retroactive changes in accounting
policies relating to asset retirement obligations and stock based
compensation.
(2) Before changes in non-cash working capital.
(3) Net income is after non-cash charges of $6.5 million and $21.8 million,
respectively for the three and six months ended June 30, 2004 relating to
fair value adjustments pursuant to hedge accounting. These amounts are net
of future income tax recoveries of $3.5 million and $11.7 million,
respectively.
(4) Reported production amount is based on company interest before royalty
burdens.
PRODUCTION
Production volumes averaged 58,147 boe/d for the second quarter of 2004 and
57,611 boe/d for the first six months of 2004. The one per cent increase in
second quarter production and 13 per cent increase in year-to-date 2004
production compared to 2003, was primarily attributed to the acquisition of Star
Oil & Gas Ltd. ("Star") in the second quarter of 2003 and positive results of
the Trust's winter drilling program.
[GRAPHIC OMITTED]
[BAR CHART -- PRODUCTION]
Second quarter production was three per cent higher than exit 2003 production of
approximately 56,500 boe/d. Second quarter production includes approximately
2,300 boe/d for new xxxxx drilled and tied-in during the first half of 2004. The
incremental production was partially offset by natural production declines on
existing properties.
During the second quarter, the Trust drilled 17 net xxxxx on operated
properties; 10 oil xxxxx and seven natural gas xxxxx. On a year-to-date basis,
the Trust has drilled 38 net xxxxx on operated properties; 21 oil xxxxx and 17
natural gas xxxxx.
-----------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 % June 30 %
Production 2004 2003 Change 2004 2003 Change
-----------------------------------------------------------------------------------------------------------------
Crude oil (bbl/day) 22,720 24,078 (6) 23,191 22,580 3
Gas (mcf/day) 186,681 175,706 6 180,607 146,669 23
NGL (bbl/day) 4,313 4,397 (2) 4,318 4,049 7
-----------------------------------------------------------------------------------------------------------------
Total Production (boe/d) 58,147 57,759 1 57,611 51,074 13
=================================================================================================================
Natural gas production increased to 187 Mmcf per day in the second quarter of
2004 and 181 Mmcf per day for the first six months of 2004, an increase of six
per cent and 23 per cent, respectively, from the same periods of 2003.
Year-to-date natural gas production comprised approximately 52 per cent of the
Trust's production portfolio compared to 48 per cent in the comparative period
of 2003.
6 ARC Energy Trust
---------------------------------------------------------------------------------------------------------------
Three Months ended Six Months Ended
June 30 June 30
Production split (per cent) 2004 2003 2004 2003
---------------------------------------------------------------------------------------------------------------
Crude oil and NGL's 46 49 48 52
Natural gas 54 51 52 48
---------------------------------------------------------------------------------------------------------------
TOTAL PER CENT 100 100 100 100
===============================================================================================================
In May 2004, ARC disposed of its Sundre properties in the Central Alberta area.
The disposed properties accounted for production of approximately 1,800 boe/d
and proved plus probable reserves of 8,800 Mboe. With the acquisition of the
additional interest in the Prestville area, the Trust added approximately 200
boe/d of production.
The following table summarizes the Trust's production by core area for the
second quarter of 2004:
-----------------------------------------------------------------------------------------------------------------
Q2 2004 Total Oil Natural Gas NGL & Condensate
Production by Core Area (1) boe/d bbls/d mcf/d bbls/d
-----------------------------------------------------------------------------------------------------------------
Central AB 9,363 2,044 33,316 1,766
Northern AB & BC 20,436 5,772 78,692 1,549
Pembina 7,646 3,606 19,057 864
Southeast AB & Southwest Sask. 10,673 1,693 53,785 16
Southeast Sask. 10,029 9,605 1,831 118
-----------------------------------------------------------------------------------------------------------------
TOTAL 58,147 22,720 186,681 4,313
=================================================================================================================
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is
Saskatchewan.
The following table summarizes the Trust's year-to-date 2004 production by core
area:
-----------------------------------------------------------------------------------------------------------------
YTD 2004 Total Oil Natural Gas NGL & Condensate
Production by Core Area (1) boe/d bbls/d mcf/d bbls/d
-----------------------------------------------------------------------------------------------------------------
Central AB 9,888 2,313 33,975 1,912
Northern AB & BC 19,425 5,726 73,329 1,478
Pembina 7,331 3,644 17,332 798
Southeast AB & Southwest Sask. 10,797 1,745 54,215 16
Southeast Sask. 10,170 9,763 1,756 114
-----------------------------------------------------------------------------------------------------------------
TOTAL 57,611 23,191 180,607 4,318
-----------------------------------------------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is
Saskatchewan.
The Trust expects production for 2004 to approximate 55,000 boe/d.
COMMODITY PRICES AND HEDGING
-----------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 % June 30 %
Benchmark prices 2004 2003 Change 2004 2003 Change
-----------------------------------------------------------------------------------------------------------------
AECO gas ($/mcf) (1) 6.80 6.99 (3) 6.70 7.47 (10)
WTI oil (U.S.$/bbl) (2) 38.34 28.90 33 36.75 31.34 17
CDN/USD foreign exchange rate 0.74 0.71 4 0.75 0.69 9
WTI oil (CDN$/bbl) 52.12 40.43 29 49.17 45.56 8
-----------------------------------------------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
The Canadian denominated oil price received by ARC and other Canadian energy
companies was negatively impacted by the continued strength of the Canadian
dollar with respect to the U.S. dollar during 2004. Despite the 17 per cent
increase in the year-to-date USD WTI oil price in 2004, the Canadian denominated
oil price increased
ARC Energy Trust 7
by only eight per cent to $49.17 per barrel in 2004 compared to $45.56 per
barrel in 2003. The Trust's realized oil price increased by 30 per cent to
$47.43 per barrel in the second quarter of 2004 compared to $36.61 per barrel in
the second quarter of 2003. The Trust's year-to-date realized oil price
increased by 14 per cent to $43.85 per barrel in 2004 from $38.61 per barrel in
2003.
Alberta AECO Hub prices were $6.80 per mcf and $6.70 per mcf for the second
quarter and first six months of 2004, respectively, decreasing slightly from the
$6.99 per mcf and $7.47 per mcf for the same periods of 2003. ARC's second
quarter gas price decreased by six per cent to $6.99 per mcf and year-to date
gas price decreased by five per cent to $6.83 per mcf compared to the same
periods of 2003.
Prior to hedging activities, XXX realized $44.09 per boe in the second quarter
of 2004, a 15 per cent increase over the $38.30 received prior to hedging in
2003. On a year-to-date basis, the Trust has received $41.86 per boe, down
slightly from the $42.29 per boe received for the same period in 2003. XXX's
reported price of $44.09 per boe in the second quarter of 2004 is not directly
comparable to the $37.77 per boe price reported for the second quarter of 2003
as a result of new hedge accounting guidelines that were implemented in 2004.
Under the new hedge accounting guideline, 2004 revenue and prices are presented
prior to hedging gains or losses while 2003 revenue and prices are inclusive of
realized hedging gains or losses. See "Impact of New Accounting Policies" for
further discussion regarding the impact of Hedge Accounting that was implemented
in 2004.
-----------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 % June 30 %
ARC REALIZED PRICES (1) (2) 2004 2003 Change 2004 2003 Change
-----------------------------------------------------------------------------------------------------------------
Oil ($/bbl) 47.43 36.61 30 43.85 38.61 14
Natural gas ($/mcf) 6.99 6.59 6 6.83 7.21 (5)
NGL's ($/bbl) 38.22 28.83 33 35.26 33.89 4
-----------------------------------------------------------------------------------------------------------------
Total commodity revenue ($/boe) 43.82 37.51 17 41.69 40.47 3
Other revenue ($/boe) 0.27 0.26 4 0.17 0.25 (32)
-----------------------------------------------------------------------------------------------------------------
TOTAL REVENUE ($/BOE) 44.09 37.77 17 41.86 40.72 3
-----------------------------------------------------------------------------------------------------------------
TOTAL REVENUE BEFORE HEDGING ($/BOE) 44.09 38.30 15 41.86 42.29 (1)
-----------------------------------------------------------------------------------------------------------------
(1) 2004 revenue and prices as reported above are prior to hedging gains and
losses on commodity and foreign currency contracts. All gains and losses on
2004 contracts are included in "loss on commodity and foreign currency
contracts" in the statement of income as these contracts have not been
designated as accounting xxxxxx. 2003 reported prices are net of hedging
gains and losses.
(2) 2003 prices have been reclassified to reflect prices prior to
transportation costs.
The Trust has entered into foreign currency hedging contracts to minimize the
impact that fluctuations in the CDN/USD exchange rate have on cash flow. In
addition, the majority of the Trust's debt balance and certain of the Trust's
transactions are denominated in U.S. dollars that partially offset the negative
impact of CDN/USD exchange rate fluctuations.
Reported prices reflect field prices net of quality differentials and prior to
transportation costs. Commencing in 2004, the Trust has reclassified the
presentation of revenue to reflect revenue and prices prior to transportation
charges. Prices reported in 2003 have been reclassified to reflect the same
presentation. See "Impact of New
8 ARC Energy Trust
Accounting Policies" in this MD&A for further discussion of the nature and
impact of the transportation cost presentation.
[GRAPHIC OMITTED]
[BAR CHART -- AVERAGE SELLING PRICE]
RISK MANAGEMENT AND HEDGING ACTIVITIES
The Trust uses a variety of commodity and foreign currency contracts including
fixed price swaps, collared contracts, max payouts and three-way collars to
manage the Trust's exposure to fluctuations in commodity prices, foreign
exchange rates and interest rates. The Trust considers these contracts to be
effective economic xxxxxx.
In response to the current commodity price environment, the Trust has varied its
hedging strategy. Previously, the Trust's hedging portfolio consisted of a large
number of fixed price contracts that mitigated the risk associated with
downturns in commodity prices, however they limited the Trust's upside potential
in rising commodity price environments. The Trust's current strategy is to focus
on "collar" agreements that limit the Trust's exposure to downturns in commodity
prices while allowing more participation in commodity price increases.
The Trust's commodity and foreign currency contract portfolio is undertaken with
financially sound counterparties to reduce the Trust's exposure to credit risk.
The Trust does not enter into contracts directly but facilitates such contracts
through an approved counterparty such as a Chartered Bank. All contracts require
approval of the Trust's Risk Management Committee prior to execution.
Following is a summary of contracts in place for the second quarter of 2004 and
the remainder of the contract period as at June 30, 2004:
----------------------------------------------------------------------------------------------------------------
Q2 2004 Remaining Contract Term (3)
------------------------------------ -----------------------------------
Total Average Total Average
Contract Contract Price Contract Contract Price
Volume(2) CDN$(1) Volume(2) CDN$(1)
----------------------------------------------------------------------------------------------------------------
Oil (mbbls) 1,515 $ 38.46 7,386 $ 41.26
Natural gas (Mmcf) 5,133 6.25 11,289 7.06
----------------------------------------------------------------------------------------------------------------
Total Mboe 2,371 38.11 9,268 41.48
Foreign currency (sell US$) (4) US$35.1 Million 0.74 US$65 Million 0.74
Electricity (MW/h) 10,920 63.00 284,640 63.00
----------------------------------------------------------------------------------------------------------------
Interest rates (5) US$62.5 Million LIBOR+38.25 bps US$62.5 Million LIBOR+38.25 bps
================================================================================================================
(1) Contracts denominated in US$ have been converted to the CDN$ equivalent at
the period end foreign exchange rate. Prices represent average prices as of
June 30, 2004. In the case of collar contracts for oil and natural gas
contracts, the forward prices as at June 30, 2004 were referenced to
determine the relevant contract price for the remaining contract period.
(2) Volumes represent total volume for oil and natural gas and total megawatts
for electricity for the second quarter of 2004.
(3) The amounts presented for the remaining contract period represent contracts
in place for commodity contracts to December 2005, for electricity until
2010 and for interest rates until 2014.
(4) Total contract volume for foreign currency contracts represents the total
US$ sell amount for the respective term.
(5) Average rate on the interest rate swap is based on the three month LIBOR
plus 38.25 basis points.
For the second quarter of 2004, the Trust had contracts in place for
approximately 64 per cent of liquids production and 35 per cent of natural gas
production. For the remainder of 2004, the Trust has contracts in place
ARC Energy Trust 9
for 3,006,000 barrels of oil (16,300 barrels per day), representing 63 per cent
of liquids production, at an average price of $42.36 per barrel. Approximately
33 per cent of natural gas production, 10,435,687 mcf of gas (59,700 mcf per
day), is contracted at an average price of $6.74 per mcf for the remainder of
2004. In the case of collar contracts for oil and natural gas contracts, the
forward prices for the second half of 2004 were referenced to determine the
relevant contract price for the remainder of 2004. Foreign exchange contracts to
sell US$65 million at an average exchange rate of $0.74, and an electricity
contract for 5 MW/h at a fixed price of $63 per MW/h are in place for the
remainder of 2004. 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.
REVENUE
Revenue before hedging increased to $233.3 million in the second quarter of 2004
and to $438.9 for the first six months of 2004, an increase of 18 per cent and
17 per cent, respectively, compared to the same periods in 2003. Higher
production volumes as a result of the Star acquisition in the second quarter of
2003 contributed to higher revenue in the second quarter and first six months of
2004. Revenue in 2003 included hedging losses of $2.8 million ($0.53 per boe) in
the second quarter and $14.4 million ($1.56 per boe) for the first six months of
2003, respectively. Hedging gains and losses in 2004 have been presented as a
separate component of revenue in the statement of income rather than being
netted against sales.
A breakdown of revenue is as follows:
----------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 % June 30 %
REVENUE ($ THOUSANDS)(1)(2) 2004 2003 Change 2004 2003 Change
----------------------------------------------------------------------------------------------------------------
Oil revenue 98,070 80,220 22 185,095 157,796 17
Natural gas revenue 118,815 105,415 13 224,352 191,526 17
NGL's revenue 15,000 11,537 30 27,707 24,840 12
----------------------------------------------------------------------------------------------------------------
Total commodity revenue 231,885 197,172 18 437,154 374,162 17
Other revenue 1,422 1,370 4 1,747 2,297 (24)
----------------------------------------------------------------------------------------------------------------
TOTAL REVENUE (2) 233,307 198,542 18 438,901 376,459 17
----------------------------------------------------------------------------------------------------------------
TOTAL REVENUE BEFORE HEDGING (2) 233,307 201,331 16 438,901 390,902 12
================================================================================================================
(1) 2003 revenue has been reclassified to reflect revenue prior to
transportation costs. Revenue and transportation both increased by $3.5
million and $4.8 million, respectively, in the second quarter and first six
months of 2003 as a result of the reclassification.
(2) Revenue for the second quarter and first six months of 2003 includes cash
hedging losses of $5.9 million and $18.9 million, respectively and non-cash
hedging gains of $3.1 million and $4.5 million, respectively. There are no
hedging gains or losses in the reported 2004 revenue amounts. Gains and
losses on hedging contracts in 2004 have been reported separately in the
statement of income.
GAIN OR LOSS ON COMMODITY AND FOREIGN EXCHANGE CONTRACTS
Gain or loss on commodity and foreign exchange contracts comprises realized and
unrealized gains or losses on commodity and foreign currency contracts that do
not meet the requirements of an effective accounting hedge, even though the
Trust considers all commodity and foreign currency contracts to be effective
economic xxxxxx. Accordingly, gains and losses on such contracts are shown as a
separate expense in the statement of income.
10 ARC Energy Trust
The Trust recorded a loss on commodity and foreign exchange contracts of $26.9
million in the second quarter of 2004 and $61.7 million for the first six months
of 2004. Following is a loss on commodity and foreign exchange contracts in
2004:
-----------------------------------------------------------------------------------------------------------------
COMMODITY AND FOREIGN EXCHANGE CONTRACTS Q2 Q1 YTD
-----------------------------------------------------------------------------------------------------------------
($ thousands except per BOE amounts) 2004 2004 2004
REALIZED CASH GAIN (LOSS) ON CONTRACTS (1) (17,972) (13,556) (31,528)
Per boe (5) (3.40) (2.61) (3.01)
-----------------------------------------------------------------------------------------------------------------
NON-CASH GAIN (LOSS) ON CONTRACTS (2) 1,050 2,414 3,464
Per boe (5) 0.20 0.46 0.33
-----------------------------------------------------------------------------------------------------------------
Non-cash amortization of opening deferred hedge loss (3) (4,328) (7,130) (11,458)
Unrealized gain (loss) on contracts, change in fair value (4) (5,698) (16,475) (22,173)
-----------------------------------------------------------------------------------------------------------------
TOTAL NON-CASH FAIR VALUE GAIN (LOSS) ON CONTRACTS (10,026) (23,605) (33,631)
Per boe (5) (1.08) (4.07) (3.63)
-----------------------------------------------------------------------------------------------------------------
TOTAL GAIN (LOSS) ON COMMODITY AND FOREIGN CURRENCY CONTRACTS (26,948) (34,747) (61,695)
Per boe (5) (5.09) (6.69) (5.88)
=================================================================================================================
(1) The realized cash loss on contracts consisted of a cash loss of $14.6
million ($7.05 per barrel) on oil and a cash loss of $2.9 million ($0.17
per mcf) on gas for the second quarter of 2004 and a year-to-date cash loss
of $29.1 million ($6.88 per barrel) on oil and $3.7 million ($0.11 per mcf)
on gas.
(2) Non-cash gains of $1 million and $3.5 million for the second quarter and
first six months of 2004 represent non-cash amortization of deferred
commodity and foreign currency contracts.
(3) Represents non-cash amortization of the opening deferred hedge loss of
$14.6 million to income over the terms of the contracts in place at January
1, 2004.
(4) The unrealized loss on contracts represents the change in fair value of the
contracts during the period. The fair value of the contracts was a loss of
$14.6 million at January 1, 2004, a loss of $31 million at March 31, 2004
and a loss of $36.8 million at June 30, 2004.
(5) Per boe amounts were based on quarterly production for the realized cash
losses and the non-cash losses. The per boe amount for total fair value
loss on contracts was calculated based on the total hedged volume for the
remainder of the contract term of 9,268,000 boe.
The second quarter $26.9 million loss on commodity and foreign currency
contracts consisted of a realized (cash) loss of $18 million ($3.40 per boe), an
unrealized (non-cash) fair value loss of $10 million ($1.08 per boe over the
remaining contracted volume), and a non-cash gain of $1.1 million ($0.20 per
boe). The year-to-date $61.7 million loss on commodity and foreign currency
contracts consisted of a realized (cash) loss of $31.5 million ($3.01 per boe),
an unrealized (non-cash) fair value loss of $33.6 million ($3.63 per boe over
the remaining contracted volume), and a non-cash gain of $3.5 million ($0.33 per
boe). The unrealized loss on commodity and foreign currency contracts reflects
the change in the fair value of commodity and foreign exchange contracts during
each reporting period. In 2003, there were no unrealized gains or losses on
commodity and foreign currency contracts, as all contracts were deemed to be
effective accounting xxxxxx up to December 31, 2003.
[GRAPHIC OMITTED]
[BAR CHART -- NETBACK]
OPERATING NETBACKS
The Trust's operating netback increased 10 per cent to $24.93 per boe in the
second quarter of 2004 compared to $22.69 per boe in the second quarter of
ARC Energy Trust 11
2003. The increase is due to a higher second quarter realized price. The
year-to-date netback decreased four per cent to $23.86 per boe from $24.93 per
boe in 2003 as a result of the slightly lower year-to-date realized price.
The netbacks incorporate realized losses on commodity and foreign currency
contracts of $3.20 per boe and $2.68 per boe for second quarter and first six
months of 2004, respectively. Fair value losses on commodity and foreign
currency contracts of $10 million and $33.6 million in the second quarter and
first six months of 2004 were not recorded as a reduction of the netback.
The components of operating netbacks are shown below:
-------------------------------------------------------------------------------------------------------------------
Q2 2004 Q2 2003
Oil Gas NGL TOTAL Total
NETBACK ($/bbl) ($/mcf) ($/boe) ($/BOE) ($/boe)
-------------------------------------------------------------------------------------------------------------------
Market price (1) 47.43 6.99 38.22 43.82 38.04
Realized loss on commodity and
foreign currency contracts (2) (7.30) (0.11) -- (3.20) (0.53)
-------------------------------------------------------------------------------------------------------------------
Selling price 40.13 6.88 38.22 40.62 37.51
Other revenue -- -- -- 0.27 0.26
-------------------------------------------------------------------------------------------------------------------
Total revenue 40.13 6.88 38.22 40.89 37.77
Royalties (7.73) (1.51) (10.35) (8.64) (7.86)
Transportation (1) (0.30) (0.18) -- (0.68) (0.65)
Operating costs (4) (8.31) (0.90) (6.97) (6.64) (6.57)
-------------------------------------------------------------------------------------------------------------------
Netback 23.79 4.29 20.90 24.93 22.69
===================================================================================================================
Commodity revenue subject to royalties (3) 47.13 6.81 38.22 43.14 37.38
Royalties as a percentage of revenue (per cent) 16.4 22.2 27.1 20.0 21.0
===================================================================================================================
-------------------------------------------------------------------------------------------------------------------
YTD 2004 YTD 2003
Oil Gas NGL TOTAL Total
NETBACK ($/bbl) ($/mcf) ($/boe) ($/BOE) ($/boe)
-------------------------------------------------------------------------------------------------------------------
Market price (1) 43.85 6.83 35.26 41.69 42.03
Realized loss on commodity and
foreign currency contracts (2) (6.26) (0.05) -- (2.68) (1.56)
-------------------------------------------------------------------------------------------------------------------
Selling price 37.59 6.78 35.26 39.01 40.47
Other revenue -- -- -- 0.17 0.25
-------------------------------------------------------------------------------------------------------------------
Total revenue 37.59 6.78 35.26 39.18 40.72
Royalties (7.61) (1.36) (9.68) (8.06) (8.41)
Transportation (1) (0.26) (0.19) -- (0.71) (0.51)
Operating costs (4) (7.88) (0.93) (6.39) (6.55) (6.87)
-------------------------------------------------------------------------------------------------------------------
Netback 21.84 4.30 19.19 23.86 24.93
===================================================================================================================
Commodity revenue subject to royalties (3) 43.59 6.64 35.26 40.98 41.52
Royalties as a percentage of revenue (per cent) 17.5 20.5 27.5 19.7 20.3
===================================================================================================================
(1) 2003 revenue and transportation costs have been reclassified to reflect
revenue prior to transportation costs. Previously, revenue was presented
net of transportation costs. This reclassification did not impact the
netback.
(2) Excludes fair value losses of $10 million and $33.6 million in the second
quarter and first six months of 2004 on commodity and foreign currency
contracts.
(3) Based on commodity field price before hedging and net of transportation
costs.
(4) Operating expenses are composed of direct costs incurred to operate both
oil and gas xxxxx. A number of assumptions have been made in allocating
these costs between oil, natural gas and natural gas liquids production.
12 ARC Energy Trust
Royalties increased to $8.64 per boe in the second quarter of 2004 compared to
$7.86 per boe in the second quarter of 2003. Year-to-date royalties decreased
slightly to $8.06 per boe from $8.41 per boe in 2003. 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 decreased slightly to
20 per cent for the second quarter of 2004 compared to 21 per cent for the same
period in 2003. The year-to-date royalty rate decreased slightly to 19.7 per
cent for the first six months of 2004 compared to 20.3 per cent in 2003.
Operating costs, net of processing income, increased in total to $35.2 million
in the second quarter of 2004 from $34.6 million for the same period in 2003.
The two per cent increase in the dollar amount of operating costs was associated
with higher production in the second quarter of 2004. Second quarter operating
costs per boe remained relatively consistent at $6.64 per boe in 2004 compared
to $6.57 per boe in the second quarter of 2003. Year-to-date operating costs
increased to $68.7 million in the first six months of 2004 from $63.5 million in
the first six months of 2003 due to increased production. Year-to-date operating
costs per boe decreased five per cent to $6.55 per boe in 2004 from $6.87 per
boe in 2003. The decrease in per boe operating costs for the first half of 2004
relative to 2003 was due to the divestment of higher cost properties in the
third quarter of 2003 and an increase in natural gas weighting of the Trust's
production following the Star acquisition. In addition, cost adjustments on
ARC's non-operated properties for pre-2003 production periods negatively
impacted the Trust's operating costs in the first half of 2003.
Due to the cyclical nature of operating costs, the Trust expects operating costs
to increase in the third quarter of 2004 as a result of increased well service
and work-over activity. ARC continues to closely manage and monitor costs on
operated and non-operated properties to maximize the cost-effectiveness of the
Trust's operations while maintaining field safety as its number one priority.
ARC expects 2004 operating costs to average approximately $7.00 per boe for
remainder of 2004.
Effective for 2004, ARC's transportation costs have been presented as an expense
in the statement of income whereas previously they were recorded as a reduction
of revenue. For comparative purposes, 2003 amounts have been reclassified.
Transportation costs as presented in the statement of income are defined by the
point of legal transfer of the product. Transportation costs are dependent upon
where the product is sold, product split, location of properties, and industry
transportation rates that are driven by supply and demand of available transport
capacity. For gas production, legal title transfers at the intersection of major
pipelines (referred to as "the Hub") whereas the majority of ARC's oil
production is sold at the wellhead. Consequently, there are higher
transportation costs incurred with gas production due to the distance from the
wellhead to the Hub.
Transportation costs remained relatively consistent at $0.68 per boe in the
second quarter of 2004 compared to $0.65 per boe in the second quarter of 2003.
Year-to-date transportation costs increased to $0.71 per boe in the first half
of 2004 from $0.51 per boe in the first half of 2003. The increase in ARC's
year-to-date transportation
ARC Energy Trust 13
costs per boe is due to a higher proportion of natural gas production and a
higher volume of gas being transported for sale at Hubs in eastern Canada and
the United States. Natural gas sold at these points incurs higher transportation
costs but typically yields a higher sales price.
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 $5.4 million ($1.02 per boe) from $4.8 million
($0.92 per boe) in the second quarter of 2003. Year-to-date cash G&A expenses
increased to $10.3 million ($0.98 per boe) in the first six months of 2004 from
$8.8 million ($0.95) in 2003. Increases in cash G&A expenses in total and per
boe were the result of the Star acquisition and increasing costs to manage the
business.
A non-cash trust unit incentive compensation expense ("non-cash compensation
expense") of $0.6 million ($0.11 per boe) was recorded in the second quarter of
2004 compared to $0.2 million ($0.03 per boe) in the second quarter of 2003. The
total non-cash compensation expense recorded for the first six months of 2004
was $3.4 million ($0.33 per boe) compared to $0.2 million ($0.02 per boe) for
the first six months of 2003. This non-cash amount relates to the value
attributed to rights and trust units granted to officers, directors, employees
and contract employees under the Trust Unit Incentive Rights Plan ("Rights
Plan"). The $0.6 million second quarter non-cash expense for the Rights Plan and
$4.1 million year-to-date non-cash expense was determined based on the rights
outstanding that were subject to valuation and the market price of the trust
units. Only the rights that were issued on or after January 1, 2003 are subject
to valuation and expense in the statement of income. The expense associated with
the Rights Plan was significantly lower in the second quarter of 2004 relative
to the first quarter as the trust unit price increased significantly in the
first quarter but remained relatively stable throughout the second quarter. An
expense of $0.2 million was recorded in the second quarter and first six months
of 2003 for the value of rights in that period.
The Trust implemented a new Whole Trust Unit Incentive Plan ("Whole Unit Plan")
that will result in future cash payments to Employees and Officers of the Trust.
The $0.7 million non-cash expense attributed to the new Whole Unit Plan is based
on 314,625 committed trust units under the Whole Unit Plan as at June 30, 2004.
The value of this plan is based on the market price of the underlying trust
units in addition to accumulated distributions that are accrued as part of the
expense amount. The $0.7 million expense recorded in the second quarter consists
of a short-term portion of $0.3 million and a long-term portion of $0.4 million.
Under the new Whole Unit Plan, a non-cash expense will be recorded each period
in the statement of income. A realization of the expense and a resulting
reduction in cash flow will occur each year when a cash payment is made upon
vesting. Vesting under the current plan will occur in the second quarter of each
year. The Whole Unit Plan expense does not impact cash flow until a cash payment
is made.
14 ARC Energy Trust
Following is a breakdown of G&A and trust unit incentive compensation expense:
-----------------------------------------------------------------------------------------------------------------
G&A AND TRUST UNIT INCENTIVE Three Months Ended Six Months Ended
COMPENSATION EXPENSE June 30 % June 30 %
($ THOUSANDS EXCEPT PER BOE) 2004 2003 Change 2004 2003 Change
-----------------------------------------------------------------------------------------------------------------
G&A expenses 7,762 6,306 23 15,162 11,804 28
Operating recoveries (2,356) (1,497) 57 (4,878) (2,986) 63
-----------------------------------------------------------------------------------------------------------------
Cash G&A expenses 5,406 4,809 12 10,284 8,818 17
Non-cash compensation - Rights Plan 565 147 284 3,410 147 2220
Accrued cash compensation - Whole Unit Plan 645 -- -- 645 -- --
-----------------------------------------------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 6,616 4,956 33 14,339 8,965 60
-----------------------------------------------------------------------------------------------------------------
Cash G&A expenses per boe 1.02 0.92 11 0.98 0.95 3
Total G&A and trust unit incentive
compensation expense per boe 1.25 0.94 33 1.37 0.97 41
=================================================================================================================
The Trust expects 2004 G&A costs, excluding non-cash G&A associated with the
Trust's Rights Plan and Whole Unit Plan, to increase slightly to approximately
$1.05 - $1.10 per boe. In addition, the Trust expects non-cash G&A of
approximately $0.25 - $0.35 per boe for the non-cash trust unit incentive
compensation expense associated with the Rights Plan and Whole Unit Plan.
INTEREST EXPENSE
Interest expense decreased to $4.8 million in the second quarter of 2004 from
$6.1 million in the second quarter of 2003. The decrease in the second quarter
and year-to-date interest expense is attributed to a lower average debt balance
in 2004 compared to 2003. Included in the second quarter interest expense are
fees incurred upon issuance of the US$125 million notes and the cost of
increasing the Trust's banking group from five lenders to eight lenders. On
April 27, with the issuance of US$125 million of notes, the Trust repaid all
prime-based Canadian denominated debt. As at June 30, 2004 the Trust's debt
balance was entirely U.S. denominated fixed rate debt with an average rate of
5.5 per cent (4.3 per cent including the current impact of the interest rate
swap contracts) and an average life of 6.8 years.
With the issuance of the fixed rate notes and repayment of variable rate debt,
the Trust's effective interest rate increased slightly. The Trust anticipates
that interest rates will increase in the future, therefore, by fixing the
interest rate on long-term debt, the Trust has implemented a natural hedge for
future cash flow and cash distributions against the impact of rising interest
rates in the longer-term.
In order to capitalize on low short-term interest rates, the Trust entered into
interest rate swap agreements to convert US$62.5 million of fixed rate debt into
floating rate debt at a rate equal to the three month LIBOR rate plus 38.25
basis points through to 2014. Including the interest rate swap, the Trust's
effective interest rate on all debt balances currently approximates 4.3 per cent
(5.5 per cent excluding the interest rate swap contracts). The Trust realized a
cash gain of $0.5 million on the interest rate swap in the second quarter of
2004 and this amount has been netted against interest expense in the statement
of income. The average rate on the interest rate swap in the second quarter
approximated 1.6 per cent.
ARC Energy Trust 15
-----------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 % June 30 %
Interest Expense ($ thousands) 2004 2003 Change 2004 2003 Change
-----------------------------------------------------------------------------------------------------------------------
Period end debt balance (1) 254,676 437,881 (58) 254,676 437,881 (58)
Fixed rate debt 254,676 132,028 92 254,676 132,028 92
Floating rate debt -- 305,853 -- -- 305,853 --
-----------------------------------------------------------------------------------------------------------------------
Interest expense before interest rate swaps (3) 5,246 6,120 (14) 7,864 9,945 (21)
Gain on interest rate hedge (473) -- -- (473) -- --
-----------------------------------------------------------------------------------------------------------------------
Net interest expense (2) 4,773 6,120 (22) 7,391 9,945 (26)
=======================================================================================================================
(1) Includes both long-term and current portions of debt. 2003 debt balances
exclude the convertible debentures.
(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.
(3) 2003 interest expense excludes interest on convertible debentures.
FOREIGN EXCHANGE GAINS AND LOSSES
For the second quarter of 2004, the Trust recorded a loss of $4.4 million ($0.82
per boe) on foreign exchange transactions compared to a gain of $7.4 million
($1.41 per boe) in the second quarter of 2003. On a year-to-date basis, the
Trust recorded a loss of $5.1 million ($0.48 per boe) on foreign exchange
transactions in 2004 compared to a gain of $14.9 million ($1.61 per boe) in
2003. These amounts include both realized and unrealized foreign exchange gains
and losses. Unrealized foreign exchange gains and losses are due to revaluation
of U.S. 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. Due to the relative stability of the Canadian
dollar in the first six months of 2004 relative to 2003, the unrealized foreign
exchange gain was $1.8 million in the first six months of 2004 compared to a
gain of $15.1 million in the first six months of 2003. 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 U.S. denominated
transactions such as interest payments, debt repayments, hedging settlements,
revenue receipts and unitholder payments. During the second quarter, the Trust
recorded a realized foreign exchange loss of $5.9 million upon repayment of
US$105 million of debt. Due to the weakening of the Canadian dollar between the
issuance and repayment dates of the debt, the Canadian dollar equivalent value
of the debt increased by $5.9 million from the date of issuance to repayment.
Following is a breakdown of the total foreign exchange gain (loss):
--------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
Foreign exchange gain (loss) June 30 June 30
($ thousands except per boe) 2004 2003 2004 2003
--------------------------------------------------------------------------------------------------------------------
Unrealized gain (loss) on U.S. denominated debt (806) 7,700 (1,749) 15,102
Realized (loss) on U.S. debt repayment (5,858) -- (5,858) --
REALIZED GAIN (LOSS) ON U.S. DENOMINATED TRANSACTIONS 2,312 (277) 2,555 (184)
TOTAL FOREIGN EXCHANGE GAIN (LOSS) (4,352) 7,423 (5,052) 14,918
--------------------------------------------------------------------------------------------------------------------
TOTAL FOREIGN EXCHANGE GAIN (LOSS) PER BOE (0.82) 1.41 (0.48) 1.61
====================================================================================================================
16 ARC Energy Trust
TAXES
Capital taxes paid or payable by ARC, based on debt and equity levels at the end
of the year, amounted to $0.7 million in the second quarter of 2004 compared to
$0.3 million in the second quarter of 2003. Year-to-date capital taxes were $1.4
million for the first six months of 2004 compared to $0.4 million in 2003. The
increase in 2004 capital taxes was attributed to the higher taxable capital base
as a result of the Star acquisition as well as a lower installment base for the
first quarter of 2003 due to prior year excess installments having been made.
In the second quarter of 2004, a future income tax recovery of $5.5 million was
included in income compared to a $71.2 million recovery in the second quarter of
2003. A year-to-date tax recovery of $21.2 million was recorded for the first
six months of 2004 compared to a recovery of $67.9 million in 2003. The lower
future income tax recoveries in the second quarter and first six months of 2004
relative to 2003 are due to a recovery of $65 million being recorded in the
second quarter of 2003 as a result of reductions in future income tax rates that
were effective in 2003. The year-to-date 2004 future income tax recovery of
$21.2 million includes a recovery of $3.2 million due to the change in Alberta
corporate income tax rates and recovery of $11.7 million due to the net
derivative liability recorded on the balance sheet at June 30, 2004 pursuant to
hedge accounting.
Upon acquisition of United Prestville on June 8, 2004, the Trust recorded a
future income tax liability of $7.3 million due to difference between the tax
basis and the fair value assigned to the acquired assets.
In the first quarter of 2004, the Alberta government passed legislation to
reduce provincial corporate income tax rates to 11.5 per cent from 12.5 per cent
effective April 1, 2004. ARC's expected future income tax rate incorporating
this rate reduction is approximately 35 per cent compared to the current rate of
approximately 39 per cent applicable to the 2004 tax year.
In the Trust's structure, payments are made between ARC Resources 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 ARC
Resources.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION
The depletion, depreciation and accretion ("DD&A") rate increased to $11.29 per
boe in the second quarter of 2004 from $11.09 per boe in the second quarter of
2003. On a year-to-date basis the DD&A rate increased to $11.29 per boe in 2004
from $10.79 per boe in 2003. The year-to-date DD&A rate further increased
compared to 2003 as a result of the Star acquisition in April 2003, in which the
depletable base increased in total by approximately $882 million. The increase
in the depletable base on the Star acquisition was attributed to an increase in
the PP&E balance of $794 million for the fair value of the acquired assets and
an increase of $88 million for the incremental future development costs net of
undeveloped land value and salvage values of the acquired assets.
ARC Energy Trust 17
A breakdown of the DD&A rate is a follows:
-------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
DD&A RATE June 30 % June 30 %
($ THOUSANDS EXCEPT PER BOE AMOUNTS) 2004 2003 Change 2004 2003 Change
-------------------------------------------------------------------------------------------------------------------
Depletion of oil & gas assets (1) 58,552 57,503 1 115,998 98,424 18
Accretion of asset retirement obligation (2) 1,167 782 49 2,333 1,345 73
-------------------------------------------------------------------------------------------------------------------
Total DD&A 59,719 58,285 3 118,331 99,769 19
DD&A Rate per boe 11.29 11.09 2 11.29 10.79 5
===================================================================================================================
(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 period.
The costs subject to depletion include $37.7 million relating to the capitalized
portion of the asset retirement obligation in the second quarter of 2004. The
retroactive application of the new accounting policy for asset retirement
obligations in 2003 required restatement of prior periods. The second quarter
and year-to-date 2003 DD&A rates decreased to $11.09 per boe and $10.79 per boe,
respectively, from the previously reported DD&A rates of $11.42 per boe and
$11.11 per boe as a result of the retroactive application.
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 acquired in each transaction.
Accounting standards require that the goodwill balance be assessed for
impairment at least annually and if such an impairment exists that it be charged
to income in the period in which the impairment occurs. The Trust has determined
that there was no goodwill impairment as of June 30, 2004.
CAPITAL EXPENDITURES AND NET ACQUISITIONS
Total capital expenditures, excluding net property and corporate acquisitions,
aggregated to $34.1 million in the second quarter of 2004 and $90.7 million for
the first six months of 2004 compared to $30.6 million and $53.1 million for the
same periods of 2003. 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 year-to-date 2004 capital
expenditures relative to 2003 is due to a larger capital program in 2004 to
capture value from increased development opportunities as a result of the Star
acquisition. The increased 2004 capital program was also influenced by strong
commodity prices that enhance the economic benefit of such development projects.
The Trust's 2004 capital program was increased to approximately $200 million
following approval by the Board of Directors in August 2004. The $200 million
capital budget, which is the highest in the Trust's history, is a result of both
additional development opportunities and increasing costs for drilling and other
industry services.
18 ARC Energy Trust
In addition to the capital expenditures, the Trust acquired properties for
consideration of $2.5 million and divested properties for consideration of $54.2
million in the second quarter, net of post closing adjustments. The Trust also
acquired a private company, United Prestville Ltd. in June 2004 for total
consideration of $30.6 million. The acquisition of United Prestville Ltd. was
undertaken to increase the Trust's ownership interest in a key property in
northern Alberta.
A breakdown of capital expenditures and net acquisitions is shown below:
-------------------------------------------------------------------------------------------------------------------
Three Months ended Six Months Ended
June 30 June 30
Capital expenditures ($ thousands) 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------
Geological and geophysical 1,373 656 3,693 1,654
Drilling and completions 24,867 23,834 62,808 40,871
Plant and facilities 7,282 4,831 23,238 9,035
Other capital 605 1,325 947 1,549
-------------------------------------------------------------------------------------------------------------------
Total capital expenditures 34,127 30,646 90,686 53,109
-------------------------------------------------------------------------------------------------------------------
Producing property acquisitions (1) 830 2,616 2,509 5,555
Producing property dispositions (1) (54,242) (82,366) (54,347) (82,305)
Corporate acquisition (1) (2) 30,560 721,332 30,560 721,332
-------------------------------------------------------------------------------------------------------------------
Total capital expenditures and net acquisitions 11,275 672,228 69,408 697,691
-------------------------------------------------------------------------------------------------------------------
Total capital expenditures financed with cash flow 34,127 53,109 59,252 53,109
Total capital expenditures financed with debt & equity (22,852) 619,119 10,156 644,582
===================================================================================================================
(1) Value is net of post-closing adjustments.
(2) Represents total consideration for the transaction including fees and prior
to the related future income tax liability assumed on acquisition.
XXX expects to undertake significant development projects in the third and
fourth quarters of 2004 to fully execute the 2004 capital program of $200
million. The Trust intends to withhold approximately 20 per cent of 2004 cash
flow to fund the 2004 capital expenditure program with the remainder to be
funded with debt.
ASSET RETIREMENT OBLIGATION AND RECLAMATION FUND
At June 30, 2004, the Trust had recorded an asset retirement obligation of $64.2
million for future abandonment and reclamation of the Trust's properties. The
asset retirement obligation decreased in total by $3.4 million as a result of
the divestment of properties in May 2004, offset by the acquisition of United
Prestville, and additional liability associated with new xxxxx drilled in the
first six months of 2004. The asset retirement obligation further increased by
$2.3 million for accretion expense and was reduced by $1.3 million for actual
abandonment expenditures in the first six months of 2004. The Trust did not
record a gain or loss on actual abandonment expenditures incurred in the first
quarter of 2004 as the costs incurred closely approximated the liability value
included in the asset retirement obligation.
Previously reported amounts for the periods ended June 30, 2003 have been
restated for the impact of the change in accounting policy for asset retirement
obligation that was implemented in 2003 and required retroactive application
with restatement of prior periods.
ARC Energy Trust 19
XXX contributed $1.5 million cash to its reclamation fund ($1.5 million in the
second quarter of 2003) and earned $0.3 million of interest income during the
second quarter of 2004 ($0.2 million in the second quarter of 2003). For the
first six months of 2004, $3 million ($2.5 million in 2003) was contributed to
the reclamation fund in addition to $0.5 million ($0.3 million in 2003) of
interest earned on the fund to arrive at a fund balance of $19.4 million at June
30, 2004. The fund balance was reduced for funding of actual abandonment
expenditures incurred in the period. 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 ($1.5 million per quarter) in order to provide for the total estimated
future abandonment and reclamation costs.
CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY
A breakdown of the Trust's capital structure is as follows:
-----------------------------------------------------------------------------------------------------------------------
JUNE 30, March 31, December 31,
($ thousands except per unit and per cent amounts) 2004 2004 2003
-----------------------------------------------------------------------------------------------------------------------
Long-term debt 245,293 236,622 223,355
Short-term debt 9,383 9,174 9,047
Working capital deficit (surplus) excluding short-term debt (2) (34,602) 38,205 29,669
-----------------------------------------------------------------------------------------------------------------------
Net debt obligations 220,074 284,001 262,071
Units outstanding and issuable for
exchangeable shares (thousands) 187,296 183,980 182,777
Market price at end of period 15.35 $15.64 $14.74
Market value of trust units and exchangeable shares 2,874,994 2,877,447 2,694,133
Total capitalization (1) 3,095,068 3,161,448 2,956,204
-----------------------------------------------------------------------------------------------------------------------
Net debt as a percentage of total capitalization 7% 9% 9%
-----------------------------------------------------------------------------------------------------------------------
Net debt obligations 220,074 284,001 262,071
-----------------------------------------------------------------------------------------------------------------------
Cash flow 122,249 108,014 396,180
-----------------------------------------------------------------------------------------------------------------------
Net debt to annualized cash flow 0.5 0.7 0.7
=======================================================================================================================
(1) 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.
(2) The 2004 working capital deficit excludes the balances for deferred hedge
loss, commodity and foreign currency contracts, and deferred commodity and
foreign currency contracts as at March 31, 2004 and June 30, 2004.
On April 27, 2004, the Trust completed the issuance of US$125 million of
long-term secured notes ("US Notes") via a private placement. The notes were
issued in two tranches of US$62.5 million each. The first tranche of US$62.5
million has a final life of 10 years (average life of 7.5 years) and pays a
semi-annual coupon of 4.62 per cent per annum. The second tranche of US$62.5
million has a final life of 12 years (average life of 10 years) and pays a
semi-annual coupon of 5.10 per cent per annum. Repayments of the notes will
occur in years 2009 through 2016.
The Trust consolidated its five credit facilities into one syndicated credit
facility in the second quarter of 2004. The syndication of the credit facilities
did not impact the Trust's borrowing base nor did it impact other key terms of
the credit facility such as security or covenants. Borrowing rates under the
syndicated facility decreased slightly. ARC Resources' oil and gas properties
continue to secure the debt. The Trust recently completed its annual credit
review with its lenders that resulted in the Trust's credit lines remaining
unchanged at $620 million until the next annual credit review in April 2005.
20 ARC Energy Trust
Total debt outstanding, inclusive of short and long-term debt, at June 30, 2004
was $254.7 million, which is entirely U.S. denominated fixed rate debt. The debt
consists of US$65 million (CDN$87.1 million) of Senior Secured Notes ("Notes")
with an average interest rate of 6.6 per cent and an average remaining life of
three years and US$125 million (CDN$167.6 million) of US Notes with an average
interest rate of 4.86 per cent and an average remaining life of nine years. The
current portion of long-term debt represents the first US$7 million (CDN$9.4
million) payment due in November 2004 on the Notes which will be financed with
available working capital or by a draw on the existing credit facilities.
[GRAPHIC OMITTED]
[BAR CHART -- CASH FLOW]
Concurrent with the issuance of the US Notes, the Trust entered into interest
rate swap transactions to effectively convert the fixed interest rate on US$62.5
million of the US Notes into a floating rate, based on the three month LIBOR
rate plus 38.25 basis points, in order to capitalize on historic low interest
rates in the United States. As a result, the Trust effectively issued US$125
million notes at an average rate of 3.3 per cent, with this rate increasing by
one half of a percentage point for every one percentage point increase in
short-term U.S. interest rates.
As at June 30, 2004, the Trust had a working capital deficiency excluding
short-term debt, of $0.5 million compared to a deficit of $64.3 million at March
31, 2004 and a deficit of $29.7 million as at December 31, 2003. The Trust's
working capital deficiency significantly decreased at June 30, 2004 due to the
issuance of the US$125 million notes and the divestment of properties in the
second quarter of 2004. The Trust invested its surplus cash balance, relating
primarily to proceeds received from the May property divestment, in short-term
money market investments at June 30, 2004. The Trust recorded a net current
liability of $35.1 million at June 30, 2004 and $26 million at March 31, 2004
for the fair value of commodity and foreign currency contracts under new hedge
accounting guidelines implemented in 2004. Excluding the Trust's net current
liability for commodity and foreign currency contracts and short-term debt, the
Trust had a working capital surplus of $34.6 million at June 30, 2004 and a
deficit of $38.2 million at March 31, 2004.
June 30, 2004 net debt to total capitalization was seven per cent and net debt
to annualized second quarter 2004 cash flow approximated 0.5 times.
The Trust intends to finance the remainder of the 2004 capital program with a
combination of cash flow and debt.
ARC Energy Trust 21
UNITHOLDERS' EQUITY
At June 30, 2004, there were 187.3 million trust units issued and issuable for
exchangeable shares, a three per cent increase from the 182.8 million trust
units issued and issuable for exchangeable shares at December 31, 2003. The
increase in the number of trust units outstanding is attributable to 2,032,358
trust units issued as consideration for the acquisition of United Prestville,
1,035,106 trust units issued pursuant to the Distribution Reinvestment Incentive
Plan ("DRIP") at an average price of $14.13 per trust unit, 1,269,517 trust
units issued pursuant to the exercise of employee rights at an average price of
$10.42 per trust unit, and the conversion of exchangeable shares that resulted
in the issuance of 130,036 trust units.
The Trust issued 27,000 additional rights under the Rights Plan during the first
quarter of 2004. There were no additional rights issuances in the second quarter
and there will be no issuances of rights in the future as the rights plan has
been replaced with a new Whole Unit Plan in the second quarter of 2004. The
existing rights plan will be in place until the remaining 3.5 million rights
outstanding as of June 30, 2004 are exercised or cancelled. The exercise price
of the rights is adjusted downward over time by the amount, if any, that annual
distributions exceed 10 per cent of the net book value of property, plant and
equipment. The rights have a five-year term and vest equally over three years
from the date of grant. Rights to purchase 3.5 million trust units at an average
adjusted exercise price of $11.24 were outstanding at June 30, 2004. These
rights have an average remaining contractual life of 3.5 years and expire at
various dates to March 22, 2009. Of the rights outstanding at June 30, 2004, a
total of 1.1 million were exercisable at that time.
In March 2004, the Board of Directors upon recommendation of the Compensation
Committee, approved a new Whole Unit Plan to replace the existing Rights Plan
for new awards granted subsequent to the first quarter of 2004. The new Whole
Unit Plan will result in employees receiving cash compensation in relation to
the value of a specified number of underlying trust units. The Whole Unit Plan
consists of Restricted Trust Units ("RTU's") for which the number of trust units
is fixed and that will vest over a period of three years and Performance Trust
Units ("PTU's") for which the number of trust units is variable and will vest at
the end of three years. The Trust issued 188,602 RTU's and 127,123 PTU's upon
inception of the plan to employees and officers, of which 1,100 RTU's were
subsequently forfeited by the end of the second quarter. Upon vesting, the
employee is entitled to receive a cash payment based on the fair value of the
underlying trust units plus accrued distributions on the underlying trust units
to vesting date. The cash compensation issued upon vesting of the PTU's is
dependent upon the future performance of the Trust compared to its peers based
on certain key industry benchmarks. The value associated with the RTU's and
PTU's will be expensed in the statement of income over the vesting period. As
the value of the RTU's and PTU's is dependent upon the trust unit price, the
number of PTU's to be issued on vesting, and distributions, therefore the
expense recorded in the statement of income may fluctuate over time. The Trust
has made provisions whereby employees may elect to have trust units purchased
for them on the market with the cash received upon vesting.
Unitholders electing to reinvest distributions or make optional cash payments to
acquire trust units from treasury under the DRIP may do so at a five per cent
discount to the prevailing market price with no additional fees or commissions.
22 ARC Energy Trust
CASH DISTRIBUTIONS
ARC declared cash distributions of $82.1 million ($0.45 per unit), representing
67 per cent of second quarter 2004 cash flow compared to cash distributions of
$67.5 million ($0.45 per unit) in the second quarter of 2003. The remaining 33
per cent of second quarter cash flow ($40.1 million) was used to fund 100 per
cent of ARC's second quarter capital expenditures ($34.1 million), make
contributions, including interest, to the reclamation fund ($1.8 million), and
pay down existing indebtedness with the remaining $4.2 million. Year-to-date,
the Trust has made distributions of $163.3 million, representing 71 per cent of
2004 cash flow. In addition, the Trust has funded $59.3 million of the current
year capital expenditures, contributed $3.5 million, including interest, to the
reclamation fund, and paid down $4.2 million of existing indebtedness with cash
from operations. 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. This holdback policy differs
among the conventional oil and gas trusts.
Cash flow and cash distributions per unit for 2004 and 2003 were as follows:
---------------------------------------------------------------------------------------------------------------
Three Months ended Six Months Ended
2004 June 30, 2004 June 30, 2004
Cash flow and distributions $ millions per unit $ millions per unit
---------------------------------------------------------------------------------------------------------------
Cash flow $ 122.2 $ 0.66 $ 230.3 $ 1.25
Reclamation fund contributions, including interest (1.8) (0.01) (3.5) (0.02)
Capital expenditures funded with cash flow (34.1) (0.18) (59.3) (0.32)
Discretionary debt repayments (4.2) (0.02) (4.2) (0.02)
---------------------------------------------------------------------------------------------------------------
Other -- -- -- 0.01
Cash distributions $ 82.1 $ 0.45 $ 163.3 $ 0.90
===============================================================================================================
---------------------------------------------------------------------------------------------------------------
Three Months ended Six Months Ended
2003 June 30, 2003 June 30, 2003
Cash flow and distributions $ millions per unit $ millions per unit
---------------------------------------------------------------------------------------------------------------
Cash flow $ 116.6 $ 0.80 $ 219.1 $ 1.58
Reclamation fund contributions, including interest (1.7) (0.01) (2.8) (0.02)
Capital expenditures funded with cash flow (32.9) (0.23) (53.1) (0.38)
Interest on convertible debentures (3.9) (0.03) (3.9) (0.03)
---------------------------------------------------------------------------------------------------------------
Discretionary debt repayments (10.6) (0.08) (32.5) (0.25)
Cash distributions $ 67.5 $ 0.45 $ 126.8 $ 0.90
===============================================================================================================
Monthly cash distributions for the third quarter of 2004 have been set at $0.15
per trust 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. The Trust expects to fund 2004 distributions from cash flow.
ARC Energy Trust 23
CASH DISTRIBUTIONS BY CALENDAR YEAR
The following table presents cash distributions paid in each calendar period.
Cash distributions for 2004 include distributions paid up to and including July
15, 2004:
-----------------------------------------------------------------------------------------------------------------
CALENDAR YEAR DISTRIBUTIONS (1) TAXABLE PORTION RETURN OF CAPITAL
-----------------------------------------------------------------------------------------------------------------
YTD 2004 (2) 1.05 0.95(3) 0.10(3)
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 $13.34 $6.70 $6.64
=================================================================================================================
(1) Based on cash distributions paid in the calendar year.
(2) Based on cash distributions paid in 2004 up to and including July 15, 2004.
(3) Based on estimated taxable portion of 2004 distributions of 90 per cent.
CASH DISTRIBUTION DATES FOR 2004
Actual and estimated cash distributions paid and announced to date for 2004
along with relevant payment dates are as follows:
-----------------------------------------------------------------------------------------------------------------
Distribution Total
Ex-Distribution Date Record Date Payment Date Distribution
-----------------------------------------------------------------------------------------------------------------
December 29, 2003 December 31, 2003 January 15, 2004 0.15
January 28, 2004 January 31, 2004 February 16, 2004 0.15
February 25, 2004 February 29, 2004 March 15, 2004 0.15
March 29, 2004 March 31, 2004 April 15, 2004 0.15
April 28, 2004 April 30, 2004 May 17, 2004 0.15
May 27, 2004 May 31, 2004 June 15, 2004 0.15
June 28, 2004 June 30, 2004 July 15, 2004 0.15
July 28, 2004 July 31, 2004 August 16, 2004 0.15
August 27, 2004 August 31, 2004 September 15, 2004 0.15*
September 28, 2004 September 30, 2004 October 15, 2004 0.15*
October 27, 2004 October 31, 2004 November 15, 2004
November 26, 2004 November 30, 2004 December 15, 2004
=================================================================================================================
* Estimated
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 trust units held. For a more detailed breakdown, please visit
our website at xxx.xxxxxxxxxxxx.xxx.
For 2004, ARC estimates that cash distributions paid in the calendar year will
be 90 per cent return on capital (taxable) and 10 per cent return of capital
(tax deferred). The increase in the taxable portion of distributions to 90 per
cent is the result of increasing commodity prices and in turn increasing cash
flow of the Trust. Actual taxable amounts may differ from the estimated amount
as they are dependent on commodity prices experienced throughout the year.
Changes in the estimated taxable and deferred portion of the distributions will
be announced quarterly.
24 ARC Energy Trust
The exchangeable shares of ARC Resources Ltd. ("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 trust 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 trust unit distribution
multiplied by the then current exchange ratio and divided by the 10 day weighted
average trading price of the trust 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 trust unit.
[GRAPHIC OMITTED]
[BAR CHART -- MONTHLY CASH DISTRIBUTIONS]
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 and sales commitments. These obligations are of a recurring and
consistent nature and impact cash flow in an ongoing manner.
Following is a summary of the Trust's contractual obligations and commitments:
-------------------------------------------------------------------------------------------------------------------
Payments Due By Period
2009 and
($ millions) Total 2004 2005-2006 2007-2008 thereafter
-------------------------------------------------------------------------------------------------------------------
Debt repayments (1) 254.7 9.4 26.8 34.9 183.6
Operating leases 24.8 3.2 8.9 7.5 5.2
-------------------------------------------------------------------------------------------------------------------
Purchase commitments 40.2 4.8 9.8 6.5 19.1
Retention bonuses 4.0 1.0 2.0 1.0 --
Whole Unit Plan (2) 6.4 -- 2.3 4.1 --
Asset retirement obligations (3) 64.2 1.6 4.2 3.5 54.9
Total contractual obligations 394.3 20.0 54 57.5 262.8
===================================================================================================================
(1) Includes long-term and short-term debt.
(2) Based on current estimate of payment to be made on vesting dates.
(3) Based on estimated timing of expenditures to be made in future periods.
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 June 30, 2004.
The Trust has not entered into any guarantee or off balance sheet arrangements
that would adversely impact the Trust's financial position or results of
operations.
ARC Energy Trust 25
IMPACT OF NEW ACCOUNTING POLICIES
In the first quarter of 2004, the Trust implemented the following new accounting
policies and instruments pursuant to requirements of the Canadian Institute of
Chartered Accountants ("CICA") and national securities regulators. The
implementation of these new policies impacted the financial results for 2004 and
comparative periods of 2003 as follows:
HEDGE ACCOUNTING - In December 2001, the CICA issued Accounting Guideline
13 "Hedging Relationships" and EIC-128 "Accounting for Trading,
Speculative, or Non-Hedging Derivative Financial Instruments" that deal
with the identification, designation, documentation and measurement of
effectiveness of hedging relationships for the purposes of applying hedge
accounting. Accounting Guideline 13 ("AcG-13") is intended to harmonize
Canadian GAAP with SFAS No.133 "Accounting for Derivatives Instruments and
Hedging Activities". AcG-13 is effective for fiscal years beginning on or
after July 1, 2003 and upon implementation of AcG-13, accounting in
accordance with EIC-128 is required.
The Trust implemented AcG-13 in the first quarter of 2004 along with
accounting in accordance with EIC-128. As a result, certain of the Trust's
derivative contracts were designated as effective xxxxxx for accounting
purposes at January 1, 2004. Commodity and foreign currency contracts that
were designated as effective xxxxxx continue to be accounted for in the
same manner as in previous periods whereby realized gains and losses on
effective xxxxxx are netted against the item to which they relate in the
statement of income. Commodity and foreign currency contracts that were not
designated as effective xxxxxx for accounting purposes are subject to fair
value accounting in accordance with EIC-128, which requires that changes in
the fair value of these derivative contracts be reported as income or
expense in each reporting period. The income or expense relating to the
change in fair value of the derivative contracts is a non-cash (unrealized)
expense that has no impact on cash flow but may result in significant
fluctuations in net income due to volatility in the underlying market
commodity prices and foreign exchange rates.
Prior to implementation of AcG-13 and EIC-128, the Trust accounted for all
derivative contracts as effective xxxxxx whereby realized gains and losses
on such contracts were included in the statement of income within the
corresponding item to which the hedge pertained. Following implementation,
realized and unrealized gains and losses on derivative contracts that do
not qualify as effective xxxxxx are reported as a separate expense in the
statement of income. In accordance with the transitional provisions of
AcG-13 and EIC-128, this new guideline has been applied prospectively
whereby prior periods have not been restated.
As an example of a commodity derivative contract, the Trust enters into oil
and natural gas put options as part of its commodity risk management
portfolio. The Trust considers such a transaction to be an effective
economic hedge as it reduces exposure to decreases in commodity prices that
would adversely impact cash flow. Per new hedge accounting requirements,
this transaction does not qualify as an effective accounting hedge and
therefore is subject to fair value accounting.
26 ARC Energy Trust
As a result of implementation of this new standard, net income for the
second quarter of 2004 decreased by $6.5 million ($10 million before a
future income tax recovery of $3.5 million). The entire $10 million
decrease in pre-tax net income was the result of non-cash losses due to
changes in the fair value of the contracts. On initial implementation of
this standard on January 1, 2004, the Trust recorded an opening deferred
charge of $14.6 million equal to the fair value of derivative contracts at
that time. The deferred charge is being amortized to earnings over the life
of the respective contracts in place at January 1, 2004. In the second
quarter of 2004, $4.3 million of the deferred charge was expensed. The
Trust recorded a derivative asset of $3.9 million and a derivative
liability of $40.7 million for the fair value of the derivative contracts
as at June 30, 2004 (nil impact on 2003). There was no impact on cash flow
as a result of implementing this new standard.
TRANSPORTATION COSTS - Effective in 2004, the Trust revised its
presentation of transportation costs in accordance with CICA Handbook
Section 1100 "Generally Accepted Accounting Principles". As a result,
revenue has been presented prior to transportation costs and a separate
expense for transportation costs has been presented in the statement of
income. The Trust has reclassified previously reported amounts to be
consistent with the presentation under this new policy. Revenue and
transportation costs both increased by $3.6 million and $3.5 million in the
second quarters of 2004 and 2003, respectively, as a result of this new
policy. Revenue and transportation costs for the first six months of 2004
and 2003 both increased by $7.4 million and $4.8 million, respectively.
There was no impact on net income or cash flow in the first quarter of 2004
nor did it impact restated net income or cash flow for the first quarter of
2003.
In addition to the new policies implemented in the first quarter of 2004, the
following standards were implemented by the Trust in 2003. Due to the
transitional provisions of these standards that required retroactive application
and restatement of prior periods, previously reported financial results for the
three and six month periods ending June 30, 2003 were restated to give effect to
the new standards as follows:
ASSET RETIREMENT OBLIGATIONS - The Trust implemented this standard in 2003
in accordance with the early adoption provisions of the standard. As a
result of the retroactive application, second quarter 2003 comparative
numbers included in this report have been restated to reflect the impact of
this standard on the second quarter 2003 financial statements, note
disclosures and MD&A. Previously reported net income for the second quarter
and six months ended June 30, 2003 increased by $1.1 million ($1.3 million
before a future income tax expense of $0.2 million) and $3.4 million ($3
million before a future income tax recovery of $0.4 million), respectively.
Opening 2003 accumulated earnings increased by $12.1 million net of
applicable income taxes. There was no impact on previously reported cash
flow.
STOCK BASED COMPENSATION AND OTHER STOCK BASED PAYMENTS - The Trust
implemented this amended standard in 2003 in accordance with the early
adoption provisions. As a result, first quarter 2003 financial results were
restated to give effect to the standard as at January 1, 2003. Previously
reported net income for the second quarter and six months ended June 30,
2003 both decreased by $0.2 million. There was no impact on previously
reported cash flow.
ARC Energy Trust 27
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 the future;
d) estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and foreign
exchange rates; and
e) estimated value of asset retirement obligations that are dependent upon
estimates of future costs and timing of expenditures.
The Trust has hired individuals and consultants who have the skill set 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 in order to make more informed decisions
on future estimates.
The ARC management 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.
2004 CASH FLOW SENSITIVITY
Below is a table which illustrates sensitivities to pre-hedged cash flow with
operational changes and changes to the business environment:
------------------------------------------------------------------------------------------------------------------
IMPACT ON ANNUAL IMPACT ON ANNUAL
CASH FLOW DISTRIBUTIONS (2)
ASSUMPTION CHANGE $/UNIT % $/UNIT
------------------------------------------------------------------------------------------------------------------
BUSINESS ENVIRONMENT
Price per barrel of oil
(US$WTI) (1) $30.00 $1.00 $0.05 3.2% $0.04
Price per mcf of natural
gas (CDN$AECO) (1) $5.25 $0.10 $0.03 1.6% $0.02
CDN/USD exchange rate $0.75 $0.01 $0.05 2.0% $0.04
Interest rate on debt 4.2% 1.0% $0.01 1.0% $0.01
------------------------------------------------------------------------------------------------------------------
OPERATIONAL
Liquids production volume 26,500 1.0% $0.01 0.5% $0.01
------------------------------------------------------------------------------------------------------------------
Gas production volumes 171,000 1.0% $0.02 0.6% $0.01
Operating expenses per boe $6.90 1.0% $0.01 0.4% $0.01
Cash G&A expenses per boe $1.05 10.0% $0.01 0.7% $0.01
==================================================================================================================
(1) Analysis does not include the effect of hedging.
(2) Analysis assumes a 20 per cent holdback on distributions.
28 ARC Energy Trust
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. See "Assessment of
Business Risks" in the Trust's 2003 Annual Report MD&A for a detailed
assessment.
OUTLOOK
It is the Trust's objective to provide the highest possible long-term returns to
unitholders by focusing on the key strategic objectives of the business plan.
This focus has resulted in ARC Energy Trust achieving excellent results from
which the unitholders of the Trust have directly benefited. During the first six
months of 2004, the Trust provided unitholders with distributions of $0.90 per
trust unit. To the end of the second quarter of 2004, the Trust has provided
cash distributions of $13.34 per trust unit and capital appreciation of $5.35
per trust unit for a total return of $18.69 per trust unit (22.8 per cent
annualized total return) for unitholders who invested in the Trust at inception.
During the first six months of 2004 and for the remainder of the year, ARC was
and will continue to be active with a robust drilling and development program on
its diverse asset base. The $200 million capital expenditure budget for 2004 is
the largest in the Trust's history excluding acquisitions. The Trust will
prudently deploy capital with a balanced drilling program of low and moderate
risk xxxxx. The 2003 drilling program resulted in a 99 per cent success rate.
The Trust continues to focus on major properties with significant upside, with
the objective to replace production declines with internal development
opportunities.
The low debt levels and strong working capital position provide the Trust with
the financial flexibility to fund the 2004 capital expenditure program and be
poised to take advantage of accretive acquisition opportunities.
See "Outlook" in the Trust's 2003 Annual Report MD&A for additional discussion
of the Trust's key future objectives.
ADDITIONAL INFORMATION
Additional information relating to ARC can be found on SEDAR at xxx.xxxxx.xxx.
ARC Energy Trust 29
QUARTERLY REVIEW
2004 2003 2002
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
---------------------------------------------------------------------------------------------------------------------------------
FINANCIAL
($CDN thousands, except per unit amounts)
Revenue before royalties 233,307 205,594 182,558 184,166 198,542 177,917 118,865 114,873
Per unit (1) 1.26 1.12 1.04 1.11 1.36 1.35 0.94 0.92
Cash flow 122,249 108,014 89,617 87,511 116,546 102,506 61,495 56,603
Per unit (1) 0.66 0.59 0.51 0.53 0.80 0.78 0.49 0.45
Net income (loss) (5) 51,181 40,122 54,465 41,535 128,159 66,042 28,374 (2,739)
Per unit (5) (6) 0.28 0.22 0.31 0.25 0.85 0.50 0.22 (0.02)
Cash distributions 82,053 81,215 78,603 73,890 67,495 59,340 48,060 47,644
Per unit (2) 0.45 0.45 0.45 0.45 0.45 0.45 0.39 0.39
Net debt outstanding (4) 220,074 284,001 262,071 412,686 466,988 226,583 347,795 271,203
Weighted average units (thousands)(3) 184,998 183,314 174,991 166,365 145,546 131,379 126,370 124,794
Units outstanding and issuable
at period end (thousands) (3) 187,296 183,980 182,777 167,530 163,184 139,239 126,444 126,270
---------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
($ thousands)
Geological and geophysical 1,373 2,320 2,846 1,171 656 998 556 619
Drilling and completions 24,867 37,942 37,738 31,661 23,834 17,037 21,047 12,025
Plant and facilities 7,282 15,956 15,512 11,917 4,831 4,204 4,265 3,115
Other capital 605 341 1,418 391 1,325 224 861 380
Total capital expenditures 34,127 56,559 57,515 45,140 30,646 22,463 26,729 16,139
Property acquisitions (dispositions), net (53,412) 1,574 (3,693) (81,166) (79,750) 3,000 61,952 46,018
Corporate acquisitions (8) 30,560 -- -- 258 721,332 -- -- --
Total capital expenditures and net acquisitions 11,275 58,133 53,822 (35,768) 672,228 25,463 88,681 62,157
---------------------------------------------------------------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 22,720 23,663 22,851 23,522 24,078 21,065 20,256 20,809
Natural gas (mmcf/d) 186.7 174.5 180.8 182.0 175.7 117.3 109.2 109.1
Natural gas liquids (bbl/d) 4,313 4,323 4,140 4,105 4,397 3,696 3,355 3,408
Total (boe/d 6:1) 58,147 57,075 57,120 57,968 57,759 44,313 41,808 42,394
Average prices (7)
Crude oil ($/bbl) 47.43 40.41 35.21 35.33 36.61 40.92 30.00 33.57
Natural gas ($/mcf) 6.99 6.64 5.85 5.64 6.59 8.16 5.37 4.22
Natural gas liquids ($/bbl) 38.22 32.30 30.14 30.92 28.83 39.99 27.49 25.23
Oil equivalent ($/boe) 44.09 39.58 34.74 34.53 37.77 44.61 30.90 29.45
---------------------------------------------------------------------------------------------------------------------------------
TRUST UNIT TRADING (based on intra-day trading)
Unit prices
High 15.74 15.74 14.87 13.88 12.84 12.34 12.74 12.98
Low 14.28 13.50 13.31 12.51 11.29 10.89 11.04 11.05
Close 15.35 15.64 14.74 13.55 12.50 11.59 11.90 12.80
Average daily volume (thousands) 337 502 395 551 503 313 269 256
=================================================================================================================================
(1) Based on weighted average trust units and 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. The 2004 net debt
outstanding excludes unrealized commodity and foreign currency contracts,
the deferred hedge loss and deferred commodity and foreign currency
contracts.
(5) Net income and net income per unit have been restated due to the
retroactive application of the change in accounting policies relating to
asset retirement obligations and stock based compensation that were
implemented in 2003.
(6) Net income in the basic per trust unit calculation has been reduced by
interest in the convertible debentures.
(7) Average prices have been restated to be prior to transportation costs in
order to be consistent with 2004 presentation.
(8) Represents total consideration for the corporate acquisition.
30 ARC Energy Trust
CONSOLIDATED BALANCE SHEETS
As at June 30 and December 31 (unaudited)
($CDN thousands) 2004 2003
---------------------------------------------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 75,061 $ 12,295
Accounts receivable 65,442 68,768
Prepaid expenses 9,715 10,400
Deferred hedge loss (Note 6) 3,117 --
Commodity and foreign currency contracts (Note 6) 3,939 --
---------------------------------------------------------------------------------------------------------------
157,274 91,463
Reclamation fund 19,374 17,181
Property, plant and equipment 1,975,359 2,015,539
Goodwill 157,592 157,592
---------------------------------------------------------------------------------------------------------------
Total assets $ 2,309,599 $ 2,281,775
===============================================================================================================
LIABILITIES
Current liabilities
Accounts payable $ 87,953 $ 94,152
Cash distributions payable 27,663 26,980
Current portion of long-term debt (Note 5) 9,383 9,047
Commodity and foreign currency contracts (Note 6) 40,688 --
Deferred commodity and foreign currency contracts (Note 6) 1,419 --
---------------------------------------------------------------------------------------------------------------
167,106 130,179
Long-term debt (Note 5) 245,293 223,355
Asset retirement obligation 64,210 66,657
Future income taxes 288,047 301,965
Other long-term liabilities (Note 13) 3,417 7,883
---------------------------------------------------------------------------------------------------------------
Total liabilities 768,073 730,039
===============================================================================================================
UNITHOLDERS' EQUITY
Unitholders' capital (Note 7) 1,899,448 1,838,580
Exchangeable shares (Note 8) 28,419 29,656
Contributed surplus (Note 9) 5,596 3,471
Accumulated earnings 739,607 648,304
Accumulated cash distributions (Note 3) (1,131,544) (968,275)
---------------------------------------------------------------------------------------------------------------
Total unitholders' equity 1,541,526 1,551,736
---------------------------------------------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 2,309,599 $ 2,281,775
===============================================================================================================
See accompanying notes to consolidated financial statements.
Approval on behalf of the Board:
/s/ Xxx X. Xxx Xxxxxxxxx /s/ Xxxx X. Xxxxxx
XXX X. XXX XXXXXXXXX XXXX X. XXXXXX
DIRECTOR DIRECTOR
ARC Energy Trust 31
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED EARNINGS
Three Months ended Six Months Ended
For the three and six months ended June 30 (unaudited) June 30 June 30
($CDN thousands, except per unit amounts) 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------------
Restated Restated
(Note 2) (Note 2)
REVENUE
Oil, natural gas and natural gas liquids 233,307 198,542 438,901 376,459
Royalties (45,713) (41,331) (84,470) (77,770)
-------------------------------------------------------------------------------------------------------------------------
187,594 157,211 354,431 298,689
Loss on commodity and foreign currency contracts (Note 6) (26,948) -- (61,695) --
-------------------------------------------------------------------------------------------------------------------------
160,646 157,211 292,736 298,689
=========================================================================================================================
Expenses
Transportation 3,610 3,461 7,439 4,749
Operating 35,158 34,559 68,680 63,518
General and administrative 5,406 4,809 10,285 8,818
Non-cash trust unit incentive compensation (Notes 9 and 10) 1,210 147 4,055 147
Interest on long-term debt 4,773 6,120 7,391 9,945
Depletion, depreciation and accretion 59,719 58,285 118,331 99,769
Capital taxes 737 267 1,400 367
(Gain) loss on foreign exchange 4,352 (7,423) 5,052 (14,918)
-------------------------------------------------------------------------------------------------------------------------
114,965 100,225 222,633 172,395
-------------------------------------------------------------------------------------------------------------------------
Income before future income tax 45,681 56,986 70,103 126,294
Future income tax recovery 5,500 71,173 21,200 67,907
-------------------------------------------------------------------------------------------------------------------------
Net income 51,181 128,159 91,303 194,201
Accumulated earnings, beginning of period 688,426 415,076 648,304 350,088
Retroactive application of change in accounting policy (Note 2) -- 13,139 -- 12,085
-------------------------------------------------------------------------------------------------------------------------
Accumulated earnings, beginning of period as restated 688,426 428,215 648,304 362,173
Interest on convertible debentures -- (3,890) -- (3,890)
-------------------------------------------------------------------------------------------------------------------------
Accumulated earnings, end of period 739,607 552,484 739,607 552,484
=========================================================================================================================
Net income per unit (Note 11)
Basic 0.28 0.85 0.50 1.37
Diluted 0.27 0.79 0.49 1.32
=========================================================================================================================
See accompanying notes to consolidated financial statements.
32 ARC Energy Trust
CONSOLIDATED STATEMENTS OF CASH FLOW
Three Months ended Six Months Ended
For the three and six months ended June 30 (unaudited) June 30 June 30
($CDN thousands) 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------------
Restated Restated
(Note 2) (Note 2)
CASH FLOW FROM OPERATING ACTIVITIES
Net income 51,181 128,159 91,303 194,201
Add items not involving cash:
Future income tax recovery (5,500) (71,173) (21,200) (67,907)
Depletion, depreciation and accretion 59,719 58,285 118,331 99,769
Non-cash loss on commodity
and foreign currency contracts (Note 6) 8,975 (3,060) 30,167 (3,943)
Unrealized (gain) loss on foreign exchange 6,664 (7,700) 7,607 (15,102)
Non-cash trust unit incentive compensation (Note 9 and 10) 1,210 147 4,055 147
Cash received on termination of foreign exchange contracts -- 11,888 -- 11,888
-------------------------------------------------------------------------------------------------------------------------
Cash flow before changes in non-cash working capital 122,249 116,546 230,263 219,053
Change in non-cash working capital 1,228 17,025 4,977 9,801
-------------------------------------------------------------------------------------------------------------------------
123,477 133,571 235,240 228,854
CASH FLOW FROM FINANCING ACTIVITIES
Borrowing (Repayment) of long-term debt (166,758) 36,173 (154,307) (74,245)
Issuance of long-term notes (Note 5) 168,975 -- 168,975 --
Interest on convertible debentures -- (3,890) -- (3,890)
Issue of trust units (Note 7) 14,908 4,905 27,862 150,520
Trust unit issue costs (Note 7) (16) (486) (16) (7,924)
Cash distributions paid (81,554) (63,950) (162,586) (118,893)
-------------------------------------------------------------------------------------------------------------------------
(64,445) (27,248) (120,072) (54,432)
CASH FLOW FROM INVESTING ACTIVITIES
Corporate acquisition, net of cash received (Note 4) (60) (156,186) (60) (196,186)
Acquisition of petroleum and natural gas properties (830) (2,616) (2,509) (5,555)
Proceeds on disposition of petroleum and natural gas properties 54,242 72,366 54,347 72,305
Capital expenditures (40,791) (21,707) (100,651) (42,796)
Reclamation fund contributions and actual expenditures (923) (1,481) (3,529) (3,025)
-------------------------------------------------------------------------------------------------------------------------
11,638 (109,624) (52,402) (175,257)
-------------------------------------------------------------------------------------------------------------------------
DECREASE IN CASH AND CASH EQUIVALENTS 70,670 (3,301) 62,766 (835)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 4,391 3,301 12,295 835
-------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF PERIOD 75,061 -- 75,061 --
=========================================================================================================================
See accompanying notes to consolidated financial statements.
ARC Energy Trust 33
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2004 and 2003 (unaudited)
(all tabular amounts in thousands, except per unit and volume amounts)
1. SUMMARY OF ACCOUNTING POLICIES
The unaudited interim consolidated financial statements follow the same
accounting policies as the most recent annual audited financial statements
except as discussed below. The interim consolidated financial statement
note disclosures do not include all of those required by Canadian generally
accepted accounting principles ("GAAP") applicable for annual financial
statements. Accordingly, these interim financial statements should be read
in conjunction with the audited consolidated financial statements included
in the Trust's 2003 annual report.
a) HEDGE ACCOUNTING - The CICA issued Accounting Guideline 13 ("AcG - 13")
"Hedging relationships", effective January 1, 2004, to clarify
circumstances in which hedge accounting is appropriate. In addition,
the CICA simultaneously amended EIC 128, "Accounting for Trading,
Speculative or Non Trading derivative Financial Instruments" to require
that all derivative instruments that do not qualify as a hedge under
AcG - 13, or are not designated as a hedge, be recorded in the balance
sheet as either an asset or a liability with the changes in fair value
recognized in earnings.
The Trust uses derivative instruments to reduce its exposure to
fluctuations in commodity prices, foreign exchange, and interest rates.
The Trust formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective
and strategy for undertaking various hedge transactions. This process
includes linking all derivatives to specific assets and liabilities on
the balance sheet or to specific firm commitments or forecasted
transactions. The Trust also formally assesses, both at the hedge's
inception and on an ongoing basis, whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes
in fair values or cash flows of hedged items.
Realized and unrealized gains and losses associated with hedging
instruments that have been terminated or cease to be effective prior to
maturity, are deferred on the balance sheet and recognized in income in
the period in which the underlying hedged transaction is recognized.
For transactions that do not qualify for hedge accounting the Trust
applies the fair value method of accounting by recording an asset or
liability on the consolidated balance sheet and recognizing changes in
the fair value of the instruments in the current period statement of
income.
As a result of this change in accounting policy, the Trust's net income
for the quarter ended June 30, 2004, decreased by $6.5 million ($10
million net of a future tax recovery of $3.5 million) and net income
for the six months ended June 30, 2004 decreased by $21.9 million
($33.6 million net of a future tax recovery of $11.7 million). Total
assets increased by $7.1 million and total liabilities increased by $29
million ($40.7 million net of a future tax recovery of $11.7 million)
as at June 30, 2004 as a result of this new accounting policy. Cash
flow was not impacted by this change. In accordance with the
transitional provisions of AcG-13 and EIC-128, this new guideline has
been applied prospectively whereby prior periods have not been
restated.
b) TRANSPORTATION COSTS - Effective for fiscal years beginning on or after
October 1, 2003, the CICA issued Handbook Section 1100 "Generally
Accepted Accounting Principles", which defines the sources of GAAP that
companies must use and effectively eliminates industry practice as a
source of GAAP. In prior years, it had been industry practice for
companies to net transportation charges against revenue rather than
showing transportation as a separate expense on the income statement.
Beginning January 1, 2004, the Trust has recorded revenue before
transportation charges and a transportation expense on the income
statement. Prior periods have been reclassified for comparative
purposes. This adjustment has no impact on net income per trust unit
calculations, or cash flow for the Trust.
34 ARC Energy Trust
2. RESTATEMENT OF PRIOR PERIODS DUE TO CHANGES IN ACCOUNTING POLICIES
At December 31, 2003, the Trust adopted two new accounting policies that
required restatement of prior quarters in 2003. The following explains the
impact of these restatements on the Trust's previously reported second
quarter and year-to-date 2003 results.
a) ASSET RETIREMENT OBLIGATIONS - At December 31, 2003, the Trust adopted
CICA Handbook Section 3110 "Asset Retirement Obligations" in accordance
with the early adoption provisions. The transitional provisions of this
section required that the standard be applied retroactively with
restatement of comparative periods. As a result of the retroactive
application, previously reported net income for the second quarter of
2003 increased by $2.3 million ($1.7 million before a future tax
recovery of $0.6 million) and opening 2003 accumulated earnings
increased by $12.1 million ($20.9 million before a future tax expense
of $8.8 million). Previously reported net income for the six months
ended June 30, 2003 increased by $3.4 million ($3 million before a
future tax recovery of $0.4 million). There was no impact on cash flow
as a result of adopting this policy. Basic and diluted per trust unit
calculations for the second quarter and first six months of 2003 each
increased by $0.01 and $0.02, respectively, as a result of adopting
this new policy.
b) UNIT BASED COMPENSATION - At December 31, 2003, the Trust early adopted
the amendments to CICA Handbook Section 3870 "Stock based compensation
and other stock based payments". Under the transitional provisions of
the standard, the Trust is required to record compensation expense in
the statement of income for rights issued on or after January 1, 2003.
As a result of the implementation of this amended standard at year end
2003, previously reported 2003 amounts have been restated to give
effect to the standard as at January 1, 2003. Previously reported net
income for the second quarter and first six months of 2003 decreased by
$0.2 million. There was no impact on cash flow as a result of adopting
this policy. Basic and diluted per trust unit calculations for the
second quarter and first six months of 2003 were not impacted as a
result of adopting this new policy.
3. RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS
------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2004 2003 2004 2003
------------------------------------------------------------------------------------------------------------------
Cash flow before changes in non-cash working capital 122,249 116,546 230,263 219,053
Add (deduct):
Cash withheld to fund capital expenditures (34,127) (32,866) (59,251) (53,109)
Reclamation fund contributions and
interest earned on fund (1,843) (1,659) (3,518) (2,788)
Interest on convertible debentures -- (3,890) -- (3,890)
------------------------------------------------------------------------------------------------------------------
Discretionary debt repayments (4,225) (10,636) (4,225) (32,431)
Cash distributions 82,054 67,495 163,269 126,835
Accumulated cash distributions, beginning of period 1,049,490 748,287 968,275 688,947
------------------------------------------------------------------------------------------------------------------
Accumulated cash distributions, end of period 1,131,544 815,782 1,131,544 815,782
Cash distributions per unit 0.45 0.45 0.90 0.90
Accumulated cash distributions per unit, beginning of period 12.89 11.09 12.44 10.64
------------------------------------------------------------------------------------------------------------------
Accumulated cash distributions per unit, end of period 13.34 11.54 13.34 11.54
==================================================================================================================
Cash distributions per trust unit reflect the sum of the per trust unit
amounts paid monthly to unitholders.
ARC Energy Trust 35
4. ACQUISITION OF UNITED PRESTVILLE LTD.
On June 8, 2004 the Trust acquired all of the issued and outstanding shares
of United Prestville Ltd. ("United Prestville") for total consideration of
$30.6 million. The transaction was accounted for based on the purchase
method with the allocation of the purchase price and consideration paid as
follows:
NET ASSETS ACQUIRED
------------------------------------------------------------------------
Working capital deficit (2,569)
Property, plant and equipment 40,412
Future income taxes (7,283)
------------------------------------------------------------------------
TOTAL NET ASSETS ACQUIRED 30,560
========================================================================
CONSIDERATION PAID
------------------------------------------------------------------------
Cash fees paid 60
Trust units issued 30,500
------------------------------------------------------------------------
TOTAL CONSIDERATION PAID 30,560
========================================================================
Pursuant to EIC-124, the acquisition of United Prestville did not qualify
to be accounted for as a business combination as the acquired entity did
not meet the necessary criteria in order to be classified as a business. As
a result, no goodwill was recorded on this transaction.
The future income tax liability on acquisition was based on the difference
between the fair value of the acquired net assets of $33.1 million and the
associated tax basis of $19.3 million.
5. LONG-TERM DEBT
The Trust has US$65 million (CDN$87.1 million) of senior secured notes (the
"Senior Secured Notes"), US$125 million (CDN$167.6 million) of long-term
secured notes (the "Long-term Notes") and one syndicated credit facility
that provide the Trust with a combined maximum borrowing base of CDN$620
million as at June 30, 2004.
The Long-term Notes were issued on April 27, 2004 via a private placement
in two tranches of US$62.5 million each. The first tranche of US$62.5
million has a final life of 10 years (average life of 7.5 years) and pays a
semi-annual coupon of 4.62 per cent per annum. The second tranche of
US$62.5 million has a final life of 12 years (average life of 10 years) and
pays a semi-annual coupon of 5.10 per cent per annum. Repayments of the
notes will occur in years 2009 through 2016.
The Trust completed its annual credit review with its lenders that resulted
in the Trust's credit facilities remaining unchanged at CDN$620 million.
In April 2004, the Trust consolidated its credit facilities into one
syndicated facility. The syndication did not impact security or covenants
under the credit facility.
6. FINANCIAL INSTRUMENTS
The Trust uses a variety of derivative instruments to reduce its exposure
to fluctuations in commodity prices and foreign exchange rates. The Trust
considers all of these transactions to be effective economic xxxxxx,
however, the majority of the Trust's contracts do not qualify as effective
xxxxxx for accounting purposes.
36 ARC Energy Trust
Following is a summary of all derivative contracts in place as at
June 30, 2004:
-------------------------------------------------------------------------------------------------------------------------
Daily Average Contract Price
Commodity Contracts Quantity Prices ($) (1) Index Term
-------------------------------------------------------------------------------------------------------------------------
Crude oil fixed price contracts 5,000 bbls 46.38 WTI July 2004 - August 2004
5,000 bbls 46.57 WTI September 2004
5,000 bbls 46.38 WTI October 2004
3,000 bbls 41.55 WTI November 2004 - December 2004
Crude oil fixed price contracts
(embedded put option) (2) 8,000 bbls 39.89 (33.68) WTI July 2004 - September 2004
5,000 bbls 38.09 (32.17) WTI October 2004 - December 2004
4,000 bbls 38.80 (34.85) WTI January 2005 - June 2005
Crude oil collared contracts
(embedded put option) (2) 4,000 bbls 36.86 - 43.06 (31.50) WTI July 2004 - September 2004
7,000 bbls 41.74 - 48.83 (34.47) WTI October 2004 - December 2004
8,000 bbls 45.57 - 53.68 (38.87) WTI January 2005 - March 2005
8,000 bbls 45.57 - 54.79 (39.54) WTI April 2005 - December 2005
Crude oil fixed price contracts
(embedded exercise option) (3) 4,000 bbls 38.80 WTI July 2005 - December 2005
Natural gas fixed price contracts 15,000 GJ 6.36 AECO July 2004 - October 2004
10,000 mmbtu 6.23 NYMEX July 2004 - October 2004
Natural gas collared contracts 15,000 GJ 5.00 - 6.63 AECO July 2004 - October 2004
10,000 GJ 7.00 - 9.90 AECO November 2004 - March 2005
Natural gas collared contracts
(embedded put option) (2) 10,000 GJ 7.00 - 8.25 (5.75) AECO July 2004 - October 2004
30,000 GJ 7.73 - 8.20 (5.83) AECO November 2004 - March 2005
Natural gas fixed price physical
delivery contract 10,000 GJ 6.00 AECO July 2004 - December 2004
-------------------------------------------------------------------------------------------------------------------------
Average Average
Monthly Contract Contract
Foreign Currency Contracts Amount (US$000) Rate Term
-------------------------------------------------------------------------------------------------------------------------
Fixed rate foreign exchange contracts (sell) 3,393 1.3654 July 2004 - December 2004
Fixed rate foreign exchange contracts (sell)
(embedded put option) (2) 7,432 1.3418 (1.2686) July 2004 - December 2004
=========================================================================================================================
--------------------------------------------------------------------------------------------------------------
Annual Fixed Annual
Monthly Contract Interest Interest
Interest Rate Contracts Amount (US$000) Rate Rate Term
--------------------------------------------------------------------------------------------------------------
Interest rate swap (4) 30,500 LIBOR+38 bps 4.62 July 2004 - April 2014
Interest rate swap (4) 32,000 LIBOR+38.5 bps 4.62 July 2004 - April 2014
==============================================================================================================
--------------------------------------------------------------------------------------------------------------
Hourly Contract
Electricity Contracts Quantity Price ($) Term
--------------------------------------------------------------------------------------------------------------
Fixed price electricity contract 5 MW/h $63.00 July 2004 - December 2010
==============================================================================================================
(1) Commodity contracts denominated in US$ have been converted to CDN$ at
the period end exchange rate of 1.3404.
(2) Counterparty may exercise a put option if index falls below the
specified price (as denoted in brackets) on a monthly settlement
basis.
(3) Counterparty can exercise their option on June 30, 2005 for a fixed
price swap at US$28.95 (CDN $38.80) for the period July through
December 2005.
(4) Interest rate swap contracts have an optional termination date of
April 27, 2009. The Trust has the option to extend the optional
termination date by one year on the anniversary date of the trade date
each year until April 2009. Starting in 2009, the contract amount
decreases annually until 2014. The Trust pays the floating interest
rate based on the three month LIBOR plus a spread and receives the
fixed interest rate.
ARC Energy Trust 37
The $1.4 million balance for commodity and foreign currency contracts on
the consolidated balance sheet relates to a natural gas fixed price
derivative contract that was assumed in conjunction with the acquisition of
Startech Energy Inc. The $1.4 million balance will be amortized over the
remaining contract term to October 2004.
The Trust has designated its fixed price electricity contract as an
effective accounting hedge as at January 1, 2004. A realized loss of $0.2
million on the electricity contract has been included in operating costs in
the January to June period. The fair value loss on the electricity contract
of $3.4 million has not been recorded on the balance sheet at June 30,
2004.
The Trust designated the interest rate swap contracts as effective
accounting xxxxxx on the contract date. A realized gain of $0.5 million on
the interest rate swap contracts has been included in interest expense for
the second quarter and six months ending June 30, 2004. The fair value loss
on the interest rate swap contracts of $2.3 million has not been recorded
on the balance sheet at June 30, 2004.
None of the Trust's commodity and foreign currency contracts have been
designated as accounting xxxxxx. Accordingly, all commodity and foreign
currency contracts have been accounted for based on the fair values.
The following table reconciles the movement in the fair value of the
Trust's financial commodity and foreign currency contracts that have not
been designated as accounting xxxxxx:
----------------------------------------------------------------------------------
Fair value at January 1, 2004(1) (14,575)
Change in fair value of contracts in the period (53,702)
Realized losses in the period 31,528
----------------------------------------------------------------------------------
Fair value at June 30, 2004 (1) (36,749)
==================================================================================
Commodity and foreign currency contracts liability at June 30, 2004 (40,688)
Commodity and foreign currency contracts asset at June 30, 2004 3,939
==================================================================================
(1) Excludes the fixed price electricity contract and interest rate swap
contracts that were accounted for as accounting xxxxxx.
Upon implementation of the new hedge accounting guideline on January 1,
2004, the Trust recorded a liability and corresponding deferred hedge loss
of $14.6 million for the fair value of the contracts at that time. The
opening deferred hedge loss is being amortized to income over the terms of
the contracts in place at January 1, 2004. In the second quarter and first
six months of 2004, $4.3 million and $11.5 million, respectively, of the
opening deferred hedge loss was recorded as an expense. The remaining $3.1
million at June 30, 2004 will be expensed to earnings over the remainder of
2004. At June 30, 2004, the fair value of the contracts that were not
designated as accounting xxxxxx was a loss of $36.8 million.
The Trust recorded a loss on commodity and foreign currency contracts of
$61.7 million in the statement of income for the six months ending June 30,
2004. This amount includes the realized and unrealized gains and losses on
derivative contracts that do not qualify as effective accounting xxxxxx.
Included in this amount is an unrealized loss of $22.2 million due to the
change in fair value of the contracts in the period. Realized cash losses
on contracts in the period of $31.5 million and amortization expense of
$11.5 million of the opening deferred hedge loss have been included in this
amount. In addition, this amount includes a non-cash amortization gain of
$3.5 million relating to contracts which were previously recorded on the
balance sheet. The second quarter loss on commodity and foreign currency
contracts of $26.9 million includes an unrealized loss of $5.7 million due
to the change in fair value of the contracts; cash realized losses of $18
million; amortization expense of the opening deferred charge of $4.3
million; and, a non-cash amortization gain of $1.1 million.
In accordance with the transitional provisions of AcG-13 and EIC-128, this
new guideline has been applied prospectively whereby prior periods have not
been restated.
38 ARC Energy Trust
7. UNITHOLDERS' CAPITAL
-----------------------------------------------------------------------------------------------------------
Number of
TRUST UNITS Trust Units $
-----------------------------------------------------------------------------------------------------------
Balance, as at January 1, 2004 179,780 1,838,580
Issued for properties (Note 4) 2,032 30,500
Issued on conversion of ARL exchangeable shares (Note 8) 130 1,237
Issued on exercise of employee rights (Note 9) 1,270 14,517
Distribution reinvestment program 1,035 14,630
Trust unit issue costs -- (16)
-----------------------------------------------------------------------------------------------------------
Balance, end of period 184,247 1,899,448
===========================================================================================================
8. EXCHANGEABLE SHARES
-----------------------------------------------------------------------------------------------------------
Number of
ARL EXCHANGEABLE SHARES Shares $
-----------------------------------------------------------------------------------------------------------
Balance, as at January 1, 2004 2,011 29,656
Exchanged for trust units (1) (84) (1,237)
-----------------------------------------------------------------------------------------------------------
Balance, end of period 1,927 28,419
Exchange ratio, end of period 1.58199 --
-----------------------------------------------------------------------------------------------------------
Trust units issuable upon conversion 3,049 28,419
===========================================================================================================
(1) During the first six months of 2004, 83,911 exchangeable shares were
converted to trust units at an average exchange ratio of 1.5539.
9. TRUST UNIT INCENTIVE RIGHTS PLAN
-----------------------------------------------------------------------------------------------------------
Number of Weighted Average
Rights Exercise Price
-----------------------------------------------------------------------------------------------------------
Balance, beginning of period 4,869 $ 11.29
Granted 27 15.64
Exercised (1,269) 10.42
Cancelled (114) 11.62
-----------------------------------------------------------------------------------------------------------
Balance before reduction of exercise price 3,513 11.62
Reduction of exercise price -- (0.38)
-----------------------------------------------------------------------------------------------------------
Balance, end of period 3,513 $ 11.24
===========================================================================================================
The Trust recorded year-to-date compensation expense and contributed
surplus of $3.5 million ($0.6 million in the second quarter of 2004), based
on the June 30, 2004 trading price of $15.35, for three million rights
issued on or after January 1, 2003. This compensation expense and
contributed surplus amount was then reduced by $0.1 million ($0.02 million
in the second quarter of 2004) for rights issued on or after January 1,
2003 that were subsequently cancelled prior to vesting. The contributed
surplus amount was further reduced by $1.3 million ($1.3 million in the
second quarter of 2004) for rights exercised in the period. These amounts
were reclassified to Unitholders' Equity. Of the 3,013,569 rights issued on
or after January 1, 2003 that were subject to recording compensation
expense, 176,933 rights have been cancelled and 400,332 rights have been
exercised to June 30, 2004.
For rights granted in 2002, the Trust has disclosed proforma results as if
the amended accounting standard had been applied retroactively.
ARC Energy Trust 39
-----------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
PRO FORMA RESULTS 2004 2003 2004 2003
-----------------------------------------------------------------------------------------------------------
Net income as reported 51,181 128,159 91,303 194,201
Less: compensation expense for rights issued in 2002 40 179 1,110 179
-----------------------------------------------------------------------------------------------------------
Pro forma net income 51,141 127,980 90,193 194,022
Basic net income per trust unit
As reported 0.28 0.85 0.50 1.37
Pro forma 0.28 0.85 0.49 1.37
-----------------------------------------------------------------------------------------------------------
Diluted net income per trust unit
As reported 0.27 0.79 0.49 1.32
Pro forma 0.27 0.79 0.48 1.32
===========================================================================================================
10. WHOLE TRUST UNIT INCENTIVE PLAN
In March 2004, the Board of Directors, upon recommendation of the
Compensation Committee, approved a new Whole Trust Unit Incentive Plan (the
"Whole Unit Plan") to replace the existing Trust Unit Incentive Rights Plan
for new awards granted subsequent to March 31, 2004. The new Whole Unit
Plan will result in employees receiving cash compensation in relation to
the value of a specified number of underlying notional trust units. The
Whole Unit Plan consists of Restricted Trust Units ("RTU's") for which the
number of trust units is fixed and will vest over a period of three years
and Performance Trust Units ("PTU's") for which the number of trust units
is variable and will vest at the end of three years. The Trust issued
188,602 RTU's and 127,123 PTU's upon inception of the plan on April 15,
2004 to employees and officers. During the second quarter, 1,100 RTU's were
cancelled whereby there were 314,625 RTU's and PTU's outstanding under the
plan at June 30, 2004.
Upon vesting, the employee 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 PTU's is dependent upon
the future performance of the Trust compared to its peers based on certain
key industry benchmarks. The cash compensation issued upon vesting of the
PTU's may range from 0.25 to two times the number of the PTU's originally
granted.
The fair value associated with the RTU's and PTU's will be expensed in the
statement of income over the vesting period. As the value of the RTU's and
PTU's is dependent upon the trust unit price, the expense recorded in the
statement of income may fluctuate over time.
The Trust recorded compensation expense of $0.7 million, based on the June
30, 2004 unit price of $15.35, distributions of $0.45 per unit during the
quarter and management's estimate of the number of PTU's to be issued on
maturity.
11. NET INCOME PER TRUST UNIT
Net income per trust unit has been determined based on the following:
-----------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2004 2003 2004 2003
-----------------------------------------------------------------------------------------------------------
Weighted average trust units 181,949 142,527 181,118 135,467
Trust units issuable on conversion of exchangeable shares 3,049 3,019 3,049 3,019
-----------------------------------------------------------------------------------------------------------
Weighted average trust units and exchangeable shares 184,998 145,546 184,167 138,486
Dilutive impact of rights 1,604 16,878 1,840 8,860
-----------------------------------------------------------------------------------------------------------
Dilutive trust units and exchangeable shares 186,602 162,424 186,007 147,346
===========================================================================================================
Net income per trust unit for the three and six months ending June 30, 2003
was adjusted for interest paid on convertible debentures.
40 ARC Energy Trust
12. INCOME TAXES
During the first quarter of 2004, the Alberta government enacted a
reduction in corporate income tax rates. Effective April 1, 2004 the
provincial corporate income tax rate decreased to 11.5 per cent from 12.5
per cent. As a result of this reduction, the Trust's income tax rate
applied to temporary differences decreased to approximately 34.5 per cent
compared to approximately 35 per cent as at December 31, 2003.
In the second quarter, the Trust recorded a future income tax liability of
$7.3 million on the acquisition of United Prestville Ltd., a private
corporation. The future income tax liability was based on the difference
between the fair value of the acquired assets of $33.5 million and the tax
basis of $19.3 million. The future income tax liability was recorded as
part of the acquisition cost to property, plant and equipment.
The future income tax recovery of $21.2 million in 2004 included a recovery
of $3.2 million attributed to the reduction in future income tax rates and
an $11.7 million recovery due to a net liability for financial commodity
and foreign currency contracts of $ 33.6 million under new hedge accounting
standards.
13. OTHER LONG-TERM LIABILITIES
2004 2003
---------------------------------------------------------------------------
Commodity and foreign currency contracts -- 4,883
Retention bonuses 3,000 3,000
Accrued long-term incentive compensation 417 --
---------------------------------------------------------------------------
Total other long-term liabilities 3,417 7,883
===========================================================================
The commodity and foreign currency contracts relate to a natural gas fixed
price contract that was assumed upon acquisition of Startech in 2001. This
balance is being amortized to earnings to October 2004. The remaining
balance of $1.4 million at June 30, 2004 is included in current
liabilities.
The retention bonuses arose upon internalization of the management contract
in 2002. The long-term portion of retention bonuses will be paid in August
2005 through August 2007.
The accrued long-term incentive compensation represents the long-term
portion of the Trust's estimated liability for the Whole Unit Plan as at
June 30, 2004. This amount is payable in 2006 through 2007.
ARC Energy Trust 41
--------------------------------------------------------------------------------
CORPORATE AND UNITHOLDER INFORMATION
--------------------------------------------------------------------------------
DIRECTORS EXECUTIVE OFFICE CORPORATE CALENDAR
Xxx X. Xxx Xxxxxxxxx (1) (3) (4) ARC Resources Ltd. 2004
Chairman 0000, 000 - 0xx Xxxxxx X.X. July 17 Announcement of
Calgary, Alberta T2P 5E9 Q3 Distribution
Xxxxxx XxXxxx (1) (4) (5) Monthly Amounts
Vice-Chairman Telephone: (000) 000-0000
Toll Free: 0-000-000-0000 August 5 2004 Q2 Results
Xxxx X. Xxxxxxxx Facsimile: (000) 000-0000
President and Chief Executive Officer Website: xxx.xxxxxxxxxxxx.xxx October 17 Announcement of
E-Mail: xx@xxxxxxxxxxxx.xxx Q4 Distribution
Xxxx X. Xxxxxxx (2) (4) Monthly Amounts
Xxxxxxxx X. Xxxxx (2) (3) (5) STOCK EXCHANGE LISTING
Xxxx X. Xxxxxx (1) (2) TRUSTEE AND TRANSFER AGENT The Toronto Stock Exchange
Xxxxxxx X. Xxxxxxxx (1) (2) Computershare Trust Company of Trading Symbols:
Canada AET.UN (Trust Units)
Xxxx X. Xxxxxxx (3) (4) (5) 600, 000 - 0xx Xxxxxx X.X. ARX (Exchangeable Shares)
Calgary, Alberta T2P 3S8
(1) Member of Audit Committee Telephone: (000) 000-0000
(2) Member of Reserve Audit Committee INVESTOR INFORMATION
(3) Member of Human Resources and
Compensation Committee Visit our website at
(4) Member of Policy and Board Governance AUDITORS xxx.xxxxxxxxxxxx.xxx
Committee
(5) Member of Management Advisory Committee Deloitte & Touche LLP or contact:
(6) Health, Safety and Environment Calgary, Alberta Investor Relations
Committee (000) 000-0000 or
0-000-000-0000 (Toll Free)
OFFICERS ENGINEERING CONSULTANTS
PRIVACY OFFICER
Xxxx X. Xxxxxxxx Xxxxxxx Xxxxxxxx Xxxx Associates
President and Chief Executive Officer Ltd. Xxxxx X. Xxxxx
Calgary, Alberta xxxxxxx@xxxxxxxxxxxx.xxx
Xxxx X. Xxxxxx Facsimile: (000) 000-0000
Vice-President, Engineering
Xxxxx X. Xxxxx LEGAL COUNSEL
Vice-President, Business Development
Burnet Xxxxxxxxx & Xxxxxx LLP
Xxxxx X. Xxxxx Calgary, Alberta
Vice-President, Corporate Services
Xxxxxx X. Xxxxxxxx
Vice-President, Finance [GRAPHIC OMITTED] [GRAPHIC OMITTED]
and Chief Financial Officer [LOGO -- VCR-MVR INC.] [LOGO -- 2003 MEMBER OF XXXX
STEWARDSHIP INITIATIVE]
Xxxxx X. Xxxxxxx [GRAPHIC OMITTED]
Vice-President, Land and Operations [LOGO - GOLD CHAMPION Members commit to
LEVEL REPORTER] continuous improvement in
Xxxxx X. Xxx the responsible
Corporate Secretary Canada's Climate Change management, development
Voluntary Challenge and Registry. and use of our natural
Xxxxx X. Xxxxxxx The industry's voluntary effort to resources; protection of our
Treasurer reduce greenhouse gas emissions environment; and, the health
and document the efforts year and safety of our workers
over year. and the general public.
