ARC Energy Trust announces third quarter 2007 results

Nov 7, 2007

CALGARY, Nov. 7 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces the results for the third quarter ending September 30,
2007.

<<
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
-------------------------------------------------------------------------
FINANCIAL
($CDN millions, except per
unit and per boe amounts)
Revenue before royalties 300.2 312.3 913.6 937.9
Per unit(1) 1.42 1.52 4.36 4.60
Per boe 53.40 54.59 53.72 54.66
Cash flow from operating
activities(2) 179.6 203.4 531.2 574.6
Per unit(1) 0.85 0.95 2.54 2.82
Per boe 31.95 35.56 31.23 33.49
Net income 120.8 116.8 389.0 403.4
Per unit(3) 0.58 0.58 1.88 2.01
Distributions 125.0 121.4 372.2 361.9
Per unit(1) 0.60 0.60 1.80 1.80
Per cent of cash flow from
operating activities(2) 70% 60% 70% 63%
Net debt outstanding(4) 699.8 579.7 699.8 579.7
Total capital expenditures 131.9 104.9 257.9 242.6

OPERATING
Production
Crude oil (bbl/d) 28,437 29,108 28,682 28,852
Natural gas (mmcf/d) 173.3 173.4 177.6 178.9
Natural gas liquids (bbl/d) 3,795 4,166 4,013 4,178
Total (boe/d) 61,108 62,178 62,296 62,851
Average prices
Crude oil ($/bbl) 73.40 71.84 66.45 67.68
Natural gas ($/mcf) 5.52 6.10 6.90 6.97
Natural gas liquids ($/bbl) 55.64 56.60 52.07 54.67
Oil equivalent ($/boe)(5) 53.41 54.59 53.73 54.66
Operating netback ($/boe)
Commodity and other revenue
(before hedging) 53.41 54.59 53.73 54.66
Transportation costs (0.65) (0.60) (0.73) (0.62)
Royalties (8.76) (9.34) (9.28) (9.95)
Operating costs (9.93) (8.82) (9.51) (8.27)
Netback (before hedging) 34.07 35.83 34.21 35.82
-------------------------------------------------------------------------

TRUST UNITS
(millions)
Units outstanding, end of period 208.8 202.8 208.8 202.9
Units issuable for
exchangeable shares 2.9 2.9 2.9 2.9
Total units outstanding and
issuable for exchangeable
shares, end of period 211.7 205.7 211.7 205.8
Weighted average units(6) 210.9 205.1 209.4 203.8
-------------------------------------------------------------------------

TRUST UNIT TRADING STATISTICS
($CDN, except volumes) based on
intra-day trading
High 22.60 30.74 23.86 30.74
Low 19.00 25.25 19.00 24.35
Close 21.17 27.21 21.17 27.21
Average daily volume (thousands) 503 615 588 569
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares. Per unit distributions are based on
the number of trust units outstanding at each distribution record
date.
(2) Cash flow from operating activities is a GAAP measure. Historically,
management has disclosed Cash Flow as a non-GAAP measure calculated
using cash flow from operating activities less the change in non-cash
working capital and the expenditures on site restoration and
reclamation as they appear on the Consolidated Statements of Cash
Flows. Cash Flow for Q3 2007 would be $183.5 million and year-to-date
Cash Flow would be $534.8 million. Distributions as a percentage of
Cash Flow would be 68 per cent for Q3 2007 and 62 per cent for year-
to-date 2007. Please refer to the non-GAAP measures section in the
MD&A for further details.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes unrealized amounts pertaining to risk management
contracts
(5) Includes other revenue.
(6) Includes trust units issuable for outstanding exchangeable shares at
period end.

ACCOMPLISHMENTS/FINANCIAL UPDATE
--------------------------------
- Production averaged 61,108 boe per day in the third quarter of 2007,
down two per cent from 62,178 boe per day achieved in the third
quarter of 2006. The Trust's 2007 production has been hampered by
restricted access to third party processing facilities for new
production and downtime on existing properties where turnarounds took
longer than expected. A third party gas plant that the Trust had
expected to be operational by early October is now scheduled to start
up in mid-November. Consequently, the Trust has lowered its fourth
quarter production expectations to approximately 64,000 boe per day.
The Trust is still on target for full year guidance of approximately
63,000 boe per day.

- The Trust drilled 151 gross wells (113 net wells) on operated
properties during the third quarter with a 100 per cent success rate.
Of the gross wells drilled, 30 were oil wells and 121 were natural
gas wells.

- Capital expenditures for the quarter, including $33 million for land
purchases, were $131.9 million, bringing year-to-date capital
expenditures to $257.9 million. Ninety-one per cent of year-to-date
capital expenditures have been funded from cash flow from operating
activities and the proceeds from the Distribution Re-investment Plan
("DRIP"). Despite spending $32.7 million on unbudgeted land
acquisitions in the quarter, the Trust still expects to spend
approximately $350 million on capital expenditures during 2007.

- The Trust completed minor property acquisitions of $27.3 million
during the quarter. These acquisitions added approximately 380 boe
per day of production and 1.4 million boe of proved plus probable
reserves. The majority of the acquired volumes is in our southeast
Saskatchewan core area and closed on September 13, 2007.

- Prior to hedging activities, ARC's total realized commodity price was
$53.28 per boe in the third quarter of 2007, compared to $54.45 per
boe received prior to hedging in the third quarter of 2006 as a
result of softer gas prices in 2007. The seven per cent increase in
the U.S. WTI oil prices was completely offset by a seven per cent
appreciation in the Canadian dollar versus the U.S. dollar resulting
in essentially no change to the Canadian dollar of WTI $78.80 in both
the third quarter of 2007 and 2006.

- Cash flow from operating activities for the quarter was $179.6
million of which $125 million was distributed to unitholders
representing $0.60 per unit based on the number of trust units
outstanding at each record date. The Trust announced fourth quarter
distributions will remain at $0.20 per unit per month, a level that
has been maintained since October 2005.

- On October 25, 2007, the Alberta Government announced the New Royalty
Framework increasing provincial royalty rates. The Trust has made a
preliminary assessment of the impact of this legislation effective
January 1, 2009 and we estimate that the total royalties payable on
the Trust's production will increase by approximately 10 per cent at
current commodity prices calculated using expected 2009 production
rates. This estimate will vary based on prices, production decline of
existing wells and performance and location of new wells drilled. The
10 per cent increase in royalties payable which equates to
approximately a two per cent increase in the Trust's royalty rate
takes into account that 30 per cent of the Trust's production is
outside the Province of Alberta. The royalty change in 2009 on a
property by property basis is highly variable with decreased
royalties on some properties, primarily shallow gas wells, and a
doubling of royalties on Alberta high rate oil production properties.
The New Alberta Royalty Framework will impact future drilling in
order for the Trust to maintain acceptable rates of return on its
capital deployed.

- On October 30, 2007, the Federal Government presented the fall
economic statement that proposed significant reductions in corporate
income tax rates from 22.1 per cent to 15 per cent. If enancted, the
reductions will be phased in between 2007 and 2012. In addition, the
Government announced that it plans to collaborate with the
provinces and territories to reach a 25 per cent combined federal-
provincial-territorial statutory corporate income tax rate.
>>

ONE YEAR UPDATE ON THE FEDERAL GOVERNMENT'S TRUST TAX LEGISLATION
-----------------------------------------------------------------
On October 31, 2006, the Federal Government announced proposed
legislation regarding taxation of Income Trusts. Currently, distributions paid
to unitholders, other than return of capital, are claimed as a deduction by
the Trust in arriving at taxable income whereby tax is eliminated at the Trust
level and is paid by the unitholders.
The Trust tax legislation, which received Royal assent on June 22, 2007
will result in a two-tiered tax structure whereby distributions would first be
subject to a 31.5 per cent tax at the Trust level commencing in 2011, and then
unitholders would be subject to tax on the distribution as if it were a
taxable dividend paid by a taxable Canadian corporation.
On October 30, 2007, the Finance Minister announced significant changes
to the tax system including reductin of the corporate income tax rate to 15
per cent by 2012. At the very least, we would expect the proposed tax on trust
distributions to be reduced accordingly since it was based upon combined
federal and provincial tax rates. More importantly with this corporate tax
reduction any claim of tax leakage in the trust sector, which was tenuous at
best, based upon our assessment of the data compiled, can no longer be claimed
to exist. We continue to lobby the government on behalf of our unitholders to
exempt the energy trust sector from the proposed tax or eliminate it
altogether.
Our Board of Directors and management continue to review the impact of
this tax on our business strategy and the merits of converting to a
corporation on or before January 1, 2011. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the after-tax distribution amount in 2011 to taxable Canadian investors
will remain approximately the same, however, will decline for both
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and
foreign investors.
Another recent development occurred on October 30, 2007 when an American
couple, Mr. and Mrs. Marvin Gottlieb, filed a Notice of Intent to submit a
claim to arbitration under the North American Free Trade Agreement (NAFTA).
U.S. investors wishing to learn more about the Gottlieb's NAFTA challenge to
the Government of Canada can visit their website at www.naftatrustclaims.com.

MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
This management's discussion and analysis ("MD&A") is dated November 6,
2007 and should be read in conjunction with the September 30, 2007 unaudited
interim consolidated financial statements of ARC Energy Trust ("ARC", "the
Trust", "we", "our"), the June 30, 2007 and the March 31, 2007 unaudited
interim consolidated financial statements and MD&As, as well as the audited
consolidated financial statements and MD&A for the year ended December 31,
2006.

Non-GAAP Measures

Historically, management used the non-GAAP measure Cash Flow or cash flow
from operations to analyze operating performance, leverage and liquidity. We
have now switched to utilize the GAAP measure cash flow from operating
activities instead of Cash Flow. There are two differences between the two
measures with cash flow from operating activities including positive or
negative changes in non-cash working capital and the deduction of expenditures
on site restoration and reclamation as they appear on the Consolidated
Statements of Cash Flows. Although management feels that Cash Flow is a valued
measure of funds generated by the Trust during the reported quarter, we have
changed our disclosure to only discuss the GAAP measure in the MD&A in order
to avoid any potential confusion by readers of our financial information and
in our opinion, to more fully comply with the intent of certain regulatory
requirements.
Our historical measure of Cash Flow reflected revenues and costs for the
three months reported in the quarter. This amount, however, was comprised of
accruals for at least one month of revenue and approximately two months of
costs. The oil and gas industry is designed such that revenues are typically
collected on the 25th day of the month following the actual production month.
Royalties are typically paid two months following the actual production month
and operating costs are paid as the invoices are received. This can take
several months; however, most invoices for operated properties are paid within
approximately two months of the production month.
At the time of writing this MD&A, substantially all revenues have been
collected for the production period of September 2007. Management performs
analysis on the amounts collected to ensure that the amounts accrued for
September are accurate. Analysis is also performed regularly on royalties and
operating costs to ensure that amounts have been accurately accrued.
Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of cash flow from operating
activities, operating netbacks ("netbacks"), total capitalization, finding,
development and acquisition costs, recycle ratio, reserve life index, reserves
per unit and production per unit to analyze financial and operating
performance. Management feels that these KPIs and benchmarks are key measures
of profitability and overall sustainability for the Trust. These KPIs 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.

Update on Legislation Changes Impacting the Trust

Broad-based Federal Tax Reductions

On October 30, 2007 the Federal Government presented the fall economic
statement that proposed significant reductions in corporate income tax rates
from 22.1 per cent to 15 per cent. The reductions will be phased in between
2007 and 2012. In addition, the Government announced that it plans to
collaborate with the provinces and territories to reach a 25 per cent combined
federal-provincial-territorial statutory corporate income tax rate.

Alberta Government Royalty Regime

In September 2007, the Alberta Government announced the results of the
royalty review that was performed by an independent panel. The report proposed
that the royalty rates in Alberta should be increased by $2 billion dollars.
The proposed increases pertained to conventional oil and gas production as
well as oil sands production.
On October 25, 2007, the Alberta Government announced The New Royalty
Framework, ("framework"), which will take effect on January 1, 2009 and is
projected by the government to increase royalties by approximately $1.4
billion in 2010 or an increase of 20 per cent over revenue forecasts by the
Alberta Government for that year. These increases comprise a 57 per cent
increase in conventional oil royalties and a 10 per cent increase in gas
royalties. The framework proposes new, simplified royalty formulas for
conventional oil and natural gas that will operate on sliding scales which are
determined by commodity prices and well productivity. The formulas eliminate
the need for conventional oil and natural gas tiers and several royalty
exemption programs.

<<
The main aspects of the framework as it impacts the Trust include the
following:

- Conventional Oil Royalties - The New Royalty Framework accepts almost
all of the royalty review panel's recommendations. They will
eliminate almost all royalty relief programs and the existing "tiers"
and move to a price and production sensitive royalty system. Rate
caps on price will be raised in the conventional oil royalty formulas
to $120 per barrel to provide for a royalty system that is sensitive
over a broader range of prices. Overall, this will result in maximum
royalty rates increasing from the current maximums of 30 per cent and
35 per cent for old and new tier rates respectively to rates that
will range up to 50 per cent. Enhanced Oil Recovery and Innovative
Energy Technology Program Royalty relief programs have been retained.

- Conventional Gas Royalties - The New Royalty Framework accepts most
of the royalty review panel's recommendations for increased gas
royalties. They will eliminate several special royalty programs and
the current "tiers" and move to a price and production sensitive
royalty system, however, they will keep the deep gas drilling program
and the "Otherwise Flared Solution Gas Royalty Waiver Program". The
province expects a 10 per cent increase in gas royalties in 2010 -
down from the 14 per cent increase the panel recommended.
>>

Based on our current estimates, the Trust expects that the total
corporate royalties payable will increase by approximately 10 per cent in
2009. This estimate will vary based on prices, production decline of existing
wells and performance and location of new wells drilled. The 10 per cent
increase in royalties payable which equates to approximately a two per cent
increase in the Trust's royalty rate takes into account that 30 per cent of
the Trust's production is outside the Province of Alberta. The royalty change
in 2009 on a property by property basis is highly variable with decreased
royalties on some properties, primarily shallow gas wells, and a doubling of
royalties on Alberta high rate oil production properties. The New Alberta
Royalty Framework will impact future drilling in order for the Trust to
maintain acceptable rates of return on its capital deployed.
The Trust reviews all of its capital expenditures on a project by project
basis; with higher royalties in the Province of Alberta, projects previously
deemed economic may no longer meet the Trust's investment objectives. Already,
the Trust has cancelled a $4 million investment in northern Alberta,
re-allocating the money to British Columbia where it believes it can get a
better return on its investment. The Trust will be reviewing the proposals in
detail in order to assess the full impact to the Trust's future cash flows and
investment opportunities and determine ways in which it can mitigate the
negative impact.

Federal Government's Trust Tax Legislation

In April 2007, the Federal Government included the proposed Trust
Taxation in the Federal Budget ("Bill C-52"). Bill C-52 received a third
reading on June 12, 2007 and then Royal Assent on June 22, 2007, thus fully
enacting the tax measures. As a result the Trust recorded a $35.6 million one
time increase in earnings and a corresponding decrease to its future income
tax liability as a result of timing differences within the Trust that have not
been previously recognized. The initial recognition of $35.6 million comprises
$24.7 million for pre-2007 generated temporary differences and $10.9 million
for temporary differences relating to the current year. This amount was
recorded in the second quarter results and is reflected in the 2007
year-to-date results.
Our Board of Directors and management continue to review the impact of
this tax on our business strategy. We expect future technical interpretations
and details will further clarify the legislation. At the present time, ARC
believes that if structural or other similar changes are not made, the
after-tax distribution amount in 2011 to taxable Canadian investors will
remain approximately the same, however, will decline for both tax-deferred
Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign investors.

Climate Change Programs

On March 8, 2007, the Alberta government introduced legislation to reduce
greenhouse gas emission intensity. Bill 3 states that facilities emitting more
than 100,000 tonnes of greenhouse gases per year must reduce their emissions
intensity by 12 per cent over the average emissions levels of 2003, 2004 and
2005; if they are not able to do so, these facilities are required to pay
$15 per tonne for every tonne above the 12 per cent target, effective as of
July 1, 2007. At this time, the Trust has determined that the impact of this
legislation would be minimal based on ARC's existing facilities ownership.
In April 2007, the Federal Government announced a new climate change plan
that calls for greenhouse gas emissions to be reduced by 20 per cent below
current levels by 2020. Firms may employ the following strategies to achieve
the targets. They will be able to:

<<
- make in-house reductions;
- take advantage of domestic emissions trading;
- purchase offsets;
- use the Clean Development Mechanism under the Kyoto Protocol; and,
- invest in a technology fund.
>>

The Trust is waiting for additional information so as to fully assess
what impact, if any, this new legislation will have on its operations.

United States Proposed Changes to Qualifying Dividends

A bill was introduced into United States Congress on March 23, 2007 that
could deny qualified dividend income treatment to the distributions made by
the Trust to its U.S. unitholders. The bill is in the first step of the
legislative process and it is uncertain whether it will eventually be passed
into law in its current form. If the bill is passed in its current form,
distributions received by U.S. unitholders would no longer qualify for the
15 per cent qualified dividend tax rate.

<<
Financial Highlights
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
(CDN$ millions, September 30 September 30
except per unit % %
and volume data) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Cash flow from operating
activities(1) 179.6 203.4 (12) 531.2 574.6 (8)
Cash flow from operating
activities per unit(1) 0.85 0.99 (14) 2.54 2.82 (10)
Net income 120.8 116.8 3 389.0 403.4 (4)
Distributions per unit(2) 0.60 0.60 - 1.80 1.80 -
Distributions as a per
cent of cash flow from
operating activities 70 60 17 70 63 11
Daily production
(boe/d)(3) 61,108 62,178 (2) 62,296 62,851 (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters; refer to Non-GAAP Measures.
(2) Based on the number of trust units outstanding at each cash
distribution record date.
(3) Reported production amount is based on company interest, which
includes royalty interest and is before royalty burdens. Where
applicable in this MD&A natural gas has been converted to barrels of
oil equivalent ("boe") based on 6 mcf: 1 bbl. The boe rate is based
on an energy equivalent conversion method primarily applicable at the
burner tip and does not represent a value equivalent at the well
head. Use of the term "boe" in isolation may be misleading.
>>

Net Income

Net income in the third quarter of 2007 was $120.8 million ($0.58 per
unit), an increase of $4 million from $116.8 million ($0.58 per unit) in the
third quarter of 2006. A $25.7 million gain on foreign exchange as well as a
$4.3 million decrease in royalties more than offset decreased revenues and
increased costs for the Trust.

Cash Flow from Operating Activities

Cash flow from operating activities was $179.6 million in the third
quarter of 2007, a 12 per cent decrease from $203.4 million recorded in the
third quarter of 2006. The decrease in third quarter cash flow from operating
activities was attributed to a $5.4 million volume variance, a $6.7 million
price variance, a $5.2 million increase in operating costs that were partially
offset by a $4.3 million decrease in royalties. In addition, the Trust had a
$7 million increase in non-cash working capital and other items that further
decreased the cash flow from operating activities in the quarter.

Following is a summary of variances in cash flow from operating
activities from 2006 to 2007:

<<
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
$ $ Per % Vari- $ $ Per % Vari-
Millions Unit ance Millions Unit ance
-------------------------------------------------------------------------
2006 Cash flow from
operating activities 203.4 0.99 574.6 2.82
-------------------------------------------------------------------------
Volume variance (5.4) (0.03) (3) (8.2) (0.04) (1)
Price variance (6.7) (0.03) (3) (15.9) (0.08) (3)
Cash gains on risk
management contracts(1) (1.6) (0.01) (1) (4.1) (0.02) (1)
Royalties 4.3 0.02 2 12.9 0.06 2
Expenses:
Operating(2) (5.2) (0.03) (3) (20.9) (0.10) (4)
Transportation (0.1) - - (1.7) (0.01) -
Cash G&A (1.5) (0.01) (1) (8.3) (0.04) (1)
Interest and cash taxes (0.7) - - (4.3) (0.02) (1)
Realized foreign
exchange gain/(loss) 0.1 - - (0.8) - -
Weighted average trust
units - (0.02) - - (0.07) -
Non-cash and other
items(3) (7.0) (0.03) (3) 7.9 0.04 1
-------------------------------------------------------------------------
2007 Cash flow from
operating activities 179.6 0.85 (12) 531.2 2.54 (8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Represents cash gains on risk management contracts including cash
settlements on termination of risk management contracts.
(2) Excludes non-cash portion of the Whole Unit Plan expense recorded in
operating costs.
(3) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
>>

Production

Production volume averaged 61,108 boe per day in the third quarter of
2007, down slightly from 62,178 boe per day during the third quarter of 2006.
The Trust experienced significant production losses during the third quarter
due in part to planned turnarounds but also due to unplanned compressor
failures, power outages and unplanned turnarounds on some of our non-operated
properties. As of September 30, 2007, most of these items have been resolved
and production has resumed to normal levels. At the end of the third quarter
the Trust has approximately 2,500 boe per day of volumes that are scheduled to
come on production during the fourth quarter. In addition, fourth quarter
production will benefit by an estimated 350 boe per day from a third quarter
property acquisition of $24.8 million that closed on September 13, 2007. We
have maintained our full year 2007 production guidance at approximately
63,000 boe per day.
Throughout the first nine months of 2007, the Trust has experienced
production restrictions in the northern Alberta and British Columbia areas as
a result of gas plant capacity constraints. A new third party plant is
scheduled to be on-line in the fourth quarter of 2007 to handle existing
excess production as well as additional development production from both
Dawson and Pouce South areas. As of September 30, the Trust had three
horizontal wells in Dawson that were waiting to be brought on production. It
is anticipated that these wells will be brought on production in the fourth
quarter when there is additional processing capacity for the resulting
production. The expected date for the gas plant to commence operations is
approximately mid November 2007. The Trust expects to see at least 1,200 boe
per day in incremental production once these wells come on production. This
amount is included in the 2,500 boe per day of incremental fourth quarter
production quoted above.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During the third quarter of 2007, the Trust
drilled 151 gross wells (113 net wells) on operated properties with a 100 per
cent success rate; 30 gross oil wells and 121 gross natural gas wells.

<<
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
% %
Production(1) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Crude oil (bbl/d) 28,437 29,108 (2) 28,682 28,852 (1)
Natural gas (mmcf/d) 173.3 173.4 - 177.6 178.9 (1)
NGL (bbl/d) 3,795 4,166 (9) 4,013 4,178 (4)
-------------------------------------------------------------------------
Total production (boe/d) 61,108 62,178 (2) 62,296 62,851 (1)
-------------------------------------------------------------------------
% Natural gas production 47 46 48 47
% Crude oil and liquids
production 53 54 52 53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.

The following table summarizes the Trust's production by core area:

-------------------------------------------------------------------------
Three Months Ended September 30, 2007
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,694 1,522 29.6 1,234
Northern AB & BC 19,106 5,776 71.2 1,475
Pembina & Redwater 13,497 9,411 18.7 971
S.E. AB & S.W. Sask. 9,679 1,008 52.0 10
S.E. Sask. & MB 11,132 10,720 1.8 105
-------------------------------------------------------------------------
Total 61,108 28,437 173.3 3,795
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Three Months Ended September 30, 2006
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 8,029 1,537 30.9 1,344
Northern AB & BC 18,354 6,308 64.0 1,373
Pembina & Redwater 14,063 9,443 19.6 1,357
S.E. AB & S.W. Sask. 10,551 1,090 56.7 10
S.E. Sask. & MB 11,181 10,730 2.2 82
-------------------------------------------------------------------------
Total 62,178 29,108 173.4 4,166
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast, S.W. is
southwest.

Commodity Prices Prior to Hedging
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
% %
Benchmark Prices 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
AECO gas (CDN$/mcf)(1) 5.61 6.03 (7) 6.81 7.19 (5)
WTI oil (US$/bbl)(2) 75.33 70.55 7 66.22 68.29 (3)
USD/CAD foreign
exchange rate 0.96 0.90 7 0.91 0.89 2
WTI oil (CDN$/bbl) 78.70 78.80 - 72.95 77.14 (5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Although oil prices have achieved record highs throughout the quarter,
the strengthening of the Canadian dollar relative to the U.S. dollar was
responsible for eroding the gains in the U.S. dollar WTI price by decreasing
the price of oil in Canadian dollar terms. The price of oil in U.S. dollars
increased by seven per cent in the third quarter of 2007 as compared to the
third quarter of 2006 while the price of oil in Canadian dollars was
essentially unchanged. ARC's realized oil price in the third quarter of 2007
was $73.40 per barrel, a two per cent increase over the $71.84 per barrel
received in the third quarter of 2006 due to minor changes in quality
differentials. Subsequent to quarter end both the price of oil and the
Canadian dollar continued to strengthen in relation to the U.S. dollar.
Investors should monitor both factors in assessing future revenues of the
Trust.
Natural gas prices weakened in the third quarter of 2007 with the Alberta
AECO Hub monthly posting averaging $5.61 per mcf as compared to $6.03 per mcf
for the comparable period of 2006. The Trust's realized price of $5.52 per mcf
in the third quarter of 2007 was 10 per cent lower than the $6.10 per mcf
price realized by the Trust in the third quarter of 2006. The Trust's realized
gas price is based on prices received at the various markets in which the
Trust sells its natural gas. ARC's natural gas sales portfolio consists of gas
sales priced at the AECO monthly index, the AECO daily spot market, eastern
and mid-west United States markets and a portion to aggregators.
Prior to hedging activities, ARC's total realized commodity price was
$53.28 per boe in the third quarter of 2007, down two per cent from the
$54.45 per boe received prior to hedging in the third quarter of 2006. Given
the Trust's balanced production mix, the increases in oil prices partially
offset the decreases in natural gas prices during the period.

<<
The following is a summary of realized prices:

-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
% %
ARC Realized Prices 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Oil ($/bbl) 73.40 71.84 2 66.45 67.68 (2)
Natural gas ($/mcf) 5.52 6.10 (10) 6.90 6.97 (1)
NGLs ($/bbl) 55.64 56.60 (2) 52.07 54.67 (5)
-------------------------------------------------------------------------
Total commodity revenue
before hedging ($/boe) 53.28 54.45 (2) 53.61 54.54 (2)
Other revenue ($/boe) 0.13 0.14 (7) 0.12 0.12 -
-------------------------------------------------------------------------
Total revenue before
hedging ($/boe) 53.41 54.59 (2) 53.73 54.66 (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Revenue

Revenue for the third quarter of 2007 was down four per cent at
$300.2 million as compared with $312.3 million for the third quarter of 2006.
Increased oil prices were offset by lower natural gas prices and lower volumes
in the quarter.

A breakdown of revenue is as follows:

-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
% %
Revenue ($ millions) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Oil revenue 192.0 192.4 - 520.3 533.0 (2)
Natural gas revenue 88.1 97.4 (10) 334.3 340.3 (2)
NGLs revenue 19.4 21.7 (11) 57.0 62.4 (9)
-------------------------------------------------------------------------
Total commodity revenue 299.5 311.5 (4) 911.6 935.7 (3)
Other revenue 0.7 0.8 (13) 2.0 2.2 (9)
-------------------------------------------------------------------------
Total revenue
before hedging 300.2 312.3 (4) 913.6 937.9 (3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Risk Management and Hedging Activities

The Trust hedges crude oil prices, natural gas prices and the Canadian
versus U.S. dollar exchange rate with the objective of protecting cash flows
and distributions to unitholders.
On a forward-looking basis ARC continues to add to its hedging position
for both crude oil and natural gas production. During the quarter ARC layered
on additional protection on crude oil to the end of 2008 and additional
natural gas positions through to the first quarter of 2008.
In addition to these normal course transactions, ARC has entered into an
energy equivalent swap in order to shift its price exposure to be more heavily
weighted towards crude oil for the period of April 1 through October 31, 2008.
Through the use of financial contracts, ARC has rebalanced its price exposure
from a forecasted 50:50 to a 52:48 oil-gas weighting. ARC achieved this
rebalancing by selling AECO natural gas at $7.10 per GJ and buying crude oil
at CDN$73.95 per barrel. A summary of all hedged volumes and prices for oil,
natural gas and related foreign exchange are detailed in the table below. The
details of these transactions are provided in note 9 in the Notes to the
Unaudited Consolidated Financial Statements.
On crude oil production ARC has hedged approximately 44 per cent of
forecast oil production in the fourth quarter of 2007, 35 per cent of
production through the first half of 2008, and 25 per cent of production for
the second half of 2008. For natural gas production ARC has protected
approximately 22 per cent of forecasted production during the fourth quarter
of 2007, 10 per cent for the first quarter of 2008, and 10 per cent for the
period from April 1 through October 31, 2008.
The following is a summary of the Trust's positions for crude oil,
natural gas and related foreign exchange for the next twelve months as at
September 30, 2007.

<<
-------------------------------------------------------------------------
Hedge Positions
as at September 30, 2007 (1)(2)
Q4 2007 Q1 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 86.47 8,500 85.23 11,000
Bought Put 70.00 14,000 64.21 11,000
Sold Put 58.57 14,000 51.39 9,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 10.64 20,986 10.64 31,652
Bought Put 7.16 42,981 7.11 31,652
Sold Put 5.05 25,621 4.76 10,551
-------------------------------------------------------------------------
Foreign Exchange CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.1397 55.2 1.0750 3.0
Sold Put 1.1096 54.0 1.0300 3.0
Swap 1.1400 4.8
-------------------------------------------------------------------------

Q2 2008 Q3 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl Bbl/day
-------------------------------------------------------------------------
Sold Call 85.23 11,000 85.63 8,000
Bought Put 64.21 11,000 63.91 8,000
Sold Put 51.39 9,000 51.07 7,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 9.00 20,000 9.00 20,000
Bought Put 7.00 20,000 7.00 20,000
Sold Put 5.75 10,000 5.75 10,000
-------------------------------------------------------------------------
Foreign Exchange CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.0750 3.0 1.0750 3.0
Sold Put 1.0300 3.0 1.0300 3.0
-------------------------------------------------------------------------

Q4 2008 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl Bbl/day
-------------------------------------------------------------------------
Sold Call 85.63 8,000 90.00 5,000
Bought Put 63.91 8,000 55.00 5,000
Sold Put 51.07 7,000 40.00 5,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 9.00 6,739 - -
Bought Put 7.00 6,739 - -
Sold Put 5.75 3,370 - -
-------------------------------------------------------------------------
Foreign Exchange CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.0750 3.00 - -
Sold Put 1.0300 3.00 - -
-------------------------------------------------------------------------

(1) The prices and volumes noted above represents averages for several
contracts. The average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to the Trust's website at www.arcenergytrust.com under
"Hedging Program" within the "Investor Relations" section for details
on the Trust's hedging positions as of September 30, 2007.
>>

The above table should be interpreted as follows using the Q4 2007 Crude
Oil Hedges as an example. To accurately analyze the Trust's hedge position,
contracts need to be modeled separately as using average prices and volumes
may be misleading.

<<
- If the market price is below $58.57, ARC will receive $70 less the
difference between $58.57 and the market price on 14,000 barrels per
day. For example if the market price is $58.55, the Trust will
receive $69.98 on 14,000 barrels per day.
- If the market price is between $58.57 and $70, ARC will receive $70
on 14,000 barrels per day.
- If the market price is between $70 and $86.47, ARC will receive the
market price on 14,000 barrels per day.
- If the market price exceeds $86.47, ARC will receive $86.47 on 8,500
barrels per day and the market price for the remaining 5,500 hedged
volumes.
>>

In light of the significant increase in value of the Canadian dollar
during the last 12 months, ARC implemented a program to lock in exchange rates
on future principal repayments on U.S. dollar denominated senior secured
notes. These transactions effectively lock in the unrealized foreign exchange
gains on the U.S. denominated debt. Although the unrealized foreign exchange
gains will continue to fluctuate quarter-to-quarter with changes in the
exchange rate, these financial transactions have effectively fixed the
economic gains of the change in exchange rates from the rate at which the U.S.
denominated debt was issued and the rate at which the future payments have
been committed. At the end of the quarter ARC had $223 million of U.S.
denominated senior secured debt outstanding requiring annual principal
repayments of varying amounts extending until December 15, 2017. As at the
quarter end, ARC had locked in the foreign exchange rate for a total of
US$62.6 million of its principal repayments in years 2014 through 2017 at an
average rate with the Canadian dollar slightly greater than par (1.00
USD/CAD). The details of these transactions are provided in the financial
note.
For a complete summary of the Trust's oil, natural gas and foreign
exchange hedges, please refer to "Hedging Program" under the "Investor
Relations" section of the Trust's website at www.arcenergytrust.com.

Gain or Loss on Risk Management Contracts

Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
The Trust recorded a realized cash gain on risk management contracts of
$8 million in the third quarter of 2007 compared to a gain of $9.6 million
recorded in for the same period of 2006. The Trust realized gains of
$8.9 million on natural gas prices and $2.2 million on foreign exchange
contracts which were partially offset by $2.9 million in losses realized on
the Trust's oil contracts as well as a loss of $0.2 million on interest rate
positions.
The total unrealized gain of $2.1 million was due mostly to a weakening
of forward natural gas prices that have resulted in unrealized gains of
$4.6 million in natural gas financial positions through to October of 2008 and
a gain on the Trust's interest rate swap of $1.9 million. These gains have
been offset by unrealized losses for the Trust's oil contracts of $2.5 million
due to an increase in crude oil prices, which reduces the value of crude oil
protection and an unrealized loss on foreign exchange contracts that were
entered into during the quarter to pay off long-term US dollar debt
commitments ($1.9 million).
The following is a summary of the total gain (loss) on risk management
contracts for the third quarter and year to date of 2007:

<<
-------------------------------------------------------------------------
Interest Q3 Q3
Risk Management Contracts Crude Oil Natural & Foreign 2007 2006
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) (2.9) 8.9 2.0 8.0 9.6
Unrealized gain (loss)
on contracts(2) (2.5) 4.6 - 2.1 0.5
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts (5.4) 13.5 2.0 10.1 10.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Interest YTD YTD
Risk Management Contracts Crude Oil Natural & Foreign 2007 2006
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) 2.8 10.4 2.1 15.3 19.4
Unrealized gain (loss)
on contracts(2) (17.7) 4.6 5.1 (8.0) (8.5)
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts (14.9) 15.0 7.2 7.3 10.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.

Operating Netbacks

The Trust's operating netback, after realized hedging gains, decreased by
five per cent to $35.52 per boe in the third quarter of 2007 compared to
$37.50 per boe in the same period of 2006. The decrease in netbacks in 2007 is
primarily due to higher operating costs and lower realized hedging gains.
These amounts were partially offset by lower royalty costs.
The components of operating netbacks are shown below:

-------------------------------------------------------------------------
Crude Heavy Q3 2007 Q3 2006
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 74.40 51.23 5.52 55.64 53.28 54.45
Other revenue - - - - 0.13 0.14
-------------------------------------------------------------------------
Total revenue 74.40 51.23 5.52 55.64 53.41 54.59
Royalties (11.75) (4.35) (0.87) (15.44) (8.76) (9.34)
Transportation (0.10) (1.21) (0.20) - (0.65) (0.60)
Operating costs(1) (12.32) (11.85) (1.30) (8.19) (9.93) (8.82)
-------------------------------------------------------------------------
Netback prior to hedging 50.23 33.82 3.15 32.01 34.07 35.83
Realized gain (loss) on
risk management
contracts (0.28) - 0.56 - 1.45 1.67
-------------------------------------------------------------------------
Netback after hedging 49.95 33.82 3.71 32.01 35.52 37.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
YTD YTD
Crude Heavy 2007 2006
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 67.39 47.00 6.90 52.07 53.61 54.54
Other revenue - - - - 0.12 0.12
-------------------------------------------------------------------------
Total revenue 67.39 47.00 6.90 52.07 53.73 54.66
Royalties (10.53) (4.00) (1.28) (14.12) (9.28) (9.95)
Transportation (0.31) (1.22) (0.20) - (0.73) (0.62)
Operating costs(1) (11.73) (12.73) (1.26) (7.74) (9.51) (8.27)
-------------------------------------------------------------------------
Netback prior to hedging 44.82 29.05 4.16 30.21 34.21 35.82
Realized gain on risk
management contracts 0.71 - 0.22 - 0.93 1.13
-------------------------------------------------------------------------
Netback after hedging 45.53 29.05 4.38 30.21 35.14 36.95
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
>>

Royalties decreased to $8.76 per boe in the third quarter of 2007
compared to $9.34 per boe in the same period of 2006. Royalties as a
percentage of pre-hedged commodity revenue net of transportation costs
decreased to 16.6 per cent compared to 17.3 per cent in the third quarter of
2006. The decrease in royalty rates is due to approximately $2.3 million of
credits for prior periods for Gas Cost Allowance recorded in the third quarter
along with credits received for the Trust's BC gas production. The Trust
expects fourth quarter royalty rates to return to normal levels of
approximately 18 percent of pre-hedged commodity revenue net of transportation
costs.
Transportation costs in 2007 continue to exceed prior year costs as a
result of the ongoing challenges in Saskatchewan where shipping restrictions
are in place for the Enbridge pipeline. Third quarter 2007 transportation
costs decreased to $0.65 per boe from $0.72 per boe in the second quarter of
2007 as natural declines in the area decreased our trucking requirements;
however, the Trust is still required to truck any new production that exceeds
our historical capacity for the Enbridge pipeline. Investors can expect
transportation prices to increase again once the winter drilling program
begins and new production levels increase. An expansion of the Enbridge
pipeline is expected to be completed sometime in early 2008.
Operating costs increased to $9.93 per boe compared to $8.82 per boe in
the third quarter of 2006. Total operating costs in the third quarter of 2007
increased by $5.3 million compared to the third quarter of 2006. This increase
is partially due to increased labor costs for field staff and some service
providers particularly in Northern Operations. In addition, the Trust has
increased electricity consumption as a result of well re-activations in the
Redwater and NPCU areas. The Trust incurred $1.3 million for an unanticipated
injection pump repair in the Berrymoor area and unbudgeted compressor repairs
in the Delburne, Pouce Coupe and Gilby areas. Acquisitions completed in the
fourth quarter of 2006 and the first nine months of 2007 have increased
operating costs by approximately $1 million in the third quarter of 2007.
There is a high percentage of fixed operating costs for the Trust's properties
resulting in a trend of increased operating costs on a per boe basis as the
properties' production declines over time. The Trust is revising its full year
guidance for operating costs to approximately $9.50 per boe based on annual
production of approximately 63,000 boe per day.

General and Administrative Expenses and Incentive Compensation

Cash G&A before incentive compensation and net of overhead recoveries on
operated properties increased to $8.4 million in the third quarter of 2007
from $6.9 million in the same period of 2006. Increases in cash G&A expenses
for 2007 were due to additional staff and higher compensation costs. On a per
boe basis, third quarter cash G&A costs excluding the whole unit plan
increased 23 per cent to $1.49 per boe in 2007 from $1.21 per boe in 2006 as a
result of higher cash G&A costs and a decrease in production volumes.
Year-to-date G&A costs include a payment under the Whole Unit Plan in the
second quarter that included the first payment for performance units issued
under the Plan in 2004. The cash payment made in April 2007 was $10.5 million
of which $8.3 million was recorded in G&A with the remaining $2.2 million
being recorded to operating costs and capital projects.
The following is a breakdown of G&A and Incentive compensation expense:

<<
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
G&A and Incentive September 30 September 30
Compensation Expense % %
($ millions) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
G&A expenses 12.0 10.6 13 38.1 32.3 (18)
Operating recoveries (3.6) (3.7) (3) (12.0) (8.9) 35
-------------------------------------------------------------------------
Cash G&A expenses before
Whole Unit Plan 8.4 6.9 22 26.1 23.4 12
-------------------------------------------------------------------------
Cash expense -
Whole Unit Plan - - - 8.3 2.7 207
-------------------------------------------------------------------------
Cash G&A expenses
including Whole Unit Plan 8.4 6.9 22 34.4 26.1 32
-------------------------------------------------------------------------
Accrued compensation -
Rights Plan - - - - 2.5 (100)
Accrued compensation -
Whole Unit Plan 3.7 3.4 9 (0.3) 8.4 (104)
-------------------------------------------------------------------------
Total G&A and trust unit
compensation expense 12.1 10.3 17 34.1 37.0 (8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
G&A and Incentive September 30 September 30
Compensation Expense % %
($ per boe) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Cash G&A expenses before
Whole Unit Plan 1.49 1.21 23 1.53 1.36 13
Cash G&A expenses
including Whole Unit Plan 1.50 1.21 24 2.02 1.52 33
Total G&A and trust unit
compensation expense 2.16 1.81 19 2.00 2.16 (7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

A non-cash incentive compensation expense ("non-cash compensation
expense") of $3.7 million was recorded in the third quarter of 2007 that
represents the estimated costs of the Whole Unit Plan for the period.

Rights Plan

The Rights Plan that provides employees, officers and independent
directors the right to purchase trust units at a specified price is being
discontinued. All rights were fully vested and expensed as of March 31, 2007.
At September 30, 2007, 0.2 million rights were outstanding at an average
exercise price of $8.72 per unit.

Whole Unit Incentive Plan ("Whole Unit Plan")

Please refer to our MD&A for the year ended December 31, 2006 for a
detailed description of the Whole Unit Plan that was put in place in 2004 as a
replacement to the Rights Plan. From an accounting perspective, the full cost
of the Whole Unit Plan is reflected in the cash G&A expenses while the cost of
the Rights Plan was represented as a non-cash charge against earnings.
The following table shows the changes to Restricted Trust Units ("RTUs")
and Performance Trust Units ("PTUs") outstanding during the first nine months
of 2007:

<<
-------------------------------------------------------------------------
Whole Unit Plan (units in thousands Number of Number of Total RTUs
and $ millions except per unit) RTUs PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 648 683 1,331
Granted in the period 206 167 373
Vested in the period (191) (110) (301)
Forfeited in the period (25) (26) (51)
-------------------------------------------------------------------------
Balance, end of period(1) 638 714 1,352
-------------------------------------------------------------------------
Estimated distributions to vesting date(2) 179 215 394
-------------------------------------------------------------------------
Estimated units upon vesting after
distributions 817 929 1,746
Performance multiplier(3) - 1.6 -
-------------------------------------------------------------------------
Estimated total units upon vesting 817 1,456 2,273
-------------------------------------------------------------------------
Trust unit price at September 30, 2007 $21.17 $21.17 $21.17
Estimated total value upon vesting $ 17.3 $ 30.8 $ 48.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Based on underlying units before performance multiplier and accrued
distributions.
(2) Represents estimated additional units to be issued equivalent to
estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and was estimated to
be 1.6 at September 30, 2007 based on a weighted average calculation
of all outstanding grants. The performance multiplier is assessed at
each period end based on management's best estimate of the
performance multiplier at the time of vesting.
>>

The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the trust unit price, the number of PTUs to be issued on vesting, and
distributions. Therefore, the expense recorded in the statement of income
fluctuates over time.
Below is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:

<<
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
September 30, 2007 Performance Multiplier
------------------------------
(units thousands and $ millions
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 817 817 817
PTUs - 987 1,974
-------------------------------------------------------------------------
Total units(1) 817 1,804 2,791
-------------------------------------------------------------------------
Trust unit price(2) 21.17 21.17 21.17
Trust unit distributions per month(2) 0.20 0.20 0.20
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting 17.3 38.2 59.1
-------------------------------------------------------------------------
Officers 2.0 12.1 22.2
Directors 1.3 1.3 1.3
Staff 14.0 24.8 35.6
-------------------------------------------------------------------------
Total Payments Under Whole Unit Plan(3) 17.3 38.2 59.1
-------------------------------------------------------------------------
2007 2.3 2.3 2.3
2008 7.8 15.2 22.7
2009 5.2 13.6 22.0
2010 2.0 7.1 12.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Includes an estimate of additional units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumes
future trust unit price of $21.17 per trust unit and distributions of
$0.20 per trust unit per month based on current levels.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in April
and October of each year and at that time is reflected as a reduction
of cash flow from operating activities.
>>

Due to the variability in the future payments under the plan, the Trust
estimates that payments could range from $17.3 million to $59.1 million from
2007 through 2010 based on the current trust unit price, and distribution
levels and a performance multiplier ranging from zero to two.

Interest Expense

Interest expense increased to $8.6 million in the third quarter of 2007
from $7.9 million in the third quarter of 2006 due to an increase in
short-term interest rates and higher debt balances. Interest expense for the
first nine months of 2007 was $27.7 million, an increase of $4.6 million from
$23.1 million in the first nine months of 2006.
The Trust had 61 per cent or $378.6 million of its debt denominated in
U.S. dollars as at September 30, 2007. The Trust's debt balance as reflected
in Canadian dollars has decreased significantly since December 31, 2006. This
is a result of the 12 per cent appreciation in the Canadian dollar as compared
to the U.S. dollar. The Trust had US$420 million in outstanding debt at
December 31 of which US$380 million was still outstanding at September 30,
2007. The Canadian dollar equivalent of the US$380 million debt balance has
decreased by $64.2 million as a result of the appreciation of the Canadian
dollar against the U.S. dollar from December 31, 2006 to September 30, 2007.
Once the foreign exchange impact is taken into consideration, the Trust's
debt balance has remained relatively unchanged from year-end as a result of
funding 91 per cent of the year-to-date capital program with cash flow from
operating activities and proceeds from the Distribution Reinvestment Program
("DRIP"). Debt was used to fund nine per cent of the year-to-date development
capital and 100 per cent of the net acquisitions year-to-date, however, this
was offset largely by the $33 million of proceeds on the sale of the Trust's
long-term investment that were applied against the debt balance in the third
quarter.
As at September 30, 2007, the Trust had $624.4 million of debt
outstanding, of which $223.2 million was fixed at a weighted average rate of
5.06 per cent and $401.2 million was floating at current market rates plus a
credit spread of 60 basis points.

Foreign Exchange Gains and Losses

The Trust recorded a net gain of $25.7 million on foreign exchange
transactions compared to a net loss of $0.2 million for the third quarter of
2006. 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. During the third quarter of
2007, the Canadian dollar reached a 30 year high when compared to the U.S.
dollar. The dollar closed the quarter just over par where one dollar Canadian
purchased $1.004 U.S.
The unrealized gain/loss impacts net income but does not impact cash flow
from operating activities 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 and hedging settlements.

Taxes

In the third quarter of 2007, a future income tax recovery of
$6.3 million was included in income compared to a $9.6 million recovery in the
third quarter of 2006. The third quarter 2006 recovery resulted from the
future tax reductions recorded in the 2006 Federal budget that reduced the
Trust's expected future income tax rate to 29.5 percent from the previous rate
of 33.7 per cent at the beginning of 2006. The corporate income tax rate
applicable to 2007 is 32.1 per cent as compared to the expected future tax
rate of 28.8 per cent based upon enacted tax legislation. If the future tax
reductions announced on October 30, 2007 are enacted by the Canadian
government, corporate taxes may be reduced further to 25 per cent by 2012.
ARC does not anticipate any material cash income taxes will be paid by
the Trust for fiscal 2007. Due to the Trust's structure, currently, both
income tax and future tax liabilities are passed on to the unitholders by
means of royalty and interest payments made by ARC Resources to the Trust.
The Trust is currently assessing various alternatives with respect to the
potential implications of the proposed Trust taxation, therefore the Trust has
not arrived at a final conclusion with respect to future organizational
structure and implications to the Trust. As a result of the enactment of bill
C-52 in the second quarter of 2007, the Trust has recorded a reduction in
future income taxes of $35.6 million related to ARC Energy Trust, as tax pools
were in excess of the net book value of the assets. The initial recognition of
$35.6 million comprises $24.7 million for pre-2007 generated temporary
differences and $10.9 million for temporary differences relating to the
current year. These amounts are reflected in the year-to-date future income
tax recovery of $64.1 million.
Capital taxes were eliminated effective January 1, 2006 pursuant to the
Federal Government budget of May 2, 2006.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate increased to
$16.11 per boe in the third quarter of 2007 from $15.34 per boe in the third
quarter of 2006. Year-to-date, the DD&A rate has increased six per cent to
$16.26 per boe as compared to $15.37 in 2006. The higher DD&A rate is driven
by an increase in the property, plant and equipment ("PP&E") value on the
Trust's balance sheet along with an increase in the future development costs
and a slight decrease in proved reserves recorded in the Trust's January 1,
2007 reserve report.
A breakdown of the DD&A rate is as follows:

<<
-------------------------------------------------------------------------
DD&A Expense Three Months Ended Nine Months Ended
September 30 September 30
($ millions except per % %
boe amounts) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Depletion of oil & gas
assets(1) 87.7 85.1 3 267.8 256.0 5
Accretion of asset
retirement obligation(2) 2.9 2.6 12 8.7 7.8 12
-------------------------------------------------------------------------
Total DD&A expense 90.6 87.7 3 276.5 263.8 5
-------------------------------------------------------------------------
DD&A expense per boe 16.11 15.34 5 16.26 15.37 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the PP&E balance and is being
depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.

Capital Expenditures and Acquisitions

Total capital expenditures, excluding acquisitions and dispositions,
totaled $131.9 million in the third quarter of 2007 compared to $104.9 million
in the third quarter of 2006. This amount was incurred on drilling and
completions, geological, geophysical and facilities expenditures, and the
purchase of undeveloped acreage. Included in the $131.9 million expenditures
is $33 million spent on the purchase of undeveloped acreage in and around
existing core areas. The Trust also spent $27.3 million on minor net property
acquisitions in the third quarter of 2007 as compared to $8.4 million for the
same period in 2006.

A breakdown of capital expenditures and net acquisitions is shown below:

-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Capital Expenditures September 30 September 30
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
Geological and geophysical 2.9 2.2 11.9 7.7
Land 33.0 1.4 34.9 20.6
Drilling and completions 73.4 76.2 154.4 161.4
Plant and facilities 21.1 24.6 54.1 51.1
Other capital 1.5 0.5 2.6 1.8
-------------------------------------------------------------------------
Total capital expenditures 131.9 104.9 257.9 242.6
-------------------------------------------------------------------------
Producing property
acquisitions (1) 27.3 8.4 42.0 47.5
Producing property
dispositions (1) - - (4.6) (8.7)
-------------------------------------------------------------------------
Total capital expenditures and
net acquisitions 159.2 113.3 295.3 281.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Value is net of post-closing adjustments.

Approximately 38 per cent of the $131.9 million capital program was
financed with cash flow from operating activities in the third quarter of 2007
compared to 75 per cent in the same period of 2006. The remainder of the
program was financed through proceeds from the 2007 distribution reinvestment
program and employee rights plan as well as debt.

-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30, 2007 September 30, 2006
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 131.9 27.3 159.2 104.9 8.4 113.3
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating
activities (1) 38% - 31% 75% 39% 69%
Proceeds from DRIP
and Rights Plan 21% - 17% 25% - 26%
Debt 41% 100% 52% - 61% 5%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30, 2007 September 30, 2006
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 257.9 37.4 295.3 242.6 38.8 281.4
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating
activities(1) 58% - 50% 84% - 72%
Proceeds from DRIP
and Rights Plan 33% - 29% 16% 100% 28%
Debt 9% 100% 21% - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters, refer to Non-GAAP Measures.
>>

Long-Term Investment

During the second quarter of 2007, the Trust sold its investment in the
shares of a private company that was involved in the acquisition of oil sands
leases. The transaction closed on June 25, 2007. The Trust recorded a cash
gain of $13.3 million with total proceeds of $33.3 million recorded as part of
cash flow from investing activities.

Asset Retirement Obligation and Reclamation Fund

At September 30, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $170.9 million as compared to $177.3 million at
December 31, 2006 for future abandonment and reclamation of the Trust's
properties. The ARO balance has been reduced by $14.6 million for reclamation
spending in the first nine months of 2007 ($2.7 million for the third quarter
of 2007). This amount has been offset by accretion of $8.7 million
($2.9 million for the third quarter of 2007). In addition, a net decrease to
the liability of $0.5 million was recorded relating to a change in estimate
net of development activities in the period. The Trust did not record a gain
or loss on actual abandonment expenditures incurred as the costs closely
approximated the liability value included in the ARO.
Reclamation spending for the first nine months of 2007 has been 100 per
cent funded through the reclamation fund. The Trust performs an analysis
annually to ensure that sufficient funds are being contributed to the
reclamation fund to fund all future reclamation expenditures. The Trust's
spending profile for reclamation in 2007 has been influenced by the Alberta
Energy and Utilities Board ("AEUB")'s inactive well program whereby all
companies are required to complete stringent new well supsension standards on
their inactive wells. Of the Trust's $14.6 million reclamation expenditures in
2007, approximately $12 million was incurred in order to comply with this
legislation. These costs were all included in the Trust's ARO model, however,
the AEUB regulation required the Trust to accelerate the timing of the
expenditures that were originally forecasted to take place in years 2007
through to 2016. The Trust expects 2008 abandonment and reclamation costs to
return to normal levels of approximately $3 million per year.

<<
Capitalization, Financial Resources and Liquidity

A breakdown of the Trust's capital structure is as follows as at September
30, 2007 and December 31, 2006:

-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per unit and September December
per cent amounts) 30, 2007 31, 2006
-------------------------------------------------------------------------
Revolving credit facilities 401.2 426.1
Senior secured notes 223.2 261.0
Working capital deficit(1) 75.4 52.0
-------------------------------------------------------------------------
Net debt obligations 699.8 739.1

Trust units outstanding and issuable for
exchangeable shares (millions) 211.7 207.2
Market price per unit at end of period 21.17 22.30
Market value of trust units and exchangeable
shares at end of period 4,481.7 4,620.0
Total capitalization (2) 5,181.5 5,359.1
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 13.5% 13.8%
Net debt obligations 699.8 739.1
Cash flow from operating activities(3) 531.2 760.6
Net debt to annualized cash flow from operating
activities 1.0 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) The working capital deficit excludes the balances for risk management
contracts.
(2) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
(3) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters; refer to Non-GAAP Measures.
>>

Net debt levels at September 30, 2007 have decreased since December 31,
2006 primarily as a result of the appreciation of the Canadian dollar
resulting in a lower Canadian dollar value of debt borrowed in U.S. funds. In
aggregate, U.S. denominated debt has generated an unrealized foreign exchange
gain of $66.2 million for the nine months ended September 30, 2007 thus
reducing the September 30, 2007 debt balance by the same amount. As at
September 30, 2007, the Trust had $380 million in U.S. denominated debt. The
Trust has entered into forward contracts to lock in the Canadian dollar
equivalent amounts for its U.S. denominated debt repayments. Please refer to
the Risk Management and Hedging Activities section for further details.
The Trust has a syndicated three year revolving credit facility allowing
for maximum borrowing of up to $800 million. This was increased from
$572 million at year-end 2006. The debt is secured by all the Trust's oil and
gas properties and is subject to the same major covenants as the prior credit
facility described in the MD&A as at December 31, 2006.
In addition to the $800 million credit facility, the Trust has issued
senior secured notes that do not reduce the available borrowings under the
credit facility. As at September 30, 2007, the Trust had $403.6 million of
available borrowings under the current credit facility.
During the quarter the Trust entered into treasury rate lock contracts in
order to manage its interest rate exposure on future debt issuances. Treasury
locks enable the Trust to synthetically secure current market rates for a
future fixed rate funding. These instruments hedge only the underlying
treasury yield and not the credit spread applicable to ARC which is determined
at the time of issuance. Based on the transactions completed over the quarter
the Trust has locked in an effective U.S. ten year treasury rate of 4.7624 per
cent on a notional amount of US$125 million.
The Trust intends to finance its $350 million 2007 capital program with
cash flow from operating activities and the proceeds of the distribution
reinvestment program with any remainder being financed with debt.

Unitholders' Equity

At September 30, 2007, there were 211.7 million units issued and issuable
for exchangeable shares, an increase from 207.2 million units from
December 31, 2006. The increase in number of units outstanding is mainly
attributable to the 4.1 million units issued pursuant to the DRIP during 2007
at an average price of $20.26 per unit.
The Trust had 0.2 million rights outstanding as of September 30, 2007
under an employee plan where further rights issuances were discontinued in
2004. The remaining rights may be exercised at an average adjusted exercise
price of $8.72 per unit as at September 30, 2007. All of the rights were fully
vested at March 31, 2007. The contractual life of the rights varies by series
but all will expire on or before March 22, 2009.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any trust
units being issued from treasury. The Trust has made provisions whereby
employees may elect to have trust units purchased for them at prevailing
prices 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. During the third quarter of 2007, the Trust raised proceeds of
$27.5 million and issued 1.4 million trust units pursuant to the DRIP.

Distributions

ARC declared distributions of $125 million ($0.60 per unit), representing
70 per cent of third quarter 2007 cash flow from operating activities compared
to distributions of $121.4 million ($0.60 per unit), representing 60 per cent
of cash flow from operating activities in the third quarter of 2006. The
remaining 30 per cent of third quarter 2007 cash flow from operating
activities ($54.6 million) was used to fund 38 per cent of ARC's 2007 third
quarter capital expenditures and make contributions, including interest, to
the reclamation funds ($5 million).
Monthly distributions for the third quarter of 2007 were $0.20 per unit.
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 items that may be deducted from cash flow from operating activities
to arrive at distributions to unitholders and the methodology used to
determine distributions is detailed in the Trust's December 31, 2006 MD&A.
Cash flow from operating activities and distributions in total and per
unit were as follows:

<<
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30 September 30
Cash flow from operating % %
activities and 2007 2006 Change 2007 2006 Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from operating
activities 179.6 203.4 (12) 0.85 0.99 (14)
Reclamation fund
contributions(1) (5.0) (3.3) 48 (0.02) (0.02) -
Capital expenditures
funded with cash flow
from operating
activities (49.6) (78.7) (37) (0.24) (0.38) (37)
Discretionary debt
repayments - - - - - -
Other(2) - - - 0.01 0.01 200
-------------------------------------------------------------------------
Distributions 125.0 121.4 3 0.60 0.60 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30 September 30
Cash flow from operating % %
activities and 2007 2006 Change 2007 2006 Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------

Cash flow from operating
activities 531.2 574.6 (8) 2.54 2.82 (10)
Reclamation fund
contributions(1) (10.1) (9.7) 3 (0.05) (0.05) -
Capital expenditures
funded with cash
flow from operating
activities (148.9) (203.0) (27) (0.71) (1.00) (29)
Discretionary debt
repayments - - - - - -
Other(2) - - - 0.02 0.03 (33)
-------------------------------------------------------------------------
Distributions 372.2 361.9 3 1.80 1.80 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operated activities are based on weighted average outstanding trust
units in the year plus trust units issuable for exchangeable shares
at year end.

2007 Monthly Distributions

Actual distributions paid and payable in 2007 along with relevant payment
dates are as follows:

-------------------------------------------------------------------------
Ex-distribution Distribution Total
Date Record Date Payment Date Distribution
-------------------------------------------------------------------------
January 29, 2007 January 31, 2007 February 15, 2007 0.20
February 26, 2007 February 28, 2007 March 15, 2007 0.20
March 28, 2007 March 31, 2007 April 16, 2007 0.20
April 26, 2007 April 30, 2007 May 15, 2007 0.20
May 29, 2007 May 31, 2007 June 15, 2007 0.20
June 27, 2007 June 30, 2007 July 16, 2007 0.20
July 27, 2007 July 31, 2007 August 15, 2007 0.20
August 29, 2007 August 31, 2007 September 17, 2007 0.20
September 26, 2007 September 30, 2007 October 15, 2007 0.20
October 29, 2007 October 31, 2007 November 15, 2007 0.20
November 28, 2007 November 30, 2007 December 17, 2007 0.20(*)
December 27, 2007 December 31, 2007 January 15, 2008 0.20(*)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Estimated
>>

Please refer to the Trust's website at www.arcenergytrust.com for details
on distributions dates for 2007.

Taxation of Distributions

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 2007, it is estimated that
distributions paid in the calendar year will be in the range of 95 to 100 per
cent return on capital (taxable) and zero to five per cent return of capital
(tax deferred). For a more detailed breakdown, please visit our website at
www.arcenergytrust.com.

<<
Contractual Obligations and Commitments

The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, and lease
rental obligations. These obligations are of a recurring and consistent nature
and impact cash flows in an ongoing manner. The Trust also has contractual
obligations and commitments that are of a less routine nature as disclosed in
the following table.

Following is a summary of the Trust's contractual obligations and
commitments as at September 30, 2007:

-------------------------------------------------------------------------
Payments Due By Period
-------------------------------------------------------------------------
2008- 2010- There-
($ millions) 2007(5) 2009 2011 after Total
-------------------------------------------------------------------------
Debt repayments(1) 13.6 22.3 439.1 149.4 624.4
Interest payments(2) 4.3 21.4 18.0 20.7 64.4
Reclamation fund contributions(3) 6.0 11.1 9.5 76.2 102.8
Purchase commitments 5.0 8.0 2.9 5.8 21.7
Operating leases 1.3 9.0 4.5 - 14.8
Derivative contract premiums(4) 5.3 9.1 - - 14.4
-------------------------------------------------------------------------
Total contractual obligations 35.5 80.9 474.0 252.1 842.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
(5) Amounts listed for 2007 represent contractual obligations and
committments due in the fourth quarter of 2007.
>>

The above noted debt repayments include the revolving credit facility.
The lenders review the credit facility each year and determine whether they
will extend the revolving periods for another year. In the event that the
credit facility is not extended at any time before the maturity date, the loan
balance will become payable on the maturity date which is April 15, 2010.
The above noted derivative contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has other commitments related to its risk management
program. As the premiums are part of the underlying derivative contract, they
have been recorded at fair market value at September 30, 2007 on the balance
sheet as part of risk management contracts.
The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At any given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2007 capital budget has
been approved by the Board at $360 million and subsequently revised downward
to $350 million due to anticipated cost savings. This commitment has not been
disclosed in the commitment table as it is of a routine nature and is part of
normal course of operations for active oil and gas companies and trusts.
The above noted operating leases include amounts for the Trust's head
office lease. The current lease expires in May 2010. The Trust expects to
commit to a new lease within the next 12 months that will then be reflected in
the commitments table.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the following table does not include any
commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.

Off Balance Sheet Arrangements

The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table above, which were entered into
in the normal course of operations. All leases have been 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 September 30, 2007.

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:

- 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;
- estimated capital expenditures on projects that are in progress;
- estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves that the Trust expects to recover
in the future;
- estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and
foreign exchange rates;
- estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
- estimated future recoverable value of property, plant and equipment
and goodwill.
>>

The Trust has hired individuals and consultants who have the skills
required to make such estimates and ensures that individuals or departments
with the most knowledge of the activity are responsible for the estimates.
Further, past estimates are reviewed and compared to actual results, and
actual results are compared to budgets in order to make more informed
decisions on future estimates.
The ARC leadership team's mandate includes ongoing development of
procedures, standards and systems to allow ARC staff to make the best
decisions possible and ensuring those decisions are in compliance with the
Trust's "code of business conduct and ethics" and "environmental, health and
safety" policies.

Internal Controls Update

ARC is required to comply with Multilateral Instrument 52-109
"Certification of Disclosure in Issuers' Annual and Interim Filings",
otherwise referred to as Canadian SOX ("C-Sox"). The 2007 certificate requires
that the Trust disclose in the interim MD&A any changes in the Trust's
internal control over financial reporting that occurred during the period that
has materially affected, or is reasonably likely to materially affect the
Trust's internal control over financial reporting. The Trust confirms that no
such changes were made to the internal controls over financial reporting
during the first nine months of 2007.

Financial Reporting Update

During 2007, the Trust completed the implementation of the new CICA
Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section
3855, Financial Instruments - Recognition and Measurement, Section 3861,
Financial Instruments - Disclosure and Presentation, and Section 3865, Hedges
that deal with the presentation of equity, recognition and measurement of
financial instruments at fair value, and comprehensive income. As required by
the new standards, adoption has been applied prospectively as at January 1,
2007 and prior periods have not been restated. The adoption of these standards
has had no material impact on the Trust's net income or Cash Flows. See notes
2 and 9 in the Notes to the Unaudited Consolidated Financial Statements for
further details.

During the third quarter of 2006, presentation changes were made to
combine the previously reported accumulated earnings and accumulated cash
distribution figures on the balance sheet into a single deficit balance.
Numbers presented for comparative purposes have been restated to reflect this
change in presentation.

Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if they
result in financial statements that provide more reliable and relevant
information. Changes in policy are applied retrospectively unless it is
impractical to determine the period or cumulative impact of the change.
Corrections of prior period errors are applied retrospectively and changes in
accounting estimates are applied prospectively by including these changes in
net income. In addition, disclosure is required for all future accounting
changes when an entity has not applied a new source of GAAP that has been
issued but is not yet effective.

Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards:
Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures, and Section 3863, Financial Instruments -
Presentation. These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance. This Section is expected to have minimal impact on the Trust's
financial statements.
Sections 3862 and 3863 specify a revised and enhanced disclosure on
financial instruments. Increased disclosure will be required on the nature and
extent of risks arising from financial instruments and how the entity manages
those risks.

Objectives and 2007 Outlook

Sustainability

The Trust believes that maintenance of production and reserves per unit
on an ongoing basis are two key factors to assess the sustainability of an oil
and gas royalty trust. On a quarterly basis, the Trust reviews changes in our
production per unit measures while reserves per unit is analyzed on an annual
basis. The Trust acquires, develops and optimizes oil and natural gas
properties in predominantly mature areas to generate a cash flow stream. Due
to the risks inherent in the oil and gas business, including particularly the
volatility of commodity prices, there can be no assurance that with the
present or even increased levels of capital expenditures, the Trust will be
successful in achieving sustainability.
Due to natural production declines, the Trust must continually develop
its reserves and/or acquire new reserves in an effort to maintain reserves,
production and cash flow from operating activities on which distributions are
paid. The Trust facilitates this by utilizing a portion of cash flow from
operating activities to fund a portion of ongoing capital development
activities and maintaining moderate debt levels. Oil and gas royalty trusts
generally distribute a high percentage of cash flow from operating activities
and hold assets that are depleting and unitholders should expect production,
revenue, cash flow from operating activities and distributions to decline over
the long-term. The Trust has an inventory of internal development prospects
that ARC believes will maintain production at approximately current levels for
a minimum period of two years. The Trust anticipates employing a conservative
distribution policy to provide for cash funding of a portion of ongoing
capital development programs and maintaining low debt levels to facilitate
further growth. The Trust measures its sustainability and success in terms of
per unit distributions, production, reserves, and cash flow from operating
activities in addition to the ability to maintain low debt levels and the
annual replacement of reserves.
Following is a summary of the historical quarterly production per unit,
cash flow from operating activities and distributions as a per cent of cash
flow from operating activities:

<<
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3 Trailing 5
Per Trust Unit Ratios 2007 2007 2007 2006 2006 Quarters
-------------------------------------------------------------------------
Production per unit(1):
Unadjusted 0.29 0.29 0.31 0.31 0.30 -
Debt-adjusted(2) 0.25 0.26 0.27 0.27 0.28 -
Normalized(3) 0.295 0.30 0.31 0.31 0.322 -
-------------------------------------------------------------------------
Cash flow from operations
per unit 0.85 0.86 0.83 0.77 0.99 -
Distributions per unit 0.60 0.60 0.60 0.60 0.60 -
Distributions as a per
cent of cash flow from
operating activities 70 69 71 77 60 69
Per cent of cash flow from
operating activities
retained 30 31 29 23 40 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Represents daily average boe of production per thousand units.
Calculated based on annual daily average production divided by
weighted average trust units outstanding including trust units
issuable for exchangeable shares.
(2) Debt-adjusted indicates that all years as presented have been
adjusted to reflect a nil net debt to capitalization. It is assumed
that additional trust units were issued at a period end price for the
reserves per unit calculation and at an annual average price for the
production per unit calculation in order to reduce the net debt
balance to zero in each year. The debt-adjusted amounts are presented
to enable comparability of quarterly per unit values.
(3) Normalized indicates that all years as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional units were issued (or repurchased) at a quarterly
average price for the production per unit calculation in order to
reduce the net debt balance to 15 per cent of total capitalization
each quarter. The normalized amounts are presented to enable
comparability of quarterly per unit values.
>>

Please refer to the Trust's 2006 year-end MD&A for a summary of the
annual historical debt-adjusted and normalized reserves per unit and reserve
life index on which the Trust assesses performance and sustainability.
Since the third quarter of 2006, the Trust's normalized production per
unit has decreased modestly from 0.322 to 0.295 boe of daily average
production per thousand trust units. The third quarter 2007 production per
unit of 0.295 was negatively impacted by maintenance activities and shut-in
production. Production per unit of 0.295 was achieved and the Trust paid
$615.9 million in distributions ($3.00 per trust unit and 69 per cent of cash
flow from operating activities) over a five quarter time period. The
normalized production per unit is a key measure as it indicates the ability to
generate cash flows from core operations, which in turn impacts the level of
cash that may be distributed to unitholders. The Trust expects to replace
production during the rest of 2007 from internal development opportunities.
To compare the Trust's results with oil and gas companies that retain all
of their cash flow from operating activities to grow production and reserves,
the Trust looks at normalized and distribution-adjusted production per unit
that calculates the total production per initial investment with the
assumption that distributions are reinvested through the DRIP plan.
Consequently, the production per initial investment increases over time as the
investor's number of trust units increases with distribution reinvestment.
Unitholders can replicate this by participating in the DRIP so that the number
of trust units they own increases over time. The Trust's normalized daily
average production per initial investment has increased from 0.329 boe per
thousand trust units in the third quarter of 2006 to 0.336 in the third
quarter of 2007. The increase is attributed to the DRIP factor whereby one
unit purchased on July 1, 2006 would have grown to 1.14 trust units on
September 30, 2007.
The Trust's distribution policy centres on the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The distributions as a per cent of cash flow from
operating activities are indicative of the Trust's commitment to fund a
portion of ongoing development activities with cash flow from operating
activities to enable long-term sustainability. On an annual basis, the Trust's
distributions as a per cent of cash flow from operating activities has
declined over time as the Trust has addressed the issue of long-term
sustainability while setting distribution levels. This has allowed the Trust
to increase the amount of cash available to fund capital expenditures.
Another possible measure of sustainability is the comparison of net
income to distributions. Net income is an accounting measure that incorporates
all costs including depletion expense and other non-cash expenses whereas cash
flow from operating activities measures the cash generated in a given period
before the cost of the associated reserves. As net income is sensitive to
fluctuations in commodity prices, it is expected that there will be deviations
between annual net income and distributions. The following table illustrates
the annual excess or shortfall of distributions to net income.

<<
-------------------------------------------------------------------------
Net Income and Distributions
($ millions except Q3 Q2 Q1 Q4 Q3 Trailing 5
per cent) 2007 2007 2007 2006 2006 Quarters
-------------------------------------------------------------------------

Net income 120.8 184.9 83.3 56.6 116.9 562.5

Distributions 125.0 124.1 123.1 122.3 121.4 615.9
-------------------------------------------------------------------------
Excess (shortfall) of net
income over
distributions (4.2) 60.8 (39.8) (65.7) (4.5) (53.4)
Excess (shortfall) as per
cent of net income (3)% 33% (48)% (116)% (4)% (9)%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Cash flow from operating activities is a GAAP measure and a change from
the non-GAAP measure reported in prior quarters; refer to the Non-GAAP
Measures section in this MD&A.

2007 Guidance

Following is a summary of the Trust's 2007 Guidance issued by way of news
release on November 2, 2006, revised 2007 guidance and actual results for the
third quarter of 2007:

-------------------------------------------------------------------------
Actual to
2007 Revised 2007 Previous September
Guidance Guidance 30, 2007
-------------------------------------------------------------------------
Production (boe/d) 63,000 63,000 62,296
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs (1) 9.50 8.95 9.51
Transportation 0.70 0.70 0.73
G&A expenses - cash (1) 2.15 2.25 2.02
G&A expenses - stock compensation
plans, non-cash (1) 0.10 0.20 (0.02)
Interest (1) 1.70 1.50 1.63
Taxes 0.00 0.00 0.00
Annual capital expenditures
($ millions) (1) 350 360 258
Weighted average trust units
and trust units issuable
(millions) (1) 210 208 209
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Guidance for the noted items was revised in the first and second
quarters of 2007. See the Trust's first and second quarter 2007 MD&A
for further details.

Variances in the 2007 actual results as compared to guidance are as
follows:

- Volumes for the first nine months of 2007 have been lower than
guidance due in part to the Trust not having access to processing
facilities for some of its wells drilled in the Dawson/Pouce areas.
The third party plant is expected to be completed in the fourth
quarter of 2007 and in addition, the Trust is currently looking at
alternate processing facilities to mitigate the production loss in
2007. The Trust expects full year 2007 production to reach
approximately 63,000 boe per day and to average 64,000 boe per day
during the fourth quarter.

- With operating costs higher than guidance for the nine months ended
September 30, 2007 we have newly revised guidance to $9.50 per boe
for the full year 2007. The Trust continues to pursue cost control in
all areas of operations.

- Transportation costs on a year-to-date basis have been higher than
guidance due to an increase in oil volumes being trucked in
Saskatchewan in response to the Enbridge pipeline restrictions.
Annual costs are still expected to be in line with our guidance of
$0.70 per boe.

- Year-to-date Cash G&A expenses were lower than guidance due to the
fact that the full year guidance includes a fourth quarter payment
scheduled for the Whole Unit Plan which will increase the amount of
cash G&A expense for the year. The Trust expects cash G&A to be in-
line with guidance for the full year of 2007.

- Non-cash G&A for stock option plans are expected to be on target for
$0.10 per boe once the fourth quarter accrual is recorded for the
whole unit plan.

- At the second quarter the Trust revised its 2007 guidance for annual
capital expenditures to $350 million as a result of cost savings
anticipated in drilling costs due to a general slow down of Canadian
drilling activity. During the third quarter, the Trust has seen
additional cost savings and now expects to complete budgeted capital
expenditures for approximately $320 million. However an unbudgeted
purchase of undeveloped acreage for $32.7 million occurred in the
third quarter in and around the Trust's existing core areas resulting
in capital exenditure guidance remaining at $350 million for the full
year 2007.

- See the "Objectives and 2007 Outlook" section in the Trust's annual
2006 MD&A for additional discussion on the Trust's key objectives.
>>

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 2006 Annual Report MD&A for a detailed
assessment.

Forward-Looking Statement

This discussion and analysis contains forward-looking statements as to
the Trusts internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions. These
statements represent management's expectations or beliefs concerning, among
other things, future operating results and various components thereof or the
economic performance of ARC Energy Trust ("ARC" or "the Trust"). The
projections, estimates and beliefs contained in such forward-looking
statements are based on management's assumptions relating to the production
performance of ARC's oil and gas assets, the cost and competition for services
throughout the oil and gas industry in 2007 and the continuation of the
current regulatory and tax regime in Canada, and necessarily involve known and
unknown risks and uncertainties, including the business risks discussed in
this MD&A, which may cause actual performance and financial results in future
periods to differ materially from any projections of future performance or
results expressed or implied by such forward-looking statements. Accordingly,
readers are cautioned that events or circumstances could cause results to
differ materially from those predicted. The Trust does not undertake to update
any forward looking information in this document whether as to new
information, future events or otherwise.

<<
Additional Information

Additional information relating to ARC can be found on SEDAR at
www.sedar.com.

QUARTERLY HISTORICAL REVIEW

(CDN $ millions, except per
Unit amounts) 2007 2006
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 300.2 305.6 307.8 292.5
Per unit(1) 1.42 1.46 1.48 1.42
Cash flow from operating
activities(2) 179.6 179.4 172.3 159.4
Per unit - basic(1) 0.85 0.86 0.83 0.77
Per unit - diluted 0.85 0.86 0.83 0.77
Net income 120.8 184.9 83.3 56.6
Per unit - basic(3) 0.58 0.90 0.41 0.28
Per unit - diluted 0.58 0.89 0.41 0.28
Distributions 125.0 124.1 123.1 122.3
Per unit(4) 0.60 0.60 0.60 0.60
Total assets 3,460.8 3,432.8 3,450.1 3,479.0
Total liabilities 1,421.4 1,415.3 1,526.6 1,550.6
Net debt outstanding(5) 699.8 653.9 729.7 739.1
Weighted average units(6) 210.9 209.5 207.9 206.5
Units outstanding and
issuable(6) 211.7 210.2 208.7 207.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 2.9 4.1 4.9 3.7
Land 33.0 1.7 0.2 11.8
Drilling and completions 73.4 25.8 55.1 79.1
Plant and facilities 21.1 16.3 16.8 26.5
Other capital 1.5 0.6 0.5 0.8
Total capital expenditures 131.9 48.5 77.5 121.9
Property acquisitions
(dispositions) net 27.3 10.0 0.2 76.4
Corporate acquisitions(7) - - - 16.6
Total capital expenditures and
net acquisitions 159.2 58.5 77.7 214.9
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,437 28,099 29,520 29,605
Natural gas (mmcf/d) 173.3 176.7 183.0 179.5
Natural gas liquids (bbl/d) 3,795 4,088 4,161 4,144
Total (boe per day 6:1) 61,108 61,637 64,175 63,663
Average prices
Crude oil ($/bbl) 73.40 65.21 60.79 58.26
Natural gas ($/mcf) 5.52 7.38 7.75 6.99
Natural gas liquids ($/bbl) 55.64 52.76 48.04 46.51
Oil equivalent ($/boe) 53.41 54.48 53.29 49.94
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 22.60 23.86 23.02 29.22
Low 19.00 20.78 20.05 19.20
Close 21.17 21.74 21.25 22.30
Average daily volume
(thousands) 503 599 658 1,125
-------------------------------------------------------------------------
-------------------------------------------------------------------------

2006 2005
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 312.3 306.7 318.9 365.3
Per unit(1) 1.52 1.51 1.58 1.89
Cash flow from operating
activities(2) 203.4 182.2 189.0 247.3
Per unit - basic(1) 0.99 0.89 0.93 1.28
Per unit - diluted 0.98 0.89 0.93 1.28
Net income 116.9 182.5 104.1 130.5
Per unit - basic(3) 0.58 0.91 0.52 0.68
Per unit - diluted 0.58 0.91 0.52 0.68
Distributions 121.4 120.6 119.9 115.7
Per unit(4) 0.60 0.60 0.60 0.60
Total assets 3,335.8 3,277.8 3,279.7 3,251.2
Total liabilities 1,371.3 1,339.9 1,434.1 1,415.5
Net debt outstanding(5) 579.7 567.4 598.9 578.1
Weighted average units(6) 205.1 203.7 202.5 193.4
Units outstanding and
issuable(6) 205.7 204.4 203.1 202.0
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 2.2 2.8 2.7 3.0
Land 1.4 14.3 4.9 5.5
Drilling and completions 76.2 29.8 55.4 60.3
Plant and facilities 24.6 10.9 15.6 17.0
Other capital 0.5 0.8 0.5 2.0
Total capital expenditures 104.9 58.6 79.1 87.8
Property acquisitions
(dispositions) net 8.4 2.8 27.6 3.0
Corporate acquisitions(7) - - - 462.8
Total capital expenditures and
net acquisitions 113.3 61.4 106.7 553.6
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,108 27,805 29,651 25,534
Natural gas (mmcf/d) 173.4 178.5 185.0 177.9
Natural gas liquids (bbl/d) 4,166 4,247 4,120 3,943
Total (boe per day 6:1) 62,178 61,803 64,600 59,120
Average prices
Crude oil ($/bbl) 71.84 71.86 59.53 62.12
Natural gas ($/mcf) 6.10 6.35 8.40 12.05
Natural gas liquids ($/bbl) 56.60 54.44 52.91 57.14
Oil equivalent ($/boe) 54.59 54.54 54.86 67.16
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 30.74 28.61 27.51 27.58
Low 25.25 24.35 25.09 20.45
Close 27.21 28.00 27.36 26.49
Average daily volume
(thousands) 614 548 546 653
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes unrealized risk management contracts asset and
liability.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.

CONSOLIDATED BALANCE SHEETS
As at September 30 and December 31 (unaudited)

($CDN millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ - $ 2.8
Accounts receivable 120.6 129.8
Prepaid expenses 15.7 18.4
Risk management contracts (Note 9) 14.7 25.7
-------------------------------------------------------------------------
151.0 176.7
Reclamation funds (Note 3) 26.2 30.9
Property, plant and equipment 3,120.9 3,093.8
Long-term investment (Note 4) - 20.0
Risk management contracts (Note 9) 5.1 -
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,460.8 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 5) $ 169.9 $ 162.1
Distributions payable 41.8 40.9
Risk management contracts (Note 9) 16.0 34.4
-------------------------------------------------------------------------
227.7 237.4
Long-term debt (Note 6) 624.4 687.1
Accrued long-term incentive compensation (Note 15) 11.9 14.6
Asset retirement obligations (Note 7) 170.9 177.3
Risk management contracts (Note 9) 14.7 -
Future income taxes (Note 8) 371.8 434.2
-------------------------------------------------------------------------
Total liabilities 1,421.4 1,550.6
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 17)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 10) 42.1 40.0

UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 2,438.1 2,349.2
Contributed surplus (Note 14) 1.7 2.4
Deficit (Note 12) (446.4) (463.2)
Accumulated other comprehensive income (Note 2) 3.9 -
-------------------------------------------------------------------------
Total unitholders' equity 1,997.3 1,888.4
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,460.8 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
For the three and nine months ended September 30 (unaudited)

Three Months Ended Nine Months Ended
($CDN millions, except September 30 September 30
per unit amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------

Revenues
Oil, natural gas and
natural gas liquids $ 300.2 $ 312.3 $ 913.6 $ 937.9
Royalties (49.2) (53.5) (157.8) (170.7)
-------------------------------------------------------------------------
251.0 258.8 755.8 767.2
Gain (loss) on risk
management contracts
(Note 9)
Realized 8.0 9.6 15.3 19.4
Unrealized 2.1 0.5 (8.0) (8.5)
-------------------------------------------------------------------------
261.1 268.9 763.1 778.1
-------------------------------------------------------------------------

Expenses
Transportation 3.6 3.5 12.4 10.7
Operating 55.7 50.4 161.7 141.9
General and administrative 12.1 10.3 34.1 37.0
Interest on long-term
debt (Note 6) 8.6 7.9 27.7 23.1
Depletion, depreciation
and accretion 90.6 87.7 276.5 263.8
(Gain) loss on foreign
exchange (25.7) 0.2 (66.2) (17.0)
-------------------------------------------------------------------------
144.9 160.0 446.2 459.5
-------------------------------------------------------------------------
Operating income 116.2 108.9 316.9 318.6
Gain on sale of investment
(Note 4) - - 13.3 -
Capital and other taxes - - - (0.3)
Future income tax recovery
(Note 8) 6.3 9.6 64.1 90.8
-------------------------------------------------------------------------
Net income before
non-controlling interest 122.5 118.5 394.3 409.1
Non-controlling interest
(Note 10) (1.7) (1.7) (5.3) (5.7)
-------------------------------------------------------------------------
Net income $ 120.8 $ 116.8 $ 389.0 $ 403.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of
period $ (442.2) $ (393.0) $ (463.2) $ (439.1)
Distributions paid or
declared (Note 13) (125.0) (121.4) (372.2) (361.9)
-------------------------------------------------------------------------
Deficit, end of period
(Note 12) $ (446.4) $ (397.6) $ (446.4) $ (397.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit
(Note 16)
Basic $ 0.58 $ 0.58 $ 1.88 $ 2.01
Diluted $ 0.58 $ 0.58 $ 1.88 $ 2.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME
For the three and nine months ended September 30 (unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
($CDN millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
Net income $ 120.8 $ 116.8 $ 389.0 $ 403.4
Other comprehensive
income, net of tax
Loss on financial
instruments designated
as cash flow hedges(1) (4.0) - (1.0) -
Gain on financial
instruments designated as
cash flow hedges in prior
periods realized in net
income in the current
period(1) 0.8 - 0.2 -
Net unrealized gains
(losses) on
available-for-sale
reclamation funds'
investments(2) 0.2 - (0.2) -
-------------------------------------------------------------------------
Other comprehensive income (3.0) - (1.0) -
-------------------------------------------------------------------------
Comprehensive income $ 117.8 $ 116.8 $ 388.0 $ 403.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other
comprehensive income,
beginning of period 6.9 - - -
Application of initial
adoption - - 4.9 -
Other comprehensive income (3.0) - (1.0) -
-------------------------------------------------------------------------
Accumulated other
comprehensive income,
end of period $ 3.9 - $ 3.9 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Amounts are net of tax recovery of $1.3 million and $0.4
million, respectively, for the three and nine months ended
September 30, 2007.
(2) Nominal future income tax impact.

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and nine months ended September 30 (unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
($CDN millions) 2007 2006 2007 2006
-------------------------------------------------------------------------

CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 120.8 $ 116.8 $ 389.0 $ 403.4
Add items not involving
cash:
Non-controlling interest
(Note 10) 1.7 1.7 5.3 5.7
Future income tax
recovery (Note 8) (6.3) (9.6) (64.1) (90.8)
Depletion, depreciation
and accretion 90.6 87.7 276.5 263.8
Non-cash (gain) loss on
risk management
contracts (Note 9) (2.1) (0.5) 8.0 8.5
Non-cash (gain) loss on
foreign exchange (25.7) 0.1 (66.5) (16.5)
Non-cash trust unit
incentive compensation
(Notes 14 and 15) 4.5 4.1 (0.1) 12.0
Gain on sale of
investment (Note 4) - - (13.3) -
Expenditures on site
restoration and
reclamation (Note 7) (2.7) (3.4) (14.6) (6.6)
Change in non-cash
working capital (1.2) 6.5 11.0 (4.9)
-------------------------------------------------------------------------
179.6 203.4 531.2 574.6
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING
ACTIVITIES
Issuance of long-term debt
under revolving credit
facilities, net 5.1 (21.8) 5.1 (4.1)
Issue of trust units 0.6 3.6 2.9 12.2
Trust unit issue costs - - - (0.3)
Cash distributions paid
(Note 13) (97.9) (95.2) (289.3) (293.9)
Payment of retention bonuses (1.0) (1.0) (1.0) (1.0)
Change in non-cash working
capital 1.5 1.2 1.3 2.7
-------------------------------------------------------------------------
(91.7) (113.2) (281.0) (284.4)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES

Acquisition of petroleum
and natural gas
properties (27.3) (8.4) (38.6) (40.8)
Proceeds on disposition
of petroleum and natural
gas properties - 0.1 1.2 2.1
Capital expenditures (132.5) (104.4) (257.6) (240.8)
Long-term investment (Note 4) - - 33.3 (20.0)
Net reclamation fund
withdrawals (contributions)
(Note 3) 6.1 (1.8) 4.5 (5.5)
Change in non-cash working
capital 30.8 24.7 4.2 15.2
-------------------------------------------------------------------------
(122.9) (89.8) (253.0) (289.8)
-------------------------------------------------------------------------
(DECREASE) INCREASE IN
CASH AND CASH EQUIVALENTS (35.0) 0.4 (2.8) 0.4
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 35.0 - 2.8 -
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ - $ 0.4 $ - $ 0.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2007 and 2006 (unaudited)
(all tabular amounts in $CDN millions, 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 highlighted in note 2. The interim consolidated
financial statement note disclosures do not include all of those
required by Canadian generally accepted accounting principles
("GAAP") applicable for annual consolidated financial statements.
Accordingly, these interim consolidated financial statements should
be read in conjunction with the audited consolidated financial
statements included in the Trust's 2006 annual report.

2. NEW ACCOUNTING POLICIES

Effective January 1, 2007, the Trust adopted six new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook Section 1530, Comprehensive Income,
Section 3855, Financial Instruments - Recognition and Measurement,
Section 3861, Financial Instruments - Disclosure and Presentation,
Section 3865, Hedges, Section 3251, Equity and Section 1506,
Accounting Changes. These new accounting standards have been adopted
prospectively and, accordingly, comparative amounts for prior periods
have not been restated. The standards provide requirements for the
recognition, measurement and disclosure of financial instruments, the
use of hedge accounting and the presentation of equity.

Comprehensive Income
Section 1530 introduces Comprehensive Income, which consists of Net
Income and Other Comprehensive Income ("OCI"). OCI represents changes
in Unitholders' Equity from transactions and other events with non-
owner sources, and includes unrealized gains and losses on financial
assets classified as available-for-sale and changes in the fair value
of the effective portion of cash flow hedging instruments that
qualify for hedge accounting. These items are excluded from Net
Income calculated in accordance with GAAP. We have included in our
Interim Consolidated Financial Statements Consolidated Statements of
Comprehensive Income, Accumulated Other Comprehensive Income
("AOCI"), and the changes in these items during the first three and
nine month periods ended September 30, 2007. Cumulative changes in
OCI are included in AOCI, which is presented as a new category within
Unitholders' Equity on the Consolidated Balance Sheet.

Financial Instruments - Recognition and Measurement
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial
derivatives. Under this standard, all financial instruments are
required to be measured at fair value on initial recognition.
Measurement in subsequent periods depends on whether the financial
instrument has been classified as held-for-trading, available-for-
sale, held-to-maturity, loans and receivables, or other financial
liabilities. Transaction costs are expensed as incurred for financial
instruments classified or designated as held-for-trading. For other
financial instruments, excluding long-term debt, transaction costs
have been expensed as incurred. The Trust has elected to capitalize
costs incurred relating to debt issuances and to amortize these costs
over the term of the associated debt. Financial assets and
liabilities held-for-trading are measured at fair value with changes
in those fair values recognized in Net Income. Financial assets held-
to-maturity, loans and receivables, and other financial liabilities
are measured at amortized cost using the effective interest method of
amortization. Available-for-sale financial assets are measured at
fair values with unrealized gains and losses recognized in OCI.
Investments in equity instruments classified as available-for-sale
that do not have a quoted market price in an active market are
measured at cost. All risk management contracts have been designated
as held-for-trading. A portion of the reclamation funds has been
designated as available-for-sale. All other financial instruments are
classified as held-to-maturity.

Derivative instruments are recorded on the Consolidated Balance Sheet
at fair value, including those derivatives that are embedded in
financial or non-financial contracts that are not closely related to
the host contracts. Changes in fair values of derivative instruments
are recognized in Net Income with the exception of derivatives
designated as effective hedges.

The Trust has elected January 1, 2003 as the effective date to
recognize embedded derivatives. No adjustments were required for
embedded derivatives on adoption of this standard.

Financial Instruments - Disclosure and Presentation
Section 3861 establishes standards for enhancing financial statement
users' understanding of the significance of financial instruments to
an entity's financial position, performance and cash flows. It
establishes standards for presentation of financial instruments and
non-financial derivatives, and identifies the information that should
be disclosed about them. This section sets forth standards on the
presentation and classification of financial instruments between
liabilities and equity, the classification of related interest,
dividends, losses and gains, and the circumstances in which financial
assets and financial liabilities are offset. The Section dictates
disclosures surrounding factors that affect the amount, timing and
certainty of an entity's future cash flows relating to financial
instruments. This Section also deals with disclosure of information
about the nature and extent of an entity's use of financial
instruments, the business purposes they serve, the risks associated
with them and management's policies for controlling those risks.

Hedges
Section 3865 specifies the criteria that must be satisfied in order
for hedge accounting to be applied and the accounting for fair value
and cash flow hedges. Hedge accounting is discontinued prospectively
when the derivative no longer qualifies as an effective hedge, or the
derivative is terminated or sold, or upon the sale or early
termination of the hedged item. The Trust has currently designated
its financial electricity contracts and treasury rate lock contracts
as effective cash flow hedges.

In a cash flow hedging relationship, the effective portion of the
change in the fair value of the hedging derivative is recognized in
OCI while the ineffective portion is recognized in Net Income. When
hedge accounting is discontinued, the amounts previously recognized
in AOCI are reclassified to Net Income during the periods when the
variability in the cash flows of the hedged item affects Net Income.
Gains and losses on derivatives are reclassified immediately to Net
Income when the hedged item is sold or early terminated.

Equity
Section 3251 establishes standards for the presentation of equity and
changes in equity during the reporting period. This section specifies
that changes in equity for the period arising from net income, other
comprehensive income, other changes in retained earnings, changes in
contributed surplus, and changes in unitholders' capital must be
presented separately.

Impact
As a result of these changes in accounting policies, on January 1,
2007 the Trust has recorded $4.9 million in application of initial
adoption in AOCI to reflect the opening fair value of its cash flow
hedges, net of tax, which was previously not recorded on the
consolidated financial statements. The Trust has also recorded an
increase of $7 million to its risk management asset and an increase
of $2.1 million to its future income tax liability.

Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if
they result in financial statements that provide more reliable and
relevant information. Changes in policy are applied retrospectively
unless it is impractical to determine the period or cumulative impact
of the change. Corrections of prior period errors are applied
retrospectively and changes in accounting estimates are applied
prospectively by including these changes in Net Income. In addition,
disclosure is required for all future accounting changes when an
entity has not applied a new source of GAAP that has been issued but
is not yet effective.

Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards:
Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures, and Section 3863, Financial Instruments -
Presentation. These new standards will be effective on January 1,
2008.

Section 1535 specifies the disclosure of an entity's objectives,
policies and processes for managing capital, quantitative data about
what the entity regards as capital, whether the entity has complied
with any capital requirements, and if it has not complied, the
consequences of such non-compliance. This Section is expected to have
minimal impact on the Trust's financial statements.

Sections 3862 and 3863 specify a revised and enhanced disclosure on
financial instruments. These Sections will require the Trust to
increase disclosure on the nature and extent of risks arising from
financial instruments and how the entity manages those risks.

3. RECLAMATION FUNDS

September 30, 2007 December 31, 2006
---------------------------------------------------------------------
Unrest- Unrest-
ricted Restricted ricted Restricted
---------------------------------------------------------------------
Balance, beginning of
period $ 24.8 $ 6.1 $ 23.5 $ -
Contributions 9.0 - 6.0 6.1
Reimbursed
expenditures(1) (14.0) (0.6) (5.7) -
Interest earned on funds 0.9 0.2 1.0 -
Net unrealized losses
on available-for-sale
investments (0.2) - - -
---------------------------------------------------------------------
Balance, end of
period $ 20.5 $ 5.7 $ 24.8 $ 6.1
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Amount differs from actual expenditures incurred by the Trust
due to timing differences and discretionary reimbursements.

The carrying values of the unrestricted and restricted reclamation
funds, as at September 30, 2007 were $20.7 million and $5.7 million,
respectively.

4. LONG-TERM INVESTMENT

During the second quarter of 2007, the Trust sold its equity
investment in a private oil sands company for proceeds of
$33.3 million, resulting in a gain on sale of investment of
$13.3 million. The original investment was purchased for $20 million.
The investment in the shares of the private company was considered to
be a related party transaction due to common directorships of the
Trust, the private company and the manager of a private equity fund
that held shares in the private company. The $20 million investment
was part of a $325 million private placement of the private company.
In addition, certain directors and officers of the Trust had minor
direct and indirect shareholdings in the private company.

5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

September December
30, 2007 31, 2006
---------------------------------------------------------------------
Trades payable $ 40.7 $ 39.0
Accrued liabilities 111.8 108.8
Current portion of accrued long-term
incentive compensation 14.4 11.5
Interest payable 3.0 1.8
Retention bonuses - 1.0
---------------------------------------------------------------------
Total accounts payable and accrued liabilities $ 169.9 $ 162.1
---------------------------------------------------------------------
---------------------------------------------------------------------

The current portion of accrued long-term incentive compensation
represents the current portion of the Trust's estimated liability for
the Whole Unit Plan as at September 30, 2007 (see Note 15). This
amount is payable in 2007 and 2008.

6. LONG-TERM DEBT

September December
30, 2007 31, 2006
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility - CDN
denominated(1) $ 241.0 $ 196.6
Syndicated credit facility - US denominated 155.4 228.4
Working capital facility 4.8 1.1
Senior secured notes
5.42% USD Note 74.7 87.4
4.94% USD Note 23.9 28.0
4.62% USD Note 62.3 72.8
5.10% USD Note 62.3 72.8
---------------------------------------------------------------------
Total long-term debt outstanding $ 624.4 $ 687.1
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Amount borrowed under the syndicated credit facility for 2007
includes $2.7 million of outstanding cheques in excess of
bank balance.

Various borrowing options exist under the credit facility including
prime rate advances, bankers' acceptances and LIBOR based loans
denominated in either Canadian or U.S. dollars. All drawings under
the facility are subject to stamping fees that vary between 60 bps
and 110 bps depending on certain consolidated financial ratios.

The following represents the significant financial covenants
governing the credit facility:

- Long-term debt and letters of credit not to exceed three times
net income before non-cash items and interest expense;
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times net income before non-cash items and interest
expense; and
- Long-term debt and letters of credit not to exceed 50 per cent
of unitholders' equity and long-term debt, letters of credit,
and subordinated debt.

In the event that the Trust enters into a material acquisition
whereby the purchase price exceeds 10 per cent of the book value of
the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times, respectively for a maximum period of
two fiscal quarters following the closing of the material
acquisition. As at September 30, 2007, the Trust was in compliance
with all covenants and had $4.7 million in letters of credit and no
subordinated debt.

The weighted average effective interest rate under the credit
facility was 5.5 percent for the three months ended September 30,
2007 (5.8 per cent in 2006) and 5.5 per cent for the nine months
ended September 30, 2007 (5.3 per cent in 2006).

Both the working capital facility and amounts due under the senior
secured notes in the next 12 months of US$6 million have not been
included in current liabilities as management has the ability and
intent to refinance this amount through the syndicated credit
facility.

Interest paid during the period did not differ significantly from
interest expense.

7. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the Trust's asset retirement
obligations:

September December
30, 2007 31, 2006
---------------------------------------------------------------------
Balance, beginning of period $ 177.3 $ 165.1
Increase in liabilities relating to corporate
acquisitions - 4.9
Increase in liabilities relating to development
activities 2.7 2.8
(Decrease) increase in liabilities relating to
change in estimate (3.2) 4.0
Settlement of liabilities during the year (14.6) (10.6)
Accretion expense 8.7 11.1
---------------------------------------------------------------------
Balance, end of period $ 170.9 $ 177.3
---------------------------------------------------------------------
---------------------------------------------------------------------

The Trust's weighted average credit adjusted risk free rate as at
September 30, 2007 was 6.4 per cent (6.5 per cent as at December 31,
2006).

8. INCOME TAXES

On June 12, 2007, Bill C-52 ("Bill") received third reading in the
House of Commons and, therefore, was considered "substantively
enacted" for Canadian GAAP. The Bill enacts the October 31, 2006
proposals to impose a new tax on distributions from publicly traded
income trusts. As a result, the future tax position of the Trust, the
parent entity, is now required to be reflected in the consolidated
future income tax calculation.

9. FINANCIAL INSTRUMENTS

Financial Instruments

Financial Instruments of the Trust carried on the Consolidated
Balance Sheet consist mainly of cash and cash equivalents, accounts
receivable, reclamation funds, current liabilities, long-term
liabilities excluding future income taxes, and risk management
contracts. At September 30, 2007 there were no significant
differences between the carrying value of these financial instruments
and their estimated fair values.

Risk Management Contracts

The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices, foreign exchange and
interest rates. The Trust considers all of these transactions to be
effective economic hedges, however, the majority of the Trust's
contracts do not qualify as effective hedges for accounting purposes.

Following is a summary of all risk management contracts in place as
at September 30, 2007 which do not qualify for hedge accounting:

Financial WTI Crude Oil Contracts

Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Oct 07
- Dec 07 Put Spread 1,000 75.00 60.00 -
Oct 07 3 - Way
- Dec 07 Collar 2,500 65.00 52.50 80.00
Oct 07
- Dec 07 Put Spread 2,500 65.00 52.50 -
Oct 07
- Dec 07 Put Spread 1,000 65.00 55.00 -
Oct 07 3 - Way
- Dec 07 Collar 1,000 65.00 52.50 85.00
Oct 07 3 - Way
- Dec 07 Collar 5,000 75.00 65.00 90.00
Oct 07
- Dec 07 Put Spread 1,000 75.00 65.00 -
Jan 08 3 - Way
- Jun 08 Collar 1,000 65.00 52.50 85.00
Jan 08 3 - Way
- Jun 08 Collar 1,000 65.00 52.50 82.50
Jan 08
- Jun 08 Collar 1,000 65.00 - 85.00
Jan 08 3 - Way
- Dec 08 Collar 1,000 70.00 55.00 90.00
Jan 08 3 - Way
- Dec 08 Collar 1,000 67.50 52.50 85.00
Jan 08
- Dec 08 Collar 1,000 67.50 - 85.00
Jan 08 3 - Way
- Dec 08 Collar 2,000 61.50 50.00 85.00
Jan 08 3 - Way
- Dec 08 Collar 1,000 61.30 50.00 85.00
Jan 08 3 - Way
- Dec 08 Collar 2,000 61.00 50.00 85.00
Jan 09 3 - Way
- Dec 09 Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------

Financial AECO Natural Gas Option Contracts

Bought Sold Sold
Volume Put Put Call
Term Contract GJ/d CDN$/GJ CDN$/GJ CDN$/GJ
---------------------------------------------------------------------
Oct 07
- Oct 07 Put Spread 30,000 7.00 5.00 -
Oct 07
- Oct 07 Put Spread 10,000 7.25 5.25 -
Oct 07
- Oct 07 Put Spread 10,000 7.50 5.50 -
Oct 07
- Oct 07 Bought Put 10,000 7.75 - -
Apr 08
- Oct 08 Collar 10,000 7.00 - 9.00
Apr 08 3 - Way
- Oct 08 Collar 10,000 7.00 5.75 9.00
---------------------------------------------------------------------

Financial AECO Natural Gas Fixed Price Contracts

Sold
Volume Swap
Term Contract GJ/d CDN$/GJ
---------------------------------------------------------------------
Oct 07
- Oct 07 Swap 30,000 5.45
---------------------------------------------------------------------

Financial NYMEX Natural Gas Contracts

Bought Sold Sold
Put Put Call
Volume US$/ US$/ US$/
Term Contract mmbtu/d mmbtu mmbtu mmbtu
---------------------------------------------------------------------
Oct 07
- Oct 07 Put Spread 5,000 8.25 6.75 -
Nov 07
- Mar 08 Collar 20,000 8.50 - 12.50
Nov 07 3 - Way
- Mar 08 Collar 10,000 9.25 6.25 12.50
---------------------------------------------------------------------

Financial Basis Swap Contract: receive NYMEX (Last 3 Day); pay AECO
(Monthly)

Basis
Swap
Volume US$/
Term Contract mmbtu/d mmbtu
---------------------------------------------------------------------
Oct 07
- Oct 08 Basis Swap 50,000 (1.1930)
Nov 08
- Oct 10 Basis Swap 50,000 (1.0430)
---------------------------------------------------------------------

Financial Basis Swap Contract: receive AECO (Monthly); pay NYMEX
(Last 3 Day)
Basis
Swap
Volume US$/
Term Contract mmbtu/d mmbtu
---------------------------------------------------------------------
Oct 07
- Oct 07 Basis Swap 30,000 (1.2233)
---------------------------------------------------------------------

Energy Equivalent Swap

Term Contract Volume Swap
---------------------------------------------------------------------
Financial WTI Crude Oil Purchase Contract
Apr 08 1,000 73.95
- Oct 08 Swap bbl/d CDN$/bbl

Financial AECO Natural Gas Sales Contract
Apr 08 10,000 7.10
- Oct 08 Swap GJ/d CDN$/GJ
---------------------------------------------------------------------

Financial Foreign Exchange Contracts

Bought Sold
Notional Swap Swap Put Put
Volume CDN$/ US$/ CDN$/ CDN$/
Term Contract MM US$ US$ CDN$ US$ US$
---------------------------------------------------------------------
USD Sales Contracts
Oct 07
- Dec 07 Swap 4.8 1.1371 (0.8794) - -

USD Option Contracts
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1220 1.0970
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1180 1.0980
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1320 1.1020
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1380 1.1030
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1332 1.1032
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1400 1.1050
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1380 1.1080
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1300 1.1100
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1400 1.1100
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1420 1.1120
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1520 1.1120
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1440 1.1140
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1460 1.1160
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1480 1.1180
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1545 1.1195
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1765 1.1465
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1280 1.0980
Oct 07
- Dec 07 Put Spread 3.0 - - 1.1250 1.1000
Oct 07
- Dec 07 Bought Put 1.2 - - 1.1600 -
Jan 08
- Dec 08 Put Spread 12.0 - - 1.0750 1.0300

USD Long-term Principal Debt Repayment Contracts

Bought Sold
Notional Swap Swap Call Put
Settlement Volume CDN$/ US$/ CDN$/ CDN$/
Date Contract MM US$ US$ CDN$ US$ US$
---------------------------------------------------------------------
December 15,
2014 Forward 9.38 0.9825 (1.0178) - -
April 27,
2015 Forward 12.50 0.9825 (1.0178) - -
December 15,
2015 Forward 9.40 0.9980 (1.0020) - -
April 27,
2016 Forward 12.50 1.0180 (0.9823) - -
December 15,
2017 Forward 9.40 1.0184 (0.9819) - -
December 15,
2016 Collar 9.40 - - 1.0600 1.0000
---------------------------------------------------------------------

Financial Interest Rate Contracts(1)

Fixed Spread on
Principal Annual 3 Mo.
Term Contract MM US$ Rate (%) LIBOR
---------------------------------------------------------------------
Jul 07
- Apr 14 Swap 30.5 4.62 38 bps
Jul 07
- Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------

(1) Starting in 2009, the notional amount of the contracts
decreases annually until 2014. The Trust pays the floating
interest rate based on a three month LIBOR plus a spread and
receives the fixed interest rate.

Following is a summary of all risk management contracts in place as
at September 30, 2007 which qualify for hedge accounting:

Financial Electricity Contracts(2)

Swap
Volume CDN$/
Term Contract MWh MWh
---------------------------------------------------------------------
Oct 07
- Dec 07 Swap 20.0 64.63
Jan 08
- Dec 08 Swap 15.0 60.17
Jan 09
- Dec 09 Swap 15.0 59.33
Jan 10
- Dec 10 Swap 5.0 63.00
---------------------------------------------------------------------

(2) Contracted volume is based on a 24/7 term.

USD Note Treasury Rate Locks

Settlement Principal Locked Rate
Date MM US$ Received (%)
---------------------------------------------------------------------
October 17,
2007 25.0 4.6450
November 15,
2007 100.0 4.7943
---------------------------------------------------------------------

The Trust has entered into interest rate swap contracts to manage the
Company's interest rate exposure on debt instruments. Prior to 2007,
these contracts were designated as effective accounting hedges on the
contract date. At January 1, 2007 the Trust elected to cease applying
hedge accounting to these contracts. As a result, the unrealized fair
value loss on the interest rate swap contracts of $0.5 million has
been reflected in Net Income for the nine months ended September 30,
2007.

The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have not been
designated as effective accounting hedges:

September September
30, 2007 30, 2006
---------------------------------------------------------------------
Fair value, beginning of period(1) $ (8.7) $ (4.0)
Fair value, end of period(1) (16.7) (12.5)
---------------------------------------------------------------------
Change in fair value of contracts in the period (8.0) (8.5)
Realized gains in the period 15.3 19.4
---------------------------------------------------------------------
Gain on risk management contracts(1) $ 7.3 $ 10.9
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) For 2007 the fixed price electricity and treasury rate lock
contracts that were accounted for as effective accounting
hedges were excluded. For 2006 the fixed price electricity
contract and interest rate swap contracts that were accounted
for as effective accounting hedges were excluded.

At September 30, 2007, the fair value of the contracts that were not
designated as accounting hedges was a loss of $16.7 million. The
Trust recorded a gain on risk management contracts of $7.3 million in
the statement of income for the first nine months of 2007
($10.9 million gain in 2006). This amount includes the realized and
unrealized gains and losses on risk management contracts that do not
qualify as effective accounting hedges.

During the quarter the Trust entered into treasury rate lock
contracts in order to manage the Company's interest rate exposure on
future debt issuances. These contracts have been designated as
effective accounting hedges on their respective contract dates and
hedge accounting has been applied. The unrealized fair value loss on
these contracts of $1.7 million has been recorded on the Consolidated
Balance Sheet at September 30, 2007 with the movement in the fair
value recorded in OCI, net of tax. It is expected that a nominal
amount of this fair value loss will be reclassified to Net Income
within the next 12 months.

The Trust's fixed price electricity contracts are intended to manage
price risk on electricity consumption. All fixed price electricity
contracts were designated as effective accounting hedges on their
respective contract dates. A realized gain of $1.2 million and
$0.5 million for the three months and nine months ended September 30,
2007 respectively (gain of $1.4 million and $1 million respectively
in 2006) on the electricity contracts has been included in operating
costs. The unrealized fair value gain on the electricity contracts of
$7.5 million has been recorded on the consolidated balance sheet at
September 30, 2007 with the movement in fair value recorded in OCI,
net of tax. A $2.6 million gain related to electricity contracts is
expected to be recognized in income over the next 12 months.

The following table reconciles the movement in the fair value of the
Trust's financial fixed price electricity and treasury rate lock
contracts that have been designated as effective accounting hedges:

September September
30, 2007 30, 2006
---------------------------------------------------------------------
Fair value, beginning of period(2) $ 7.0 $ -
Fair value, end of period 5.8 -
---------------------------------------------------------------------
Change in fair value of contracts in the
period $ (1.2) $ -
---------------------------------------------------------------------
---------------------------------------------------------------------

(2) Fair value of fixed price electricity contracts recognized
prospectively on January 1, 2007.

The fair values of all derivative contracts are determined using
published price quotations in an active market through a valuation
model.

10. EXCHANGEABLE SHARES

ARL EXCHANGEABLE SHARES September December
(thousands) 30, 2007 31, 2006
---------------------------------------------------------------------
Balance, beginning of period 1,433 1,595
Exchanged for trust units(1) (110) (162)
---------------------------------------------------------------------
Balance, end of period 1,323 1,433
Exchange ratio, end of period 2.18448 2.01251
---------------------------------------------------------------------
Trust units issuable upon conversion, end
of period 2,889 2,884
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) During the first nine months of 2007, 110,345 ARC Resources
exchangeable shares ("ARL exchangeable shares") were
converted to trust units at an average exchange ratio of
2.114563.

Following is a summary of the non-controlling interest for September
30, 2007 and December 31, 2006:

September December
30, 2007 31, 2006
---------------------------------------------------------------------
Non-controlling interest, beginning of period $ 40.0 $ 37.5
Reduction of book value for conversion to
trust units (3.2) (4.1)
Current period net income attributable to
non-controlling interest 5.3 6.6
---------------------------------------------------------------------
Non-controlling interest, end of period $ 42.1 $ 40.0
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 32.6 $ 27.3
---------------------------------------------------------------------
---------------------------------------------------------------------

11. UNITHOLDERS' CAPITAL

September 30, 2007 December 31, 2006
---------------------------------------------------------------------
Number of Number of
Trust Units Trust Units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning of
period 204,289 2,349.2 199,104 2,230.8
Issued for cash - - 1 -
Issued on conversion
of ARL exchangeable
shares (Note 10) 233 3.2 310 4.1
Issued on exercise of
employee rights
(Note 14) 129 2.1 978 18.4
Distribution
reinvestment program 4,122 83.6 3,896 96.1
Trust unit issue costs - - - (0.2)
---------------------------------------------------------------------
Balance, end of period 208,773 2,438.1 204,289 2,349.2
---------------------------------------------------------------------
---------------------------------------------------------------------

12. DEFICIT

The deficit balance is composed of the following items:

September December
30, 2007 31, 2006
---------------------------------------------------------------------
Accumulated earnings $ 2,084.8 $ 1,695.8
Accumulated distributions (2,531.2) (2,159.0)
---------------------------------------------------------------------
Deficit $ (446.4) $ (463.2)
---------------------------------------------------------------------
---------------------------------------------------------------------

13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS

Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operating activities is
reduced by reclamation fund contributions including interest earned
on the funds, a portion of capital expenditures and, when applicable,
debt repayments. The portion of cash flow from operating activities
withheld to fund capital expenditures and to make debt repayments is
at the discretion of the Board of Directors.

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
---------------------------------------------------------------------
Cash flow from
operating activities $ 179.6 $ 203.4 $ 531.2 $ 574.6
Deduct:
Cash withheld to fund
current period
capital expenditures (49.6) (78.7) (148.9) (203.0)
Reclamation fund
contributions and
interest earned on
fund balances (5.0) (3.3) (10.1) (9.7)
---------------------------------------------------------------------
Distributions(1) 125.0 121.4 372.2 361.9
Accumulated
distributions,
beginning of period 2,406.2 1,915.3 2,159.0 1,674.8
---------------------------------------------------------------------
Accumulated
distributions, end of
period $ 2,531.2 $ 2,036.7 $ 2,531.2 $ 2,036.7
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per
unit(2) $ 0.60 $ 0.60 $ 1.80 $ 1.80
Accumulated
distributions per
unit, beginning of
period(3) $ 19.83 $ 17.43 $ 18.63 $ 16.23
---------------------------------------------------------------------
Accumulated
distributions per
unit, end of
period(3) $ 20.43 $ 18.03 $ 20.43 $ 18.03
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Distributions include non-cash amounts of $27 million and
$83 million for the three and nine months ended September 30,
2007, respectively ($27 million and $70 million for the same
periods in 2006, respectively) relating to the distribution
reinvestment program.
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of the Trust in July 1996.

14. TRUST UNIT INCENTIVE RIGHTS PLAN

A summary of the changes in rights outstanding under the plan is as
follows:

Weighted
Number Average
of Rights Exercise
(thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of period 369 9.47
Exercised (129) 10.82
---------------------------------------------------------------------
Balance before reduction of exercise price 240 9.41
Reduction of exercise price(1) - (0.69)
---------------------------------------------------------------------
Balance, end of period 240 8.72
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) The holder of the right has the option to exercise rights
held at the original grant price or a reduced exercise price.

The Trust recorded nominal compensation expense for the first nine
months of 2007 ($2.5 million in the first nine months of 2006) for
the cost associated with the rights. The compensation expense was
based on the fair value of all outstanding rights in the third
quarter of 2007 and is amortized over the remaining vesting period of
such rights. Of the 3,013,569 rights issued on or after January 1,
2003 that were subject to recording compensation expense, 357,999
rights have been cancelled and 2,416,669 rights have been exercised
to September 30, 2007.

The following table reconciles the movement in the contributed
surplus balance:

September December
CONTRIBUTED SURPLUS 30, 2007 31, 2006
---------------------------------------------------------------------
Balance, beginning of period $ 2.4 $ 6.4
Compensation expense - 2.5
Net benefit on rights exercised(1) (0.7) (6.5)
---------------------------------------------------------------------
Balance, end of period $ 1.7 $ 2.4
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to Unitholders' capital.

15. WHOLE TRUST UNIT INCENTIVE PLAN

The Trust recorded compensation expense of $8 million and
$1.3 million to general and administrative and operating expenses,
respectively, and capitalized $1.4 million to property, plant and
equipment in the nine months ended September 30, 2007 for the
estimated cost of the plan ($11.1 million, $2.2 million and
$2.2 million for the nine months ended September 30, 2006). The
compensation expense was based on the September 30, 2007 unit price
of $21.17 ($27.21 at September 30, 2006), accrued distributions, a
weighted average performance multiplier of 1.6 (2.0 in 2006), and the
number of units to be issued on maturity.

The following table summarizes the Restricted Trust Unit ("RTU") and
Performance Trust Unit ("PTU") movement for the nine months ended
September 30, 2007:

Number of Number of
RTUs PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 648 683
Vested (191) (110)
Granted 206 167
Forfeited (25) (26)
---------------------------------------------------------------------
Balance, end of period 638 714
---------------------------------------------------------------------
---------------------------------------------------------------------

The following table reconciles the change in total accrued long-term
incentive compensation liability relating to the Whole Unit Plan:

September December
30, 2007 31, 2006
---------------------------------------------------------------------
Balance, beginning of period $ 26.1 $ 15.0
Change in liabilities in the period
General and administrative expense (0.3) 8.2
Operating expense 0.2 1.1
Property, plant and equipment 0.3 1.8
---------------------------------------------------------------------
Balance, end of period $ 26.3 $ 26.1
---------------------------------------------------------------------
Current portion of liability 14.4 11.5
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 11.9 $ 14.6
---------------------------------------------------------------------
---------------------------------------------------------------------

16. BASIC AND DILUTED PER UNIT CALCULATIONS

Net income per trust unit has been determined based on the following:

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
---------------------------------------------------------------------
Weighted average trust
units(1) 208.0 202.2 206.5 200.9
---------------------------------------------------------------------
Trust units issuable on
conversion of
exchangeable shares(2) 2.9 2.9 2.9 2.9
Dilutive impact of
rights(3) 0.1 0.4 0.2 0.5
---------------------------------------------------------------------
Diluted trust units 211.0 205.5 209.6 204.3
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Weighted average trust units excludes trust units issuable
for exchangeable shares.
(2) Diluted trust units include trust units issuable for
outstanding exchangeable shares at the period end exchange
ratio.
(3) All outstanding rights were dilutive and therefore all have
been included in the diluted trust unit calculation for both
2007 and 2006.

Basic net income per unit has been calculated based on net income
after non-controlling interest divided by weighted average trust
units outstanding. Diluted net income per unit has been calculated
based on net income before non-controlling interest divided by
diluted trust units.

17. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at September 30, 2007:

---------------------------------------------------------------------
Payments Due By Period
---------------------------------------------------------------------
2008- 2010- There-
($ millions) 2007(5) 2009 2011 after Total
---------------------------------------------------------------------
Debt repayments(1) 13.6 22.3 439.1 149.4 624.4
Interest payments(2) 4.3 21.4 18.0 20.7 64.4
Reclamation fund
contributions(3) 6.0 11.1 9.5 76.2 102.8
Purchase commitments 5.0 8.0 2.9 5.8 21.7
Operating leases 1.3 9.0 4.5 - 14.8
Derivative contract
premiums(4) 5.3 9.1 - - 14.4
---------------------------------------------------------------------
Total contractual
obligations 35.5 80.9 474.0 252.1 842.5
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain
commodity derivative contracts.
(5) Amounts listed for 2007 represent contractual obligations and
committments due in the fourth quarter of 2007.

In addition to the above, the Trust has commitments related to its
risk management program (See Note 9).

The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending
litigation will not have a material adverse impact on the Trust's
financial position or results of operations.
>>

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5 billion. The Trust
currently has an interest in oil and gas production of approximately 63,000
barrels of oil equivalent per day from six core areas in western Canada. The
royalty trust structure allows net cash flow to be distributed to unitholders
in a tax efficient manner. ARC Energy Trust trades on the TSX under the symbol
AET.UN.

Note: Barrels of oil equivalent (boe) may be misleading, particularly if
used in isolation. In accordance with NI 51-101, a boe conversion ratio for
natural gas of 6 mcf:1 bbl 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.

ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 2007 and beyond; the
sources, deployment and allocation of expected capital in 2007; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,
President and Chief Executive Officer

For further information: about ARC Energy Trust, please visit our website www.arcenergytrust.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600 Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9