Exhibit 99.2

NEWS RELEASE
August 1, 2007

ARC ENERGY TRUST ANNOUNCES SECOND QUARTER 2007 RESULTS

Calgary, August 1, 2007 (AET.UN and ARX – TSX) ARC Energy Trust (“ARC” or “the Trust”) announces the results for the second quarter ending June 30, 2007.

	Three Months Ended				Six Months Ended
	June 30				June 30
	2007		2006		2007		2006
FINANCIAL ($CDN millions, except per unit and per boe amounts)
Revenue before royalties	305.6		306.7		613.4		625.7
Per unit (1)	1.46		1.51		2.94		3.09
Per boe	54.48		54.54		53.88		54.70
Cash Flow (2)	167.6		194.7		351.4		385.9
Per unit (1)	0.80		0.96		1.68		1.90
Per boe	29.88		34.61		30.87		33.73
Net income	184.9		182.5		268.2		286.6
Per unit (3)	0.90		0.91		1.30		1.43
Distributions	124.1		120.6		247.2		240.5
Per unit (1)	0.60		0.60		1.20		1.20
Per cent of Cash Flow	74		62		70		62
Net debt outstanding (4)	653.9		567.4		653.9		567.4
Total capital expenditures	48.5		58.6		126.0		137.7
OPERATING
Production
Crude oil (bbl/d)	28,099		27,805		28,806		28,723
Natural gas (mmcf/d)	176.7		178.5		179.8		181.7
Natural gas liquids (bbl/d)	4,088		4,247		4,124		4,184
Total (boe/d)	61,637		61,803		62,899		63,194
Average prices
Crude oil ($/bbl)	65.21		71.86		62.96		65.53
Natural gas ($/mcf)	7.38		6.35		7.57		7.39
Natural gas liquids ($/bbl)	52.76		54.44		50.39		53.69
Oil equivalent ($/boe) (5)	54.48		54.54		53.88		54.70
Operating netback ($/boe)
Commodity and other revenue (before hedging)	54.48		54.54		53.88		54.70
Transportation costs	(0.72	)	(0.66	)	(0.77	)	(0.64	)
Royalties	(9.43	)	(9.78	)	(9.54	)	(10.25	)
Operating costs	(9.63	)	(8.20	)	(9.30	)	(8.00	)
Netback (before hedging)	34.70		35.90		34.27		35.81

TRUST UNITS (millions)
Units outstanding, end of period	207.3	201.5	207.3	201.5
Units issuable for exchangeable shares	2.9	2.9	2.9	2.9
Total units outstanding and issuable for exchangeable shares, end of period	210.2	204.4	210.2	204.4
Weighted average units (6)	209.5	203.7	208.7	203.1

TRUST UNIT TRADING STATISTICS ($CDN, except volumes) based on intra-day trading
High	23.86	28.61	23.86	28.61
Low	20.78	24.35	20.05	24.35
Close	21.74	28.00	21.74	28.00
Average daily volume (thousands)	599	548	629	546

(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 date.

(2)Cash Flow is a non-GAAP measure. Refer to the non-GAAP measure section in the MD&A for a reconciliation of Cash Flow to cash flow from operating activities as prescribed by GAAP.

(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 risk management contracts

(5)Includes other revenue.

(6)Includes trust units issuable for outstanding exchangeable shares at period end.

ACCOMPLISHMENTS / FINANCIAL UPDATE

·Production averaged 61,637 boe per day in the second quarter of 2007, relatively unchanged from 61,803 boe per day achieved in the second quarter of 2006. The second quarter is normally the low point for the year as maintenance activities at both ARC operated and third party operated facilities result in production being shut-in. During the second quarter of 2007 approximately 2,000 boe per day of production was shut-in due to maintenance activities and other operational disruptions. Production in the third quarter is expected to return to normal levels. The Trust has maintained its full year production guidance of 63,000 boe per day.

·The Trust drilled eight wells during the quarter including the third well of a four-well horizontal drilling program at Dawson in northeast British Columbia, keeping the Trust on track to reach natural gas production of 40 mmcf/d for this property by the fourth quarter. Achieving this goal is dependent upon the completion of a third party gas plant that is currently under construction with an anticipated start-up date of November 1, 2007.

·Capital expenditures for the quarter were $48.5 million, 86 per cent of which was funded from Cash Flow with the remainder funded with proceeds from the distribution re-investment program (DRIP).  Year-to-date capital expenditures are $126 million, all which have been funded from Cash Flow and the proceeds from the DRIP. The Trust expects to spend approximately $350 million on capital expenditures during 2007.

·Prior to hedging activities, ARC’s total realized commodity price was $54.48 per boe in the second quarter of 2007, relatively unchanged from the $54.54 per boe received prior to hedging in the second quarter of 2006. The Trust benefited from a balanced production mix, whereby a 16 per cent increase in natural gas prices offset a nine per cent decrease in oil prices in the second quarter of 2007 compared to the second quarter of 2006.

·In addition to the fluctuations in the commodity price, the Canadian dollar appreciated significantly against the U.S. dollar, reaching a 30 year high of CDN/USD $0.94 at the end of the second quarter. The average CDN/USD for the second quarter of 2007 was $0.91, a seven per cent increase from CDN/USD$0.85 in the first quarter of 2007. The Trust has seen a negative impact to revenue, and therefore Cash Flow, during the quarter because commodity prices are derived from U.S. dollar posted prices for both oil and natural gas. Future revenues may be negatively impacted due to the continued strengthening of the Canadian dollar. In July 2007, the dollar has continued to appreciate with the latest record high being USD/CDN $0.96 on July 16, 2007. Conversely, the Trust has benefited from management’s decision to hold a major portion of the Trust’s subsidiaries’ debt in U.S. dollars. The Trust has seen a significant decrease in the Canadian dollar equivalent of its debt balance; however, the majority of this gain is a non-cash, unrealized gain.

·Net income for the quarter was $184.9 million, effectively unchanged from $182.5 million in the second quarter of 2006. The Trust has recorded a $35.6 million one time increase in earnings and a corresponding decrease to its future income tax liability as a result of the passage of the previously announced tax on income trusts.

·Cash Flow for the quarter was $167.6 million of which $124.1 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 third quarter distributions will remain at $0.20 per unit per month, a level that has been maintained since October 2005.

·The Trust recorded the sale of its long-term investment during the second quarter. A gain of $13.3 million dollars was recorded and the full proceeds of $33.3 million were recorded in cash flow from investing activities during the quarter. The net debt balance excluding unrealized risk management contract assets and liabilities of $653.9 million at June 30, 2007 incorporates the proceeds from the sale.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

This management’s discussion and analysis (“MD&A”) is dated July 31, 2007 and should be read in conjunction with the June 30, 2007 unaudited interim consolidated financial statements of ARC Energy Trust (“ARC”, “the Trust”, “we”, “our”), the March 31, 2007 unaudited interim consolidated financial statements and MD&A, as well as the audited consolidated financial statements and MD&A for the year ended December 31, 2006.

Non-GAAP Measures

Management uses Cash Flow and Cash Flow per unit derived from cash flow from operating activities (before changes in non-cash working capital and expenditures on site reclamation and restoration) to analyze operating performance and leverage. Cash Flow as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles, (“GAAP”) and therefore it may not be comparable with the calculation of similar measures for other entities. Cash Flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP.  Management uses the non-GAAP measure of Cash Flow because we feel that it is a more meaningful measure of the true cash generated in a period from active operations and therefore have concluded that it is material and relevant to discuss Cash Flow throughout this MD&A.

The following table reconciles the cash flow from operating activities to Cash Flow, which is used frequently in this MD&A:

	Three Months Ended June 30			Six Months Ended June 30
($ millions)	2007		2006	2007		2006
Cash flow from operating activities	179.4		182.2	351.7		371.2
Changes in non-cash working capital	(19.0	)	10.6	(12.2	)	11.5
Expenditures on site restoration and reclamation	7.2		1.9	11.9		3.2
Cash Flow	167.6		194.7	351.4		385.9
Weighted average units including exchangeable shares	209.5		203.7	208.7		203.1
Cash Flow per Unit	0.80		0.96	1.68		1.90

Management uses certain key performance indicators (“KPIs”) and industry benchmarks such as distributions as a per cent of Cash Flow, 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

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 has 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.

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, the distribution amount in 2011 to tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign investors would fall by an estimated 31.5 percent and 26.5 percent, respectively.

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 will be required to pay $15 per tonne for every tonne above the 12 per cent target, beginning on July 1, 2007.

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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 our 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 June 30				Six Months Ended June 30
(CDN$ millions, except per unit and volume data)	2007	2006	% Change		2007	2006	% Change
Cash Flow (1)	167.6	194.7	(14	)	351.4	385.9	(9	)
Cash Flow per unit (1)	0.80	0.96	(17	)	1.68	1.90	(12	)
Net income	184.9	182.5	1		268.2	286.6	(6	)
Distributions per unit (2)	0.60	0.60	—		1.20	1.20	—
Distributions as a per cent of Cash Flow	74	62	19		70	62	13
Daily production (boe/d) (3)	61,637	61,803	—		62,899	63,194	(1	)

(1)	Refer to Non-GAAP Measures.
(2)	Based on number of trust units outstanding at each cash distribution 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 boe in isolation may be misleading.

Net Income

Net income in the second quarter of 2007 was $184.9 million ($0.90 per unit), an increase of $2.4 million from $182.5 million ($0.91 per unit) in the second quarter of 2006. Higher operating costs ($7.9 million), interest costs ($1.7 million) and depletion expense ($4.6 million) in the quarter were almost entirely offset by an increased gain on foreign exchange ($12.7 million). In addition, the Trust recorded an increased gain on risk management contracts ($14 million) that was offset by a lower future income tax recovery ($24.5 million) and the recording of a gain on sale of investment ($13.3 million).

Cash Flow

Cash Flow was $167.6 million in the second quarter of 2007 a 14 per cent decrease from $194.7 million recorded in the second quarter of 2006. The decrease in second quarter Cash Flow was attributed to an $11 million decrease in realized cash hedging gains, an $8.5 million increase in cash operating costs and a $5.7 million increase in cash general and administrative (“G&A”) costs. The increase in operating costs, more fully described later in this MD&A, were due primarily to turnaround and workovers that occurred in the quarter and the G&A cost increase is attributed to the cash payout under the Trust’s Whole Unit Plan which occurred in the second quarter.

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Following is a summary of variances in Cash Flow from 2006 to 2007:

	Three Months Ended June 30						Six Months Ended June 30
	$ Millions		$ Per Unit		%Variance		$ Millions		$ Per Unit		%Variance
2006 Cash Flow	194.7		0.96		—		385.9		1.90		—
Volume variance	(0.8	)	—		—		(2.9	)	(0.01	)	(1	)
Price variance	(0.4	)	—		—		(9.4	)	(0.05	)	(2	)
Cash gains on risk management contracts (1)	(11.0	)	(0.05	)	(6	)	(2.6	)	(0.01	)	(1	)
Royalties	2.1		0.01		1		8.6		0.04		2
Expenses:
Operating (2)	(8.5	)	(0.04	)	(4	)	(15.4	)	(0.08	)	(4	)
Transportation	(0.3	)	(0.01	)	-		(1.5	)	(0.01	)	—
Cash G&A	(5.7	)	(0.03	)	(3	)	(6.8	)	(0.04	)	(2	)
Interest and cash taxes	(1.9	)	(0.01	)	(1	)	(3.7	)	(0.02	)	(1	)
Realized foreign exchange (loss)	(0.6	)	(0.01	)	—		(0.9	)	—		—
Other	—		—		—		0.1		—		—
Weighted average trust units	—		(0.02	)	—		—		(0.04	)	—
2007 Cash Flow	167.6		0.80		(14	)	351.4		1.68		(9	)

(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.

Please refer to “NON-GAAP MEASURES” that occurs as the first heading in this MD&A for a reconciliation of Cash Flow to cash flow from operating activities as prescribed by GAAP.

Production

Production volume averaged 61,637 boe per day in the second quarter of 2007, relatively unchanged from 61,803 boe per day during the second quarter of 2006. The Trust experienced significant production loss during the second quarter as a result of planned turnarounds and workovers. Of the approximately 2,000 boe per day of volumes that were shut-in during the quarter, the Trust estimates that 1,000 boe per day was lost due to either unscheduled activities or where turnarounds took significantly longer than expected. The Trust expects third quarter production to return to normal levels.  We have maintained our full year 2007 production guidance at 63,000 boe per day.

Throughout the first six months of 2007, the Trust has experienced production restrictions in the northern Alberta area 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. As of June 30, the Trust had three horizontal wells in Dawson that were waiting to be completed. It is anticipated that these wells will be completed during the third quarter so that they can be brought on production in the fourth quarter when there is additional processing capacity for the resulting production.

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 second quarter of 2007, the Trust drilled eight gross wells (six net wells) on operated properties with a 100 per cent success rate; six gross oil wells and two gross natural gas wells. Normally, the second quarter is the least active quarter for drilling as field operations are restricted during “spring break-up” and do not get back to normal levels until late in the quarter when field conditions have improved.

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	Three Months Ended June 30				Six Months Ended June 30
Production (1)	2007	2006	% Change		2007	2006	% Change
Crude oil (bbl/d)	28,099	27,805	1		28,806	28,723	—
Natural gas (mcf/d)	176,706	178,504	(1	)	179,814	181,721	(1	)
NGL (bbl/d)	4,088	4,247	(4	)	4,124	4,184	(1	)
Total production (boe/d)	61,637	61,803	—		62,899	63,194	(1	)
% Natural gas production	48	48			48	48
% Crude oil and liquids production	52	52			52	52

(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 June 30, 2007				Three Months Ended June 30, 2006
Production	Total	Oil	Gas	NGL	Total	Oil	Gas	NGL
Core Area (1)	(boe/d)	(bbl/d)	(mmcf/d)	(bbl/d)	(boe/d)	(bbl/d)	(mmcf/d)	(bbl/d)
Central AB	7,774	1,631	29.0	1,316	8,082	1,501	30.7	1,464
Northern AB & BC	19,417	5,599	73.9	1,499	18,345	5,596	67.2	1,554
Pembina & Redwater	13,515	9,188	19.1	1,136	13,712	9,293	20.0	1,093
S.E. AB & S.W. Sask.	9,915	1,070	53.0	9	10,798	1,043	58.4	9
S.E. Sask. & MB	11,016	10,611	1.7	128	10,866	10,372	2.2	127
Total	61,637	28,099	176.7	4,088	61,803	27,805	178.5	4,247

(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 June 30				Six Months Ended June 30
Benchmark Prices	2007	2006	% Change		2007	2006	% Change
AECO gas (CDN$/mcf) (1)	7.37	6.28	17		7.42	7.78	(5	)
WTI oil (US$/bbl) (2)	65.02	70.70	(8	)	61.59	67.14	(8	)
USD/CAD foreign exchange rate	0.91	0.89	2		0.88	0.88	—
WTI oil (CDN$/bbl)	71.35	79.08	(10	)	69.78	76.28	(9	)

(1)Represents the AECO monthly posting.

(2)WTI represents West Texas Intermediate posting as denominated in US$.

The price of oil in U.S. dollars decreased by eight per cent in the second quarter of 2007 as compared to the second quarter of 2006 while the price of oil in Canadian dollars decreased by 10 per cent. The strengthening of the Canadian dollar relative to the U.S. dollar was responsible for the larger decrease of the price of oil in Canadian dollar terms. ARC’s realized oil price in the second quarter of 2007 was $65.21 per barrel, a nine per cent decrease over the $71.86 per barrel received in the second quarter of 2006 as minor changes in differential offset a portion of the decrease due to the change in foreign exchange.

Natural gas prices recovered in the second quarter of 2007 with the Alberta AECO Hub monthly posting averaging $7.37 per mcf as compared to $6.28 per mcf for the comparable period of 2006. The Trust’s realized price of $7.38 per mcf in the second quarter of 2007 was 16 per cent higher than the $6.35 per mcf price realized by the Trust in the second 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.

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Prior to hedging activities, ARC’s total realized commodity price was $54.48 per boe in the second quarter of 2007, relatively unchanged from the $54.54 per boe received prior to hedging in the second quarter of 2006. Given the Trust’s balanced production mix, the increases in natural gas prices offset the decreases in oil prices during the period.

The following is a summary of realized prices:

	Three Months Ended June 30				Six Months Ended June 30
ARC Realized Prices	2007	2006	% Change		2007	2006	% Change
Oil ($/bbl)	65.21	71.86	(9	)	62.96	65.63	(4	)
Natural gas ($/mcf)	7.38	6.35	16		7.57	7.39	2
NGLs ($/bbl)	52.76	54.44	(3	)	50.39	53.70	(6	)
Total commodity revenue before hedging ($/boe)	54.37	54.42	—		53.77	54.58	(1	)
Other revenue ($/boe)	0.11	0.12	(8	)	0.11	0.12	(8	)
Total revenue before hedging ($/boe)	54.48	54.54	—		53.88	54.70	(1	)

Revenue

Revenue was relatively unchanged at $305.6 million as compared with $306.7 million for the second quarter of 2006 as increased gas revenues were offset by a decrease in oil and NGL revenue.

A breakdown of revenue is as follows:

	Three Months Ended June 30				Six Months Ended June 30
Revenue ($ millions)	2007	2006	% Change		2007	2006	% Change
Oil revenue	166.8	181.8	(8	)	328.3	340.7	(4	)
Natural gas revenue	118.6	103.2	15		246.3	242.9	1
NGLs revenue	19.6	21.0	(7	)	37.6	40.7	(8	)
Total commodity revenue	304.9	306.0	—		612.2	624.3	(2	)
Other revenue	0.6	0.7	(14	)	1.2	1.4	(14	)
Total revenue before hedging	305.6	306.7	—		613.4	625.7	(2	)

Risk Management and Hedging Activities

The Trust continues to maintain a strong hedging position with an emphasis on protecting Cash Flow and distributions to unitholders.

During the second quarter ARC realized cash hedging gains of $0.3 million bringing cash hedging gains for the year-to-date to $7.3 million. Gains on crude oil puts and foreign exchange positions were offset by settlements on natural gas basis swaps and premiums paid for natural gas contracts.

In addition to layering into additional natural gas and crude oil positions during the quarter, ARC also modified positions that were previously on the books as part of its active hedging program.

ARC optimized its crude oil positions by restructuring the long-term 5,000 barrels per day hedge that was entered into to protect the acquisition metrics of the 2005 Redwater / NPCU properties. ARC increased the floor price on the 3-way collar from $55.00 to an average of $61.26. This was achieved at no cost by lowering the ceiling price on the original structure from $90.00 to $85.00 and raising the sold floor price from $40.00 to $50.00. This raises the average floor price for crude oil hedges for 2008 to $63.33 per barrel.

On a forward-looking basis ARC continues to add layers of protection for both crude oil and natural gas production. During the quarter ARC layered on additional protection on crude to the end of 2008 and additional natural gas positions through to Q1 2008.

On crude oil production ARC has protected approximately 40 per cent of forecast oil production through year-end 2007, 30 per cent of production through the first half of 2008, and 20 per cent of production for the second half of

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2008. For natural gas production ARC has protected approximately 32.5 per cent of production during the third quarter of 2007, 20 per cent for the fourth quarter of 2007, and 15 per cent for the first quarter of 2008.

The following is a summary of the Trust’s positions for the next twelve months as at June 30, 2007.

Hedge Positions
as at June 29, 2007 (1)(2)

	Q3 2007		Q4 2007		Q1 2008		Q2 2008
Crude oil	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
Sold call	86.48	8,500	86.48	8,500	84.75	10,000	84.75	10,000
Bought put	61.92	13,000	61.92	13,000	63.63	10,000	63.63	10,000
Sold put	48.90	12,500	48.90	12,500	50.94	8,000	50.9375	8,000
Natural gas	CDN$/GJ	GJ/day	CDN$/GJ	GJ/day	CDN$/GJ	GJ/day	CDN$/GJ	GJ/day
Sold call	9.08	40,435	11.36	20,986	11.35	31,652	—	—
Bought put	7.24	65,275	7.41	42,981	7.58	31,652	—	—
Sold put	5.19	55,275	5.19	18,625	—	—	—	—
FX	CAD/USD	$ Million	CAD/USD	$ Million	CAD/USD	$ Million	CAD/USD	$ Million
Bought put	1.1400	55.8	1.1400	55.8	—	—	—	—
Sold put	1.1096	54.0	1.1096	54.0	—	—	—	—
Swap	1.1371	4.2	1.1371	4.2	—	—	—	—

(1)    The prices and volumes noted above represent averages for several contracts and the average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. 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 note 9 in the Trust’s unaudited consolidated financial statements as at June 30, 2007 and 2006 for a detailed breakdown of the Trust’s hedging position as at June 30, 2007.

The above table should be interpreted as follows using the third quarter 2007 crude oil hedges as an example. The Trust has hedged 13,000 barrels per day at a minimum average price of US$61.92 and participates in prices up to a maximum average of US$86.48 on 8,500 barrels per day with no limit on the remaining 4,500 hedged barrels per day and on all other unhedged production for the period. Finally, ARC’s average protected price of $61.92 reduces penny for penny at an average price below $48.90 on 12,500 barrels per day.

As a result of commodity hedging contracts denominated in U.S. dollars, ARC systematically enters into foreign exchange agreements to offset this exposure. In addition, ARC manages these foreign exchange positions by converting the forwards to U.S. dollar put spreads whereby ARC achieves a position that is a net asset.

Please refer to “NON-GAAP MEASURES” that occurs as the first heading in this MD&A for a reconciliation of Cash Flow to cash flow from operating activities as prescribed by GAAP.

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 $0.3 million in the second quarter of 2007 compared to a gain of $11.3 million recorded in for the same period of 2006. The Trust had a similar hedging strategy in place for the first quarters of 2007 and 2006; however, 2007 market prices were comparable to the Trust’s floor prices for natural gas resulting in cash hedging losses being the premiums paid in the period. The $2.2 million cash loss recorded for natural gas was offset by small gains on the Trust’s crude oil and foreign exchange contracts.

The unrealized gain of $10.8 million was due mostly to a weakening of forward natural gas prices that have resulted in unrealized gains in natural gas financial positions through the first quarter of 2008 and strengthening of the Canadian dollar that has resulted in an increase in unrealized gains on foreign exchange positions partly offset by strengthening crude oil prices that have reduced the value of crude oil hedge positions.

8

The following is a summary of the total gain (loss) on risk management contracts for the second quarter and year to date of 2007:

Risk Management Contracts ($ millions)	Crude Oil & Liquids		Natural Gas		Interest & Foreign Currency	Q2 2007 Total	Q2 2006  Total
Realized cash gain (loss) on contracts (1)	0.8		(2.2	)	1.7	0.3	11.3
Unrealized gain (loss) on contracts (2)	(8.6	)	16.3		3.1	10.8	(14.2	)
Total gain (loss) on risk management contracts	(7.8	)	14.1		4.8	11.1	(2.9	)

Risk Management Contracts ($ millions)	Crude Oil & Liquids		Natural Gas	Interest & Foreign Currency	YTD 2007 Total		YTD 2006  Total
Realized cash gain (loss) on contracts (1)	5.7		1.6	—	7.3		9.9
Unrealized gain (loss) on contracts (2)	(15.3	)	—	5.2	(10.1	)	(9.1	)
Total gain (loss) on risk management contracts	(9.6	)	1.6	5.2	(2.8	)	0.8

(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 eight per cent to $34.75 per boe in the second quarter of 2007 compared to $37.90 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:

Netbacks ($ per boe)	Crude  Oil ($/bbl)		Heavy Oil ($/bbl)		Gas ($/mcf)		NGL ($/bbl)		Q2 2007  Total ($/boe)		Q2 2006  Total ($/boe)
Weighted average sales price	66.09		47.50		7.38		52.76		54.37		54.42
Other revenue	—		—		—		—		0.11		0.12
Total revenue	66.09		47.50		7.38		52.76		54.48		54.54
Royalties	(10.48	)	(4.11	)	(1.34	)	(14.43	)	(9.43	)	(9.78	)
Transportation	(0.34	)	(0.93	)	(0.19	)	—		(0.72	)	(0.66	)
Operating costs (1)	(12.19	)	(15.47	)	(1.22	)	(7.76	)	(9.63	)	(8.20	)
Netback prior to hedging	43.08		26.99		4.63		30.57		34.70		35.90
Realized gain (loss) on risk management contracts	1.04		—		(0.14	)	—		0.05		2.00
Netback after hedging	44.12		26.99		4.49		30.57		34.75		37.90

Netbacks ($ per boe)	Crude  Oil ($/bbl)		Heavy Oil ($/bbl)		Gas ($/mcf)		NGL ($/bbl)		YTD 2007  Total ($/boe)		YTD 2006  Total ($/boe)
Weighted average sales price	63.86		45.09		7.57		50.39		53.77		54.58
Other revenue	—		—		—		—		0.11		0.12
Total revenue	63.86		45.09		7.57		50.39		53.88		54.70
Royalties	(10.02	)	(3.84	)	(1.47	)	(13.50	)	(9.54	)	(10.25	)
Transportation	(0.41	)	(1.23	)	(0.20	)	—		(0.77	)	(0.64	)
Operating costs (1)	(11.46	)	(13.18	)	(1.23	)	(7.73	)	(9.30	)	(8.00	)
Netback prior to hedging	41.97		26.84		4.67		29.16		34.27		35.81
Realized gain (loss) on risk management contracts	1.15		—		0.05		—		0.63		0.86
Netback after hedging	43.12		26.84		4.72		29.16		34.91		36.67

(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 $9.43 per boe in the second quarter of 2007 compared to $9.78 per boe in the same period of 2006. Royalties as a percentage of pre-hedged commodity revenue net of transportation costs decreased to 17.5 per

9

cent compared to 18 per cent in the second quarter of 2006. The decrease in royalty rates is consistent with the changes in the Trust’s production profile as new production brought on-stream impacts the overall royalty rates.

Transportation costs increased nine per cent to $0.72 per boe in the second quarter of 2007 compared to $0.66 per boe in the second quarter of 2006. The Trust has experienced challenges in Saskatchewan throughout the second half of 2006 and the first half of 2007 due to shipping restrictions on the Enbridge pipeline as it is operating at full capacity. During the first quarter, the Trust had to truck approximately 900 boe per day of operated oil production at a cost significantly greater than the cost to transport those volumes by pipeline. While transportation costs came down in the second quarter of 2007 as compared to the first quarter of 2007, as a result of a reduction in trucked volumes, costs were still higher than the second quarter of 2006. An expansion of the Enbridge pipeline is expected to be completed sometime in late 2007 or early 2008.

Operating costs increased to $9.63 per boe compared to $8.20 per boe in the second quarter of 2006. Total operating costs in the second quarter of 2007 increased by $7.9 million compared to the second quarter of 2006. This increase is due to increased costs for workovers and maintenance ($3 million), increased labour and LTIP costs ($0.9 million), increased lease rentals for renewals ($1.5 million), increased property taxes ($1 million), and 13th month adjustments booked in the quarter ($1.5 million).

In comparing the Trust’s total second quarter 2007 operating costs to the first quarter of 2007, operating costs have increased by $2 million. This amount includes higher costs for workovers and maintenance ($3 million) net of a reduction in processing fees recorded in the period ($1 million).

General and Administrative Expenses and Incentive Compensation

Cash G&A before incentive compensation and net of overhead recoveries on operated properties was relatively unchanged at $8.9 million in the second quarter of 2007 from $8.8 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, second quarter cash G&A costs increased two per cent to $1.59 per boe in 2007 from $1.56 per boe in 2006 as a result of higher cash G&A costs and a slight decrease in production volumes.

During the second quarter the Trust made a payment under the Whole Unit Plan 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 remainder $2.2 million being recorded to operating costs and capital projects.  These amounts were fully accrued at the end of the first quarter of 2007, however, cash flow from operating activities in the second quarter of 2007 has been decremented for the full amount of the cash payment.

The following is a breakdown of G&A and Incentive compensation expense:

G&A and Incentive Compensation Expense	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2007		2006		% Change		2007		2006		% Change
G&A expenses	12.7		11.4		11		26.2		21.7		21
Operating recoveries	(3.8	)	(2.6	)	46		(8.5	)	(5.2	)	63
Cash G&A expenses before Whole Unit Plan	8.9		8.8		1		17.7		16.5		7
Cash expense – Whole Unit Plan	8.3		2.7		207		8.3		2.7		207
Cash G&A expenses including Whole Unit Plan	17.2		11.5		50		26.0		19.2		35
Accrued compensation – Rights Plan	—		0.8				—		2.5
Accrued compensation – Whole Unit Plan	(4.3	)	1.2		458		(4.0	)	5.0		180
Total G&A and trust unit compensation expense	12.9		13.5		(4	)	22.0		26.7		(18	)

G&A and Incentive Compensation Expense	Three Months Ended June 30				Six Months Ended June 30
($ per boe)	2007	2006	% Change		2007	2006	% Change
Cash G&A expenses before Whole Unit Plan	1.59	1.56	2		1.55	1.45	7
Cash G&A expenses including Whole Unit Plan	3.07	2.05	50		2.28	1.68	36
Total G&A and trust unit compensation expense	2.29	2.39	(4	)	1.93	2.33	(17	)

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A non-cash incentive compensation expense (“non-cash compensation expense”) of $(4.3) million was recorded in the second quarter of 2007 which represents the estimated costs of the Whole Unit Plan for the period net of the accrual reversal for the cash amount paid in April 2007.

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 June 30, 2007, 0.2 million rights were outstanding at an average exercise price of $8.95 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 during the quarter of RTUs and PTUs outstanding:

Whole Unit Plan (units in thousands and $ millions except per unit)	Number of  RTUs			Number of  PTUs			Total RTUs and PTUs
Balance, beginning of period	648			683			1,331
Granted in the period	204			164			368
Vested in the period	(191		)	(111		)	(302		)
Forfeited in the period	(25		)	(25		)	(50		)
Balance, end of period (1)	636			711			1,347
Estimated distributions to vesting date (2)	171			175			346
Estimated units upon vesting after distributions	807			886			1,693
Performance multiplier (3)	—			1.6
Estimated total units upon vesting	807			1,388			2,195
Trust unit price at June 30, 2007	$	21.74		$	21.74		$	21.74
Estimated total value upon vesting	$	17.5		$	30.2		$	47.7

(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 June 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.

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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 June 30, 2007	Performance Multiplier
(units thousands and $ millions except per unit)	—	1.0	2.0
Estimated trust units to vest
RTUs	807	807	807
PTUs	—	886	1,771
Total units (1)	807	1,693	2,578
Trust unit price (2)	21.74	21.74	21.74
Trust unit distributions per month (2)	0.20	0.20	0.20
Value of Whole Unit Plan upon vesting	17.5	38.6	59.6
Officers	2.0	12.1	22.2
Directors	1.4	1.4	1.4
Staff	14.1	25.1	36.0
Total Payments Under Whole Unit Plan (3)	17.5	38.6	59.6
2007	2.4	2.4	2.4
2008	7.8	15.4	23.1
2009	5.3	13.8	22.2
2010	2.0	7.0	11.9

(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. Assumed future trust unit price of $21.74 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 $17.5 million to $59.6 million from 2007 through 2010 based on the current trust unit price, distribution levels and a performance multiplier ranging from zero to two.

Interest Expense

Interest expense increased to $9.3 million in the second quarter of 2007 from $7.6 million in the second quarter of 2006 due to an increase in short-term interest rates, and higher debt balances. Interest expense for the first six months of 2007 was $19.2 million, an increase of $4 million from $15.2 million in the first six months of 2006.

The Trust’s debt balance as reflected in Canadian dollars has decreased significantly since December 31, 2006. This is a result of the nine 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 June 30, 2007.  The Canadian dollar equivalent of the US$380 million debt balance has decreased by $38.7 million as a result of the appreciation of the Canadian dollar against the U.S. dollar from December 31, 2006 to June 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 100 per cent of the year to date capital program with Cash Flow and proceeds from the Distribution Reinvestment Program (“DRIP”).  See “Non-GAAP Measures” section.

As at June 30, 2007, the Trust had $644.8 million of debt outstanding, of which $238.3 million was fixed at a weighted average rate of 5.06 per cent and $406.5 million was floating at current market rates plus a credit spread of 60 basis points. 63 per cent of the Trust’s debt is denominated in U.S. dollars.

Foreign Exchange Gains and Losses

The Trust recorded a gain of $35.5 million on foreign exchange transactions compared to a gain of $22.8 million for the second 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 second quarter of 2007, the Canadian dollar reached a 30 year high when compared to the U.S. dollar. The dollar closed the quarter at $1.06 per U.S. dollar.

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The unrealized gain/loss impacts net income but does not impact Cash Flow as it is a non-cash amount. Realized foreign exchange gains or losses arise from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements.

Please refer to “NON-GAAP MEASURES” that occurs as the first heading in this MD&A for a reconciliation of Cash Flow to cash flow from operating activities as prescribed by GAAP.

Taxes

In the second quarter of 2007, a future income tax recovery of $46.4 million was included in income compared to a $70.9 million recovery in the second quarter of 2006. The second 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 29.7 percent from the previous rate of 33.7 per cent.  The corporate income tax rate applicable to 2007 is 32.1 per cent as compared to the expected future tax rate of 28.9 per cent.

ARC does not anticipate any material cash income taxes will be paid 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, 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.

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 $16.31 per boe in the second quarter of 2007 from $15.43 per boe in the second quarter of 2006.  Year-to-date, the DD&A rate has increased six percent to $16.33 per boe as compared to $15.38 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 June 30			Six Months Ended June 30
($ millions except per boe amounts)	2007	2006	% Change	2007	2006	% Change
Depletion of oil & gas assets (1)	88.5	84.2	5	180.1	170.7	6
Accretion of asset retirement obligation (2)	2.9	2.6	12	5.8	5.2	12
Total DD&A	91.4	86.8	5	185.9	175.9	6
DD&A expense per boe	16.31	15.43	6	16.33	15.38	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 $48.5 million in the second quarter of 2007 compared to $58.6 million in the second quarter of 2006. This amount was incurred on drilling and completions, geological, geophysical and facilities expenditures, and the purchase of undeveloped acreage.  The Trust also spent $14.6 million on minor property acquisitions in the second quarter of 2007 as compared to $5.2 million for the same period in 2006.

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

	Three Months Ended June 30				Six Months Ended June 30
Capital Expenditures ($ millions)	2007		2006		2007		2006
Geological and geophysical	4.1		2.8		9.0		5.5
Land	1.7		14.3		1.9		19.2
Drilling and completions	25.8		29.8		80.9		85.1
Plant and facilities	16.3		10.9		33.1		26.5
Other capital	0.6		0.8		1.1		1.4
Total capital expenditures	48.5		58.6		126.0		137.7
Producing property acquisitions (1)	14.6		5.2		14.8		39.0
Producing property dispositions (1)	(4.6	)	(2.4	)	(4.6	)	(8.6	)
Total capital expenditures and net acquisitions	58.5		61.4		136.2		168.1

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

Approximately 86 per cent of the $48.5 million capital program was financed with Cash Flow in the second quarter of 2007 compared to 100 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.  See “Non-GAAP Measures” section.

Source of Funding of Capital Expenditures and Net Acquisitions

($ millions)

	Three Months Ended June 30, 2007						Three Months Ended June 30, 2006
	Development Capital		Net Acquisitions		Total Expenditures		Development Capital		Net Acquisitions		Total Expenditures
Expenditures	48.5		10.0		58.5		58.6		2.8		61.4
Per cent funded by:
Cash Flow (1)	86	%	—		71	%	100	%	100	%	100	%
Proceeds from DRIP and Rights Plan	14	%	100	%	29	%	—		—		—
Debt	—		—		—		—		—		—
	100	%	100	%	100	%	100	%	100	%	100	%

Source of Funding of Capital Expenditures and Net Acquisitions

($ millions)

	Six Months Ended June 30, 2007						Six Months Ended June 30, 2006
	Development Capital		Net Acquisitions		Total Expenditures		Development Capital		Net Acquisitions		Total Expenditures
Expenditures	126.0		10.2		136.2		137.7		30.4		168.1
Per cent funded by:
Cash Flow (1)	79	%	—		73	%	100	%	4	%	83	%
Proceeds from DRIP and Rights Plan	21	%	100	%	27	%	—		96	%	17	%
Debt	—		—		—		—		—		—
	100	%	100	%	100	%	100	%	100	%	100	%

(1)         See Non-GAAP Measures Section

14

Long-Term Investment

During the second quarter, 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 June 30, 2007, the Trust has recorded an Asset Retirement Obligation (“ARO”) of $168.8 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 $11.9 million for reclamation spending in the first half of 2007 ($7.2 million for the second quarter of 2007). This amount has been offset by accretion of $5.8 million ($2.9 million for the second quarter of 2007). In addition, a net decrease to the liability of $2.4 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 in the second quarter of 2007 was 25 per cent funded by the reclamation fund. The remaining 75 per cent ($5.4 million) was funded temporarily through working capital. On a year-to-date basis, reclamation spending has been 43 per cent funded through the reclamation fund and the remaining 57 per cent has been funded temporarily through working capital. On an annual basis, the Trust will adjust the balance of the reclamation fund for the full amount of reclamation spending in the period.

Capitalization, Financial Resources and Liquidity

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

Capital Structure and Liquidity	June 30, 2007		December 31, 2006
($ millions except per unit and per cent amounts)
Revolving credit facilities	406.5		426.1
Senior secured notes	238.3		261.0
Working capital deficit excluding short-term debt (1)	9.1		52.0
Net debt obligations	653.9		739.1
Trust units outstanding and issuable for exchangeable shares (millions)	210.2		207.2
Market price per unit at end of period	21.74		22.30
Market value of trust units and exchangeable shares at end of period	4,569.7		4,620.0
Total capitalization (2)	5,223.6		5,359.1
Net debt as a percentage of total capitalization	12.5	%	13.8	%
Net debt obligations	653.9		739.1
Cash Flow (3)	351.4		760.6
Net debt to annualized Cash Flow	0.9		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)	See “Non-GAAP Measures” Section

Net debt levels at June 30, 2007 have decreased since December 31, 2006 as a result of funding 100 per cent of the 2007 year to date quarter capital program with Cash Flow and proceeds of the DRIP program. Lastly, the Trust’s net debt balance has decreased significantly as a result of the appreciation in the Canadian dollar which generated an unrealized gain of $40.5 million for the six months ended June 30, 2007. As at June 30, 2007, the Trust had $380 million in U.S. denominated debt.

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 June 30, 2007, the Trust had $394.3 million of available borrowings under the current credit facility.

The Trust intends to finance its $350 million 2007 capital program with Cash Flow and the proceeds of the distribution reinvestment program with any remainder being financed with debt.

15

Unitholders’ Equity

At June 30, 2007, there were 210.2 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 2.8 million units issued pursuant to the DRIP during 2007 at an average price of $20.43 per unit.

The Trust had 0.2 million rights outstanding as of June 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 $8.95 per unit as at June 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 second quarter of 2007, the Trust raised proceeds of $29.1 million and issued 1.4 million trust units pursuant to the DRIP.

Distributions

ARC declared distributions of $124.1 million ($0.60 per unit), representing 74 per cent of second quarter 2007 Cash Flow compared to distributions of $120.6 million ($0.60 per unit), representing 62 per cent of Cash Flow in the second quarter of 2006. The remaining 26 per cent of second quarter 2007 Cash Flow ($43.5 million) was used to fund 86 per cent of ARC’s 2007 year to date capital expenditures and make contributions, including interest, to the reclamation funds ($1.8 million).

Monthly distributions for the second 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 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 and distributions in total and per unit were as follows:

	Three Months Ended June 30						Three Months Ended June 30
Cash Flow and Distributions	2007		2006		% Change		2007		2006		% Change
			($ millions)						($ per unit)
Cash Flow	167.6		194.7		(14	)	0.80		0.96		(17	)
Reclamation fund contributions (1)	(1.8	)	(4.7	)	(62	)	(0.01	)	(0.02	)	(50	)
Capital expenditures funded with Cash Flow	(41.7	)	(68.1	)	(39	)	(0.20	)	(0.33	)	(39	)
Discretionary debt repayments	—		(1.3	)	—		—		—		—
Other (2)	—		—		—		0.01		(0.01	)	200
Distributions	124.1		120.6		3		0.60		0.60		—

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	Six Months Ended June 30						Six Months Ended June 30
Cash Flow and Distributions	2007		2006		% Change		2007		2006		% Change
	($ millions)						($ per unit)
Cash Flow	351.4		385.9		(9	)	1.68		1.90		(12	)
Reclamation fund contributions (1)	(5.1	)	(6.4	)	(20	)	(0.02	)	(0.03	)	(33	)
Capital expenditures funded with Cash Flow	(99.1	)	(137.7	)	(28	)	(0.47	)	(0.68	)	(31	)
Discretionary debt repayments	—		(1.3	)	—		—		—		—
Other (2)	—		—		—		0.01		0.01		—
Distributions	247.2		240.5		3		1.20		1.20		—

(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, reclamation fund contributions and capital expenditures funded with Cash Flow are based on weighted average outstanding trust units in the year plus trust units issuable for exchangeable shares at year end.

Please refer to “NON-GAAP MEASURES” that occurs as the first heading in this MD&A for a reconciliation of Cash Flow to cash flow from operating activities as prescribed by GAAP.

2007 Monthly Distributions

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

Ex-distribution Date	Record Date	Distribution Payment Date	Total 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
November 28, 2007	November 30, 2007	December 17, 2007
December 27, 2007	December 31, 2007	January 15, 2008

*       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 Flow in an ongoing manner. The Trust also has contractual obligations and commitments that are of a less routine nature as disclosed in the following table.

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

	Payments Due By Period
($ millions)	2007	2008-2009	2010-2011	Thereafter	Total
Debt repayments (1)	7.3	23.8	454.2	159.5	644.8
Interest payments (2)	6.0	22.9	19.3	22.1	70.3
Reclamation fund contributions (3)	6.0	11.1	9.5	76.2	102.8
Purchase commitments	8.6	8.2	3.1	6.3	26.2
Operating leases	2.6	9.0	4.5	—	16.1
Derivative contract premiums (4)	19.8	8.1	—	—	27.9
Retention bonuses	1.0	—	—	—	1.0
Total contractual obligations	51.3	83.1	490.6	264.1	889.1

(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.

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 June 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 June 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.

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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 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 six months of 2007.

Financial Reporting Update

During 2007, the Trust completed the implementation of the new CICA Handbook Section 3855, Financial Instruments – Recognition and Measurement, Section 1530, Comprehensive Income, and Section 3865, Hedges that deal with the recognition and measurement of financial instruments at fair value and comprehensive income. See notes 2 and 9 in the Notes to the Unaudited Consolidated Financial Statements for further details.

During the second 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.

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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 levels on which distributions are paid.  The Trust facilitates this by utilizing a portion of Cash Flow to fund a portion of ongoing capital development activities and maintaining moderate debt levels. Oil and gas royalty trusts hold assets that are depleting and unitholders should expect production, revenue, Cash Flow and distributions to decline over the long-term if reserves cannot be economically replaced. 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 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 and distributions as a per cent of Cash Flow:

Per Trust Unit Ratios	Q2 2007	Q1 2007	Q4 2006	Q3 2006	Q2 2006	Trailing 5 Quarters
Production per unit (1):
Unadjusted	0.29	0.31	0.31	0.30	0.30	—
Debt-adjusted (2)	0.26	0.27	0.27	0.28	0.27	—
Normalized (3)	0.303	0.31	0.31	0.32	0.326	—
Cash Flow per unit	0.80	0.88	0.85	0.98	0.96	—
Distributions per unit	0.60	0.60	0.60	0.60	0.60	3.00
Distributions as a per cent of Cash Flow	74	67	70	61	62	66
Per cent of Cash Flow retained	26	33	30	39	38	34

(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 annual 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 annual 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 second quarter of 2006, the Trust’s normalized production per unit has decreased modestly from 0.326 to 0.303 boe of daily average production per thousand trust units. The second quarter 2007 production per unit of 0.303 was negatively impacted by maintenance activities and shut-in production. Production per unit of 0.303 was achieved and the Trust paid $611.5 million in distributions ($3.00 per trust unit and 66 per cent of Cash Flow) over a five quarter time period. The normalized production per unit is a key measure as it indicates the ability to generate Cash Flow 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 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

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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 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 are indicative of the Trust’s commitment to fund a portion of ongoing development activities with Cash Flow to enable long-term sustainability. On an annual basis, the Trust’s distributions as a per cent of Cash Flow 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 maintain stable distributions during the last five quarters.

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 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 per cent)	Q2 2007	Q1 2007		Q4 2006		Q3 2006		Q2  2006	Trailing 5 Quarters
Net income	184.9	83.3		56.6		116.9		182.5	624.2
Distributions	124.1	123.1		122.3		121.4		120.6	611.5
Excess (shortfall)	60.8	(39.8	)	(65.7	)	(4.5	)	61.9	12.7
Excess (shortfall) as per cent of net income	33	(48	)	(116	)	(4	)	34	2

Please refer to “NON-GAAP MEASURES” that occurs as the first heading in this MD&A for a reconciliation of Cash Flow to cash flow from operating activities as prescribed by GAAP.

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 second quarter of 2007:

	2007	2007
	Revised	Previous	Actual to
	Guidance	Guidance	June 30, 2007
Production (boe/d)	63,000	63,000	62,899
Expenses ($/boe):
Operating costs	9.25	8.95	9.30
Transportation	0.70	0.70	0.77
G&A expenses – cash (1)	2.15	2.25	2.28
G&A expenses – stock compensation plans (1)	0.10	0.20	(0.35	)
Interest (1)	1.70	1.50	1.69
Taxes	0.00	0.00	0.00
Annual capital expenditures ($ millions)	350	360	126.0
Weighted average trust units and trust units issuable (millions) (1)	210	208	209

(1)   Guidance for the noted items were revised in the first quarter of 2007.  See the Trust’s first quarter 2007 MD&A for further details.

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

·With operating costs higher than guidance for the six months ended June 30, 2007 we have revised guidance to $9.25 per boe for the full year 2007.   The Trust is continually pursuing cost control initiatives in order to address ongoing pressures in the service industry.

·Transportation costs were 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.

·Cash G&A expenses were higher than guidance due to the fact that the Trust paid its April LTIP payment in the second quarter. The cash expense is offset by a reversal of the non-cash expense in the quarter. The Trust expects cash G&A to be in-line with guidance for the full year of 2007.

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·The Trust is revising 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.

·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.

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QUARTERLY HISTORICAL REVIEW

(CDN $ millions, except per Unit amounts)	2007		2006				2005
FINANCIAL	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Revenue before royalties	305.6	307.8	292.5	312.3	306.7	318.9	365.3	310.2
Per unit (1)	1.46	1.48	1.42	1.52	1.51	1.58	1.89	1.62
Cash Flow(2)	167.6	183.8	174.4	200.3	194.7	191.2	207.6	168.1
Per unit – basic (1)	0.80	0.88	0.85	0.98	0.96	0.94	1.07	0.88
Per unit – diluted	0.80	0.88	0.84	0.97	0.95	0.94	1.07	0.87
Net income	184.9	83.3	56.6	116.9	182.5	104.1	130.5	114.6
Per unit – basic (3)	0.90	0.41	0.28	0.58	0.91	0.52	0.68	0.61
Per unit – diluted	0.89	0.41	0.28	0.58	0.91	0.52	0.68	0.59
Distributions	124.1	123.1	122.3	121.4	120.6	119.9	115.7	92.6
Per unit (4)	0.60	0.60	0.60	0.60	0.60	0.60	0.60	0.49
Total assets	3,432.8	3,450.1	3,479.0	3,335.8	3,277.8	3,279.7	3,251.2	2,483.5
Total liabilities	1,415.3	1,526.6	1,550.6	1,371.3	1,339.9	1,434.1	1,415.5	912.2
Net debt outstanding (5)	653.9	729.7	739.1	579.7	567.4	598.9	578.1	357.6
Weighted average units (6)	209.5	207.9	206.5	205.1	203.7	202.5	193.4	191.7
Units outstanding and issuable (6)	210.2	208.7	207.2	205.7	204.4	203.1	202.0	192.1
CAPITAL EXPENDITURES
Geological and geophysical	4.1	4.9	3.7	2.2	2.8	2.7	3.0	2.3
Land	1.7	0.2	11.8	1.4	14.3	4.9	5.5	2.0
Drilling and completions	25.8	55.1	79.1	76.2	29.8	55.4	60.3	63.6
Plant and facilities	16.3	16.8	26.5	24.6	10.9	15.6	17.0	14.8
Other capital	0.6	0.5	0.8	0.5	0.8	0.5	2.0	0.3
Total capital expenditures	48.5	77.5	121.9	104.9	58.6	79.1	87.8	83.0
Property acquisitions (dispositions) net	10.0	0.2	76.4	8.4	2.8	27.6	3.0	5.9
Corporate acquisitions (7)	—	—	16.6	—	—	—	462.8	—
Total capital expenditures and net acquisitions	58.5	77.7	214.9	113.3	61.4	106.7	553.6	88.9
OPERATING Production
Crude oil (bbl/d)	28,099	29,520	29,605	29,108	27,805	29,651	25,534	23,513
Natural gas (mmcf/d)	176.7	183.0	179.5	173.4	178.5	185.0	177.9	168.2
Natural gas liquids (bbl/d)	4,088	4,161	4,144	4,166	4,247	4,120	3,943	4,047
Total (boe per day 6:1)	61,637	64,175	63,663	62,178	61,803	64,600	59,120	55,592
Average prices
Crude oil ($/bbl)	65.21	60.79	58.26	71.84	71.86	59.53	62.12	69.37
Natural gas ($/mcf)	7.38	7.75	6.99	6.10	6.35	8.40	12.05	9.08
Natural gas liquids ($/bbl)	52.76	48.04	46.51	56.60	54.44	52.91	57.14	50.43
Oil equivalent ($/boe)	54.48	53.29	49.94	54.59	54.54	54.86	67.16	60.66
TRUST UNIT TRADING (based on intra-day trading) Unit prices
High	23.86	23.02	29.22	30.74	28.61	27.51	27.58	24.20
Low	20.78	20.05	19.20	25.25	24.35	25.09	20.45	19.94
Close	21.74	21.25	22.30	27.21	28.00	27.36	26.49	24.10
Average daily volume (thousands)	599	658	1,125	614	548	546	653	599

(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)	See Non-GAAP Measures 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.

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CONSOLIDATED BALANCE SHEETS

As at June 30 and December 31 (unaudited)

($CDN millions)	2007			2006
ASSETS
Current assets
Cash and cash equivalents	$	35.0		$	2.8
Accounts receivable	114.3			129.8
Prepaid expenses	14.9			18.4
Risk management contracts (Note 9)	31.3			25.7
	195.5			176.7
Reclamation funds (Note 3)	32.1			30.9
Property, plant and equipment	3,047.6			3,093.8
Long-term investment (Note 4)	—			20.0
Goodwill	157.6			157.6
Total assets	$	3,432.8		$	3,479.0
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities (Note 5)	$	131.8		$	162.1
Distributions payable	41.5			40.9
Risk management contracts (Note 9)	39.9			34.4
	213.2			237.4
Long-term debt (Note 6)	644.8			687.1
Accrued long-term incentive compensation (Note 15)	9.1			14.6
Asset retirement obligations (Note 7)	168.8			177.3
Future income taxes (Note 8)	379.4			434.2
Total liabilities	1,415.3			1,550.6
COMMITMENTS AND CONTINGENCIES (Note 17)
NON-CONTROLLING INTEREST
Exchangeable shares (Note 10)	41.6			40.0
UNITHOLDERS’ EQUITY
Unitholders’ capital (Note 11)	2,409.4			2,349.2
Contributed surplus (Note 14)	1.8			2.4
Deficit (Note 12)	(442.2		)	(463.2		)
Accumulated other comprehensive income (Note 2)	6.9			—
Total unitholders’ equity	1,975.9			1,888.4
Total liabilities and unitholders’ equity	$	3,432.8		$	3,479.0

See accompanying notes to consolidated financial statements.

24

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT

For the three and six months ended June 30 (unaudited)

	Three Months Ended June 30						Six Months Ended June 30
($CDN millions, except per unit amounts)	2007			2006			2007			2006
Revenues
Oil, natural gas and natural gas liquids	$	305.6		$	306.7		$	613.4		$	625.7
Royalties	(52.8		)	(55.0		)	(108.6		)	(117.3		)
	252.8			251.7			504.8			508.4
Gain (loss) on risk management contracts (Note 9)
Realized	0.3			11.3			7.3			9.9
Unrealized	10.8			(14.2		)	(10.1		)	(9.1		)
	263.9			248.8			502.0			509.2
Expenses
Transportation	4.0			3.7			8.7			7.3
Operating	54.0			46.1			105.9			91.5
General and administrative	12.9			13.5			22.0			26.7
Interest on long-term debt (Note 6)	9.3			7.6			19.2			15.2
Depletion, depreciation and accretion	91.4			86.8			185.9			175.9
Gain on foreign exchange	(35.5		)	(22.8		)	(40.5		)	(17.2		)
	136.1			134.9			301.2			299.4
Operating income	127.8			113.9			200.8			209.8
Gain on sale of investment (Note 4)	13.3			—			13.3			—
Capital and other taxes	—			0.3			—			(0.3		)
Future income tax recovery (Note 8)	46.4			70.9			57.8			81.2
Net income before non-controlling interest	187.5			185.1			271.9			290.7
Non-controlling interest (Note 10)	(2.6		)	(2.6		)	(3.7		)	(4.1		)
Net Income	$	184.9		$	182.5		$	268.2		$	286.6
Deficit, beginning of period	$	(503.0	)	$	(454.9	)	$	(463.2	)	$	(439.1	)
Distributions paid or declared (Note 13)	(124.1		)	(120.6		)	(247.2		)	(240.5		)
Deficit, end of period (Note 12)	$	(442.2	)	$	(393.0	)	$	(442.2	)	$	(393.0	)
Net income per unit (Note 16)
Basic	$	0.90		$	0.91		$	1.30		$	1.43
Diluted	$	0.89		$	0.91		$	1.30		$	1.43

See accompanying notes to consolidated financial statements.

25

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE INCOME

For the three and six months ended June 30 (unaudited)

	Three Months Ended June 30					Six Months Ended June 30
($CDN millions)	2007			2006		2007			2006
Other comprehensive income, net of tax
Gain on financial instruments designated as cash flow hedges	$	1.8		$	—	$	3.0		$	—
Loss on financial instruments designated as cash flow hedges in prior periods realized in net income in the current period	(0.6		)	—		(0.7		)	—
Net unrealized losses on available-for-sale reclamation funds’ investments	(0.3		)	—		(0.3		)	—
Other comprehensive income	$	0.9		$	—	$	2.0		$	—
Accumulated other comprehensive income, beginning of period	$	6.0		$	—	$	—		$	—
Application of initial adoption	—			—		4.9			—
Accumulated other comprehensive income, end of period	$	6.9		$	—	$	6.9		$	—

See accompanying notes to consolidated financial statements.

26

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the three and six months ended June 30 (unaudited)

	Three Months Ended June 30						Six Months Ended June 30
($CDN millions)	2007			2006			2007			2006
CASH FLOW FROM OPERATING ACTIVITIES
Net Income	$	184.9		$	182.5		$	268.2		$	286.6
Add items not involving cash:
Non-controlling interest (Note 10)	2.6			2.6			3.7			4.1
Future income tax recovery (Note 8)	(46.4		)	(70.9		)	(57.8		)	(81.2		)
Depletion, depreciation and accretion	91.4			86.8			185.9			175.9
Non-cash (gain) loss on risk management contracts (Note 9)	(10.8		)	14.2			10.1			9.1
Non-cash (gain) on foreign exchange	(35.6		)	(22.2		)	(40.8		)	(16.5		)
Non-cash trust unit incentive compensation (Notes 14 and 15)	(5.2		)	1.7			(4.6		)	7.9
Gain on sale of investment	(13.3		)	—			(13.3		)	—
Expenditures on site restoration and reclamation	(7.2		)	(1.9		)	(11.9		)	(3.2		)
Change in non-cash working capital	19.0			(10.6		)	12.2			(11.5		)
	179.4			182.2			351.7			371.2
CASH FLOW FROM FINANCING ACTIVITIES
Issuance of long-term debt under revolving credit facilities, net	(7.8		)	0.9			—			17.7
Issue of trust units	1.2			5.8			2.3			8.6
Trust unit issue costs	—			—			—			(0.2		)
Cash distributions paid (Note 13)	(95.2		)	(99.0		)	(191.4		)	(198.7		)
Change in non-cash working capital	(1.9		)	(2.6		)	(0.2		)	1.4
	(103.7		)	(94.9		)	(189.3		)	(171.2		)
CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas properties	(11.2		)	(3.6		)	(14.7		)	(32.4		)
Proceeds on disposition of petroleum and natural gas properties	1.2			0.8			4.6			2.0
Capital expenditures	(47.8		)	(57.9		)	(125.2		)	(136.5		)
Long-term investment (Note 4)	33.3			(20.0		)	33.3			(20.0		)
Net reclamation fund contributions (Note 3)	(0.3		)	(3.2		)	(1.5		)	(3.7		)
Changes in non-cash working capital	(15.9		)	(12.1		)	(26.7		)	(9.4		)
	(40.7		)	(96.0		)	(130.2		)	(200.0		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	35.0			(8.7		)	32.2			—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	—			8.7			2.8			—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	35.0		$	—		$	35.0		$	—

See accompanying notes to consolidated financial statements.

27

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

June 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 three 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 3865, Hedges, 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 and measurement of financial instruments and the use of hedge accounting.

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 a Consolidated Statement of Other Comprehensive Income for the changes in these items during the first six months of 2007, while the cumulative changes in OCI are included in Accumulated Other Comprehensive Income (“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, transaction costs are capitalized on initial recognition. 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.

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 cash flow hedges.

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 as an effective cash flow hedge.

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

28

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.

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

	June 30, 2007						December 31, 2006
	Unrestricted			Restricted			Unrestricted			Restricted
Balance, beginning of period	$	24.8		$	6.1		$	23.5		$	—
Contributions	4.5			—			6.0			6.1
Reimbursed expenditures (1)	(3.0		)	(0.6		)	(5.7		)	—
Interest earned on funds	0.5			0.1			1.0			—
Net unrealized losses on available-for-sale investments	(0.3		)	—			—			—
Balance, end of period	$	26.5		$	5.6		$	24.8		$	6.1

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

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.

29

5.     ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

	June 30, 2007		December 31, 2006
Trades payable	$	33.9	$	39.0
Accrued liabilities	83.2		108.8
Current portion of accrued long-term incentive compensation	12.1		11.5
Interest payable	1.6		1.8
Retention bonuses	1.0		1.0
Total accounts payable and accrued liabilities	$	131.8	$	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 June 30, 2007 (see Note 15). This amount is payable in 2007 and 2008.

6.     LONG-TERM DEBT

	June 30, 2007		December 31, 2006
Revolving credit facilities
Syndicated credit facility – CDN denominated	$	239.9	$	196.6
Syndicated credit facility – US denominated	165.9		228.4
Working capital facility	0.8		1.1
Senior secured notes
5.42% USD Note	79.7		87.4
4.94% USD Note	25.5		28.0
4.62% USD Note	66.5		72.8
5.10% USD Note	66.5		72.8
Total long term debt outstanding	$	644.8	$	687.1

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 June 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 5.4 percent for the three months ended June 30, 2007 (5.4 per cent in 2006) and 5.5 per cent for the six months ended June 30, 2007 (5.0 per cent in 2006).

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.

30

7.ASSET RETIREMENT OBLIGATIONS

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

	June 30, 2007			December 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	0.6			2.8
(Decrease) Increase in liabilities relating to change in estimate	(3.0		)	4.0
Settlement of liabilities during the year	(11.9		)	(10.6		)
Accretion expense	5.8			11.1
Balance, end of period	$	168.8		$	177.3

The Trust’s weighted average credit adjusted risk free rate as at June 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.

The tax provision differs from the amount computed by applying the combined Canadian federal and provincial statutory income tax rates to income before future income tax recovery as follows:

	June 30, 2007			June 30, 2006
Income before future income tax expense and recovery	$	214.1		$	209.5
Expected income tax expense at statutory rates	67.2			72.2
Effect on income tax of:
Net income of the Trust	(76.8		)	(79.3		)
Non-taxable portion of gains/losses	(8.5		)	—
Effect of change in corporate tax rate	(7.3		)	(58.5		)
Resource allowance	—			(5.5		)
Change in estimated pool balances	(7.0		)	(6.4		)
Non-deductible crown charges	—			0.5
Capital Tax	—			0.1
Other non-deductible items	(0.7		)	(4.3		)
Initial recognition of Trust tax pools	(24.7		)	—
Future income tax recovery	$	(57.8	)	$	(81.2	)

The net future income tax liability is comprised of the following:

	June 30, 2007			June 30, 2006
Future tax liabilities:
Capital assets in excess of tax value	$	437.6		$	494.0
Long-term debt	9.7			—
Other comprehensive income	3.0			—
Future tax assets:
Non-capital losses	(4.3		)	(1.6		)
Asset retirement obligations	(48.7		)	(42.3		)
Accrued long-tem incentive compensation	(6.1		)	—
Risk management contracts	(5.4		)	(3.9		)
Attributed Canadian royalty income	(4.6		)	(11.5		)
Deductible share issue costs	(1.8		)	—
Net future income tax liability	$	379.4		$	434.7

31

The following is a summary of the Trust’s estimated consolidated tax pools, as of June 30, 2007:

Canadian oil and gas property expenses	$	735.6
Canadian development expenses	298.5
Canadian exploration expenses	43.5
Undepreciated capital cost	405.9
Non-capital losses	13.8
Provincial tax pools	161.1
Other	13.5
Estimated tax basis	$	1,671.9

9.FINANCIAL INSTRUMENTS

The Trust uses a variety of derivative instruments to reduce its exposure to fluctuations in commodity prices and foreign exchange rates.  The Trust considers all of these transactions to be effective economic 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 June 30, 2007:

Financial WTI Crude Oil Contracts

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

Financial AECO Natural Gas Contracts

		Volume	Bought Put	Sold Put	Sold Call
Term	Contract	GJ/d	CDN$/GJ	CDN$/GJ	CDN$/GJ
Jul 07 – Aug 07	Collar	10,000	7.75	—	10.00
Jul 07 – Aug 07	3 - Way Collar	10,000	7.50	5.50	9.50
Jul 07 – Aug 07	3 - Way Collar	10,000	7.25	5.25	9.00
Jul 07 – Aug 07	3 - Way Collar	30,000	7.00	5.00	8.65
Sep 07 – Oct 07	Bought Put	10,000	7.75	—	—
Sep 07 – Oct 07	Put Spread	10,000	7.50	5.50	—
Sep 07 – Oct 07	Put Spread	10,000	7.25	5.25	—
Sep 07 – Oct 07	Put Spread	30,000	7.00	5.00	—

Financial NYMEX Natural Gas Contracts

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

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

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

32

Financial Foreign Exchange Contracts

		Notional
		Volume	Swap	Swap		Bought Put	Sold Put
Term	Contract	MM US$	CDN$/US$	US$/CDN$		CDN$/US$	CDN$/US$
USD Sales Contracts
Jul 07 – Dec 07	Swap	8.4	1.1371	(0.8794	)	—	—
USD Option Contracts
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1220	1.0970
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1180	1.0980
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1320	1.1020
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1380	1.1030
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1332	1.1032
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1400	1.1050
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1380	1.1080
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1300	1.1100
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1400	1.1100
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1420	1.1120
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1520	1.1120
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1440	1.1140
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1460	1.1160
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1480	1.1180
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1545	1.1195
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1765	1.1465
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1280	1.0980
Jul 07 – Dec 07	Put Spread	6.0	—	—		1.1250	1.1000
Jul 07 – Dec 07	Bought Put	6.0	—	—		1.1600	—

Financial Electricity Contracts (1)

		Volume	Swap
Term	Contract	MWh	CDN$/MWh
Jul 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

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

Financial Interest Rate Contracts (2)

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

(2) 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.

The Trust has designated all fixed price electricity contracts as effective accounting hedges on their respective contract dates. A realized loss of $0.1 million and $0.7 million for the three months and six months ended June 30, 2007 respectively ($0.4 million and $0.5 respectively in 2006) on the electricity contracts has been included in operating costs. The unrealized fair value gain on the electricity contracts of $10.2 million has been recorded on the consolidated balance sheet at June 30, 2007 with the movement in fair value recorded in OCI, net of tax.

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 $2.4 million has been reflected in the income statement for the six months ended June 30, 2007.

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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:

	June 30, 2007			June 30, 2006
Fair value, beginning of period (1)	$	(8.7	)	$	(4.0	)
Fair value, end of period (1)	(18.8		)	(13.1		)
Change in fair value of contracts in the period	(10.1		)	(9.1		)
Realized gains in the period	7.3			9.9
(Loss) gain on risk management contracts (1)	$	(2.8	)	$	0.8

(1)   For 2007 the fixed price electricity 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.

The following table reconciles the movement in the fair value of the Trust’s financial electricity contracts that have been designated as effective accounting hedges:

	June 30, 2006		June 30, 2007
Fair value, beginning of period (2)	$	7.0	$	—
Fair value, end of period	10.2		—
Change in fair value of contracts in the period	3.2		—

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

At June 30, 2007, the fair value of the contracts that were not designated as accounting hedges was a loss of $18.8 million.  The Trust recorded a loss on risk management contracts of $2.8 million in the statement of income for the first six months of 2007 ($0.8 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.

10.  EXCHANGEABLE SHARES

ARL EXCHANGEABLE SHARES (thousands)	June 30, 2007		December 31, 2006
Balance, beginning of period	1,433		1,595
Exchanged for trust units (1)	(72	)	(162	)
Balance, end of period	1,361		1,433
Exchange ratio, end of period	2.12420		2.01251
Trust units issuable upon conversion, end of period	2,892		2,884

(1)   During the first six months of 2007, 71,741 ARC Resources exchangeable shares (“ARL exchangeable shares”) were converted to trust units at an average exchange ratio of 2.07802.

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

	June 30, 2007			December 31, 2006
Non-controlling interest, beginning of period	$	40.0		$	37.5
Reduction of book value for conversion to Trust units	(2.1		)	(4.1		)
Current period net income attributable to non-controlling interest	3.7			6.6
Non-controlling interest, end of period	$	41.6		$	40.0
Accumulated earnings attributable to non-controlling interest	$	31.0		$	27.3

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11.  UNITHOLDERS’ CAPITAL

	June 30, 2007		December 31, 2006
	Number of  Trust Units (thousands)	$	Number of  Trust Units (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)	149	2.1	310	4.1
Issued on exercise of employee rights (Note 14)	122	2.0	978	18.4
Distribution reinvestment program	2,749	56.1	3,896	96.1
Trust unit issue costs	—	—	—	(0.2	)
Balance, end of period	207,309	2,409.4	204,289	2,349.2

12.  DEFICIT

The deficit balance is composed of the following items:

	June 30, 2007			December 31, 2006
Accumulated earnings	$	1,964.0		$	1,695.8
Accumulated distributions	(2,406.2		)	(2,159.0		)
Deficit	$	(442.2	)	$	(463.2	)

13.  RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS

Distributions are calculated in accordance with the Trust Indenture. To arrive at distributions, cash flow from operations adjusted for changes in non-cash working capital and expenditures on site restoration and reclamation, is reduced by reclamation fund contributions including interest earned on the funds and a portion of capital expenditures, and debt repayments. The portion of cash flow withheld to fund capital expenditures and to make debt repayments is at the discretion of the Board of Directors.

	Three Months Ended June 30						Six Months Ended June 30
	2007			2006			2007			2006
Cash flow from operating activities	$	179.4		$	182.2		$	351.7		$	371.2
Change in non-cash working capital	(19.0		)	10.6			(12.2		)	11.5
Expenditures on site reclamation and restoration	7.2			1.9			11.9			3.2
Cash flow from operating activities after the above adjustments	167.6			194.7			351.4			385.9
Deduct:
Cash withheld to fund current period capital expenditures	(41.7		)	(68.1		)	(99.1		)	(137.7		)
Reclamation fund contributions and interest earned on fund balances	(1.8		)	(4.7		)	(5.1		)	(6.4		)
Discretionary debt repayments	—			(1.3		)	—			(1.3		)
Distributions (1)	124.1			120.6			247.2			240.5
Accumulated distributions, beginning of period	2,282.1			1,794.7			2,159.0			1,674.8
Accumulated distributions, end of period	$	2,406.2		$	1,915.3		$	2,406.2		$	1,915.3
Distributions per unit (2)	$	0.60		$	0.60		$	1.20		$	1.20
Accumulated distributions per unit, beginning of period (3)	$	19.23		$	16.83		$	18.63		$	16.23
Accumulated distributions per unit, end of period (3)	$	19.83		$	17.43		$	19.83		$	17.43

(1)	Distributions include non-cash amounts of $28 million and $54 million for the three and six months ended June 30, 2007, respectively ($21 million and $42 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.

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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	(122	)	10.86
Balance before reduction of exercise price	247		9.40
Reduction of exercise price (1)	—		(0.45	)
Balance, end of period	247		8.95

(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 six months of 2007 ($2.5 million in the first six 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 second 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 2,410,269 rights have been exercised to June 30, 2007.

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

	June 30, 2007			December 31,  2006
CONTRIBUTED SURPLUS
Balance, beginning of period	$	2.4		$	6.4
Compensation expense	—			2.5
Net benefit on rights exercised (1)	(0.6		)	(6.5		)
Balance, end of period	$	1.8		$	2.4

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

15.WHOLE UNIT INCENTIVE PLAN

The Trust recorded compensation expense of $4.3 million and $0.6 million to general and administrative and operating expenses, respectively, and capitalized $0.8 million to property, plant and equipment in the six months ended June 30, 2007 for the estimated cost of the plan ($7.8 million, $1.4 million and $1.6 million for the six months ended June 30, 2006). The compensation expense was based on the June 30, 2007 unit price of $21.74 ($28.00 at June 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 six months ended June 30, 2007:

	Number of		Number of
	RTUs		PTUs
	(thousands)		(thousands)
Balance, beginning of period	648		683
Vested	(191	)	(111	)
Granted	204		164
Forfeited	(25	)	(25	)
Balance, end of period	636		711

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

	June 30, 2007			December 31, 2006
Balance, beginning of period	$	26.1		$	15.0
Change in liabilities in the period General and administrative expense	(4.1		)	8.2
Operating expense	(0.5		)	1.1
Property, plant and equipment	(0.3		)	1.8
Balance, end of period	$	21.2		$	26.1
Current portion of liability	12.1			11.5
Accrued long-term incentive compensation	$	9.1		$	14.6

16.  BASIC AND DILUTED PER UNIT CALCULATIONS

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

	Three Months Ended June 30		Six Months Ended June 30
	2007	2006	2007	2006
Weighted average trust units (1)	206,562	200,814	205,780	200,202
Trust units issuable on conversion of exchangeable shares (2)	2,892	2,895	2,892	2,895
Dilutive impact of rights (3)	179	740	212	817
Diluted trust units	209,633	204,449	208,884	203,914

(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 June 30, 2007:

	Payments Due By Period
($ millions)	2007	2008-2009	2010-2011	Thereafter	Total
Debt repayments (1)	7.3	23.8	454.2	159.5	644.8
Interest payments (2)	6.0	22.9	19.3	22.1	70.3
Reclamation fund contributions (3)	6.0	11.1	9.5	76.2	102.8
Purchase commitments	8.6	8.2	3.1	6.3	26.2
Operating leases	2.6	9.0	4.5	—	16.1
Derivative contract premiums (4)	19.8	8.1	—	—	27.9
Retention bonuses	1.0	—	—	—	1.0
Total contractual obligations	51.3	83.1	490.6	264.1	889.1

(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.

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

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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 $5.4 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

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