Enerplus Resources Fund
The Dome Tower
3000, 333-7th Avenue SW
Calgary, Alberta T2P 2Z1
Tel 403.298.2200
Fax 403.298.2211
www.enerplus.com
November 7, 2008
FOR IMMEDIATE RELEASE
Enerplus Resources Fund
TSX: ERF.un
NYSE: ERF
ENERPLUS ANNOUNCES 2008 THIRD QUARTER

OPERATING AND FINANCIAL RESULTS

Calgary, Alberta - Enerplus Resources Fund ("Enerplus") is pleased to announce our results from operations for the
period ending September 30, 2008.

Highlights are as follows:

• Cash flow from operating activities was $383.6 million ($2.33 per unit) on the sale of our crude oil and
natural gas production, slightly higher than the cash flows earned during the second quarter of 2008.
• Actual cash distributions paid to unitholders were $1.31 per unit, up 4% from the second quarter.

Our payout
ratio was approximately 59% during the period.

When we include our development capital expenditures, our
adjusted payout ratio was 102% for the quarter.
• We closed the sale of our Joslyn oil sands lease for net proceeds of $502 million, which greatly enhanced
our financial flexibility and put us in an enviable position with regard to the strength of our balance sheet.
Our debt to trailing 12 month cash flow ratio is currently 0.4x, one of the lowest in our sector.
• We have achieved another milestone regarding our operated Kirby oil sands project by filing the regulatory
application slightly earlier than planned for Phase 1 development of 10,000 bbls/day of bitumen production.
• Daily production during the third quarter averaged 95,644 BOE/day.

The majority of the production shortfall
was related to our development program at Shackleton where higher than normal rainfall in both the second
and third quarters hampered our ability to execute our shallow gas program.

As well, we undertook a review
of our completion techniques at Shackleton in order to optimize production from additional zones delaying
the tie-in of a number of wells in the area.
• We invested $163.2 million on our development capital expenditure program in the third quarter drilling 272
net wells.

We also invested approximately $43 million on pre-investment spending, which included the
purchase of land in the Montney region of Alberta and British Columbia and the Bakken region of southeast
Saskatchewan as well as our oil sands activities.
Revised 2008 Guidance
• The downturn in commodity prices throughout the quarter combined with the current uncertainty in the
capital markets has reinforced our belief in the importance of maintaining strong financial flexibility.

As a
result, we have reduced our monthly cash distribution level from $0.47/unit to $0.38/unit effective with the
November 2008 distribution payment.

We are also reducing our overall capital spending plans for 2008 by
$35 million (6%) to $545 million for the year which includes an additional $20 million of land acquisitions
over our original plans which do not provide near-term production or cash flow, but which we expect will help
build development opportunities for the future.
• As a result of our adjustment in capital spending and lower than expected third quarter production, we are
lowering our 2008 average annual production guidance slightly to 96,000 BOE/day and adjusting our
anticipated exit rate from 100,000 BOE/day to 98,500 BOE/day.
• Our cash operating costs were $10.10/BOE, up from $9.61/BOE during the third quarter of 2007.

We are
increasing our estimate of full year 2008 operating costs by $0.50/BOE to $9.50/BOE due to the reduced
production forecast as well as by continued cost increases related to our optimization activities in the U.S.
• General and administrative cash expenses were $1.50/BOE, down from $2.11/BOE during the third quarter
of 2007.

We are decreasing our estimate for 2008 general and administrative expenses by $0.20/BOE to
approximately $2.00/BOE primarily due to lower expenses associated with long-term compensation plans.
• Looking ahead to 2009, given the lower commodity price environment we currently face as well as the
uncertainty in the financial and credit markets, we are expecting our 2009 capital spending to be moderately
lower than our 2008 spending.

We expect to provide detailed operational and production guidance for 2009
in mid-December.

SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS
All amounts are stated in Canadian dollars unless otherwise specified.

In accordance with Canadian practice,
production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of Crown and
other royalties, unless otherwise stated.

Where applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE.

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 wellhead.

Use of BOE in isolation may
be misleading.

Certain prior year amounts have been restated to reflect current year presentation.

Readers are also
urged to review the Management"s Discussion & Analysis (MD&A) and Audited Financial Statements for more
fulsome disclosure on our operations.

These reports can be found on our website at www.enerplus.com, our SEDAR
profile at www.sedar.com and as part of our SEC filings available on www.sec.gov.

SELECTED FINANCIAL RESULTS
Three months ended September 30, Nine months ended September 30,
(in Canadian dollars) 2008 2007 2008 2007
Financial (000"s)
Cash Flow from Operating Activities $383,573 $232,801 $1,004,246 $663,464
Cash Distributions to Unitholders(1) 224,417 163,110 619,121 483,388
Cash Withheld for Acquisitions and Capital
Expenditures 159,156 69,691 385,125 180,076
Net Income 465,773 93,033 699,397 240,990
Debt Outstanding (net of cash) 522,254 649,829 522,254 649,829
Development Capital Spending 163,215 90,647 377,485 281,045
Acquisitions 4,574 1,755 1,771,383 269,149
Divestments 502,489 96 504,697 5,569
Actual Cash Distributions to Unitholders
per Trust Unit $1.31 $1.26 $3.83 $3.78
Financial per Weighted Average Trust Units(2)
Cash Flow from Operating Activities $2.33 $1.80 $6.32 $5.22
Cash Withheld for Acquisitions and Capital
Expenditures 0.97 0.54 2.42 1.42
Net Income 2.82 0.72 4.40 1.90
Payout Ratio(3) 59% 70% 62% 73%
Selected Financial Results per BOE (4)
Oil & Gas Sales(5) $73.62 $49.64 $72.44 $49.89
Royalties (13.71) (9.28) (13.54) (9.38)
Commodity Derivative Instruments (6.82) 1.00 (5.19) 0.63
Operating Costs (10.10) (9.61) (9.51) (9.32)
General and Administrative (1.50) (2.11) (1.66) (2.00)
Interest and Other Income and Foreign
Exchange (1.46) (1.34) (1.23) (1.34)
Taxes (0.59) (0.70) (1.19) (0.46)
Restoration and Abandonment (0.54) (0.48) (0.52) (0.47)
Page 3 of 40
Cash Flow from Operating Activities before
changes in non-cash working capital $38.90 $27.12 $39.60 $27.55
Weighted Average Number of Trust Units
Outstanding Including Equivalent Exchangeable
Limited Partnership Units (thousands) 164,908 129,373 158,980 127,025
Debt/Trailing 12 Month Cash Flow Ratio(6) 0.4x 0.7x 0.4x 0.7x

SELECTED OPERATING RESULTS
Three months ended September 30, Nine months ended September 30,
2008 2007 2008 2007
Average Daily Production
Natural gas (Mcf/day) 341,803 251,264 336,328 263,884
Crude oil (bbls/day) 34,119 34,077 34,295 34,602
NGLs (bbls/day) 4,557 3,937 4,660 4,194
Total (BOE/day) 95,644 79,891 95,010 82,777
% Natural gas 60% 52% 59% 53%
Average Selling Price (5)
Natural gas (per Mcf) $8.25 $5.59 $8.60 $6.63
Crude oil (per bbl) 110.63 69.16 103.85 62.75
NGLs (per bbl) 81.20 50.79 77.21 49.26
US$ exchange rate 0.96 0.96 0.98 0.91
Net Wells drilled 272 101 469 177
Success Rate 99% 99% 99% 99%
(1) Calculated based on distributions paid or payable.
(2) Based on weighted average trust units outstanding for the period, including the exchangeable limited partnership units assumed through the Focus
Energy Trust acquisition.
(3) Calculated as Cash Distributions to Unitholders divided by Cash Flow from Operating Activities.

See "Non-GAAP Measures" in the following
Management"s Discussion and Analysis.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
(6) Including the trailing 12 month cash flow of Focus Energy Trust.
Trust Unit Trading Summary TSX - ERF.un NYSE - ERF
For the three months ended September 30, 2008 (CDN$) (US$)
High $48.15 $47.47
Low $35.57 $33.64
Close $38.86 $37.19
2008 Cash Distributions Per Trust Unit
Payment Month CDN$ US$
First Quarter Total $1.26 $1.23
Second Quarter Total $1.26 $1.25
July $0.42 $0.42
August 0.42 0.39
September 0.47 0.45
Third Quarter Total $1.31 $1.26
Total Year-to-Date $3.83 $3.74

2008 Production and Development Activity
Three months ended September 30, Nine months ended September 30,
Wells Drilled* Wells Drilled*
Play Type
Production
Volumes
(BOE/day)
Capital
Spending
($ millions) Gross Net
Production
Volumes
(BOE/day)
Capital
Spending
($ millions) Gross Net
Shallow Gas & CBM 23,479 $55.0 254 235 23,183 $ 101.3 471 394
Crude Oil Waterfloods 16,904 19.7 20 18 16,061 47.6 42 28
Deep Tight Gas 15,730 11.0 22 3 14,431 42.8 52 8
Bakken/Tight Oil 10,118 45.0 3 2 10,778 78.0 11 8
Other Conventional Oil
& Gas 29,413 26.7 78 14 30,557 67.6 157 31
Total Conventional 95,644 157.4 377 272 95,010 337.3 733 469
Check
Oil Sands
Kirby - 5.0 - - - 29.5 - -
Other Oil Sands - 0.8 - - - 10.7 - -
Total Oil Sands - 5.8 - - - 40.2 - -
Total 95,644 $163.2 377 272 95,010 $377.5 733 469
* Drilling totals do not include delineation wells at Kirby or service wells
Drilling success rate year-to-date: 99%
Development capital spending was $163.2 million in the third quarter and $377.5 million for the year.

Our activities
have included both oil and natural gas projects however a greater concentration of spending was directed at natural
gas opportunities during the quarter.

A total of 272 net wells were drilled in the third quarter, the majority of which
were at Shackleton, our largest and most profitable shallow natural gas property which is located in southwest
Saskatchewan.
Our crude oil activities were concentrated on our waterflood properties and our Bakken oil property in the U.S.

In
Alberta, a key waterflood development project was undertaken at our Giltedge property where we drilled 13 wells and
have identified further development potential associated with the significant amount of oil remaining in this pool.

In the
U.S.

we also continued our refrac program and our third well per section drilling program on our Sleeping Giant field.
We continue to be encouraged by the performance from this field and plan to continue our drilling program into 2009.
As a result of this activity, we expect our capital spending to increase from approximately $60 million to between $70
million and $80 million in this area in 2008.

The aggressive pace of Bakken development in Montana and North
Dakota continues to be a concern as pipeline capacity has not kept pace with production growth.

Through
management of our inventory volumes, we have not faced any significant production curtailments to date, however
we have seen an increase in transportation differentials which have impacted our netbacks.

We continue to monitor
the situation closely.
Overall, our investment activities are aimed at helping to replace our annual production volumes and establishing
future development opportunities for the years to come.

During the quarter, we invested approximately $43 million
primarily on the purchase of land in the Montney region of Alberta and British Columbia and the Bakken region of
southeast Saskatchewan and oil sands project work.

Year-to-date, our pre-investment spending has totaled
approximately $87 million, approximately one half of which has been invested in our Kirby oil sands lease and the
majority of the remainder being invested in undeveloped land.
Oil Sands Activities
Enerplus achieved another milestone during the quarter on our operated Kirby steam assisted gravity drainage
("SAGD") Oil Sands project by filing our regulatory application for the first phase of development "(Phase 1") with the
Energy Resources Conservation Board and Alberta Environment on September 26, 2008, slightly earlier than
expected.

We plan to continue to advance the Kirby project to be in a position to present this project for a sanctioning
Page 5 of 40
decision by our Board of Directors once we receive regulatory approval and have completed additional engineering
design planning.

We expect to be in this position by the fourth quarter of 2009.

We are also continuing to delineate
the lease to set up expansion of this project over time.
Phase 1 of the Kirby lease consists of a 10,000 bbl/day SAGD development that we expect to produce bitumen for
approximately 25 years.

We tentatively plan to begin construction in 2009 following regulatory approval.

First steam
is anticipated in late 2011, first production is expected in 2012 and full commercial production volumes of 10,000
bbls/day are expected in 2013.

Our current estimate of the capital costs associated with construction of Phase 1 is
approximately $400 million (2008 dollars).
Our 2007/08 winter drilling program was focused on delineating the northern block of the lease which is where Phase
I will be located.

Based on the results of this delineation work, our third party reserve engineers have confirmed a
best estimate contingent resource of approximately 414 million barrels, a 70% increase from the original resource
estimate completed when we purchased the lease in the spring of 2007.

The following table summarizes the
contingent resource estimate for the Kirby Lease:
Northern Area Wabiskaw D (Project area) 118 million barrels
Northern Area McMurray 191 million barrels
Central and Southern Areas 105 million barrels
Total Kirby Lease Contingent Resource Estimate 414 million barrels
For additional information relating to contingent resource estimates, see "Information Regarding Contingent Resource Estimates" in
the following Management"s Discussion and Analysis.

As well, for additional information regarding our Kirby Oil Sands project, see
pages 16 and 17 of our Annual Information Form for the year ended December 31, 2007, a copy of which is available on our
SEDAR profile at www.sedar.com and which also forms part of our Form 40-F for the year ended December 31, 2007 filed with the
SEC, a copy of which is available at www.sec.gov.
Looking Ahead
We are experiencing unprecedented volatility in the commodity, credit and equity markets on a global scale not seen
in decades.

We are fortunate to be in a position of strength not only due to the opportunities we have within our asset
base, but also the financial flexibility we have with over $1.1 billion of available credit capacity.

We will continue to
invest in our assets and will evaluate opportunities for acquisitions in this attractive market, but we will do so
judiciously.

We believe that in tumultuous times like these, it is in our best interest to maintain our financial flexibility
by controlling costs and managing our cash flows.

I believe we will not only weather these uncertain times as we
have previously in our 22 year history but that we will attract new highly skilled people and capture opportunities
which will allow us to further build and strengthen our company.
MANAGEMENT"S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated November 6, 2008 and is to be read in conjunction
with:
• the audited consolidated financial statements as at and for the years ended December 31, 2007 and 2006;
and
• the unaudited interim consolidated financial statements as at and for the three and nine months ended
September 30, 2008 and 2007.
All amounts are stated in Canadian dollars unless otherwise specified.

All references to GAAP refer to Canadian
generally accepted accounting principles.

All note references relate to the notes included with the accompanying
unaudited interim consolidated financial statements.

In accordance with Canadian practice revenues are reported on
a gross basis, before deduction of Crown and other royalties, unless otherwise stated.

Where applicable, natural gas
has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE.

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
wellhead.

Use of BOE in isolation may be misleading.
The following MD&A contains forward-looking information and statements.

We refer you to the end of the MD&A for
our disclaimer on forward-looking information and statements.
Page 6 of 40
NON-GAAP MEASURES
Throughout the MD&A we use the term "payout ratio" to analyze operating performance, leverage and liquidity.

We
calculate payout ratio by dividing cash distributions to unitholders ("cash distributions") by cash flow from operating
activities ("cash flow"), both of which are measures prescribed by GAAP which appear on our consolidated
statements of cash flows.

The term "payout ratio" does not have a standardized meaning or definition as prescribed
by GAAP and therefore may not be comparable with the calculation of similar measures by other entities.
Refer to the "Liquidity and Capital Resources" section of the MD&A for further information on cash flow, cash
distributions and payout ratio.
OVERVIEW
Cash flow from operating activities for the third quarter increased to $383.6 million from $364.5 million in the second
quarter, largely due to decreases in our non-cash operating working capital.

Our payout ratio was 59% for the
quarter and 62% year to date.

Commodity prices remained strong for most of the quarter however the sharp decline
in prices towards the end of the quarter resulted in $280.7 million of non-cash gains on our commodity derivative
instruments.

We received net proceeds of $502.0 million for the Joslyn disposition on July 31, 2008 which was used
to pay down debt.

At September 30, 2008 our balance sheet remains strong with a trailing 12 month debt to cash flow
ratio of 0.4x, leaving us with available capacity of over $1.1 billion on our $1.4 billion credit facility.
Our year-to-date development capital spending totaled $377.5 million and is behind schedule mainly due to weather
and project delays at both operated and non-operated properties.

Based on our year-to-date spending and project
deferrals and cancellations in the fourth quarter we are revising our annual development capital guidance to $545
million from $580 million, based on a $55 million reduction in our conventional program which is partially offset by $20
million of additional land acquisitions.
Production for the quarter was 95,644 BOE/day, slightly lower than expected due to a combination of development
delays and unplanned facility downtime.

Given our year-to-date results and revised capital program we are
decreasing our annual average production guidance from 98,000 BOE/day to 96,000 BOE/day and our 2008 exit rate
guidance from 100,000 BOE/day to 98,500 BOE/day.

In conjunction with the revised production estimates we are
increasing our operating cost guidance from $9.00/BOE to $9.50/BOE however our general and administrative
expense guidance is being revised downwards to $2.00/BOE from $2.20/BOE primarily due to decreased expenses
associated with our long-term compensation plans.
The significant decrease in commodity prices combined with the current uncertainty in the capital markets has
reinforced our belief in the importance of maintaining strong financial flexibility therefore we have lowered our monthly
cash distribution to $0.38 per unit from $0.47 per unit effective November 20, 2008.
RESULTS OF OPERATIONS
Production
Production in the third quarter of 2008 averaged 95,644 BOE/day, a decrease of 5% from 100,188 BOE/day in the
second quarter of 2008.

The decrease for the quarter was primarily due to capital project delays and unplanned
downtime at our non-operated plants including Brooks South, K3, McMahon and Elmworth.

We also experienced tiein
delays at our operated Shackleton property during the quarter as we were assessing alternative well completion
techniques.

As a result of these capital delays and unplanned downtime, we are reducing our annual average
production guidance from 98,000 BOE/day to 96,000 BOE/day and our 2008 exit rate from 100,000 BOE/day to
98,500 BOE/day.
For the three and nine months ended September 30, 2008 production increased 20% and 15% respectively,
compared to the same periods in 2007.

These increases were primarily due to the additional production from the
Focus Energy Trust ("Focus") assets acquired on February 13, 2008.
Average production volumes for the three and nine months ended September 30, 2008 and 2007 are outlined below:
Page 7 of 40
Three months ended September 30, Nine months ended September 30,
Daily Production Volumes 2008 2007 % Change 2008 2007 % Change
Natural gas (Mcf/day) 341,803 251,264 36% 336,328 263,884 27%
Crude oil (bbls/day) 34,119 34,077 -% 34,295 34,602 (1)%
Natural gas liquids bbls/day) 4,557 3,937 16% 4,660 4,194 11%
Total daily sales (BOE/day) 95,644 79,891 20% 95,010 82,777 15%
Pricing
The prices received for our natural gas and crude oil production have a direct impact on our earnings, cash flow and
financial condition.

The following table compares our average selling prices, net of transportation costs, for the three
and nine months ended September 30, 2008 and 2007.

It also compares the benchmark price indices for the same
periods:
Three months ended September 30, Nine months ended September 30,
Average Selling Price(1) 2008 2007 % Change 2008 2007 % Change
Natural gas (per Mcf) $ 8.25 $ 5.59 48% $ 8.60 $ 6.63 30%
Crude oil (per bbl) $110.63 $69.16 60% $103.85 $62.75 65%
Natural gas liquids (per bbl) $81.20 $50.79 60% $77.21 $49.26 57%
Per BOE $73.62 $49.64 48% $72.44 $49.89 45%
Average Benchmark Pricing
AECO natural gas - monthly index
(CDN$/Mcf) $ 9.25 $ 5.61 65% $ 8.58 $ 6.81 26%
AECO natural gas - daily index (CDN$/Mcf) $ 7.75 $ 5.18 50% $ 8.62 $ 6.55 32%
NYMEX natural gas - monthly NX3 index
(US$/Mcf) $ 10.09 $ 6.13 65% $ 9.65 $ 6.88 40%
NYMEX natural gas - monthly NX3 index
CDN$ equivalent (CDN$/Mcf) $ 10.51 $ 6.39 64% $ 9.85 $ 7.56 30%
WTI crude oil (US$/bbl) $117.98 $75.38 57% $113.29 $66.23 71%
WTI crude oil CDN$ equivalent (CDN$/bbl) $122.90 $78.52 57% $115.60 $72.78 59%
CDN$/US$ exchange rate 0.96 0.96 -% 0.98 0.91 8%
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
During the quarter the AECO natural gas price fell approximately 51% from a high of $11.83/Mcf on July 1 to a low of
$5.79/Mcf at the end of September.

This sharp decrease was triggered by significant increases in U.S.

natural gas
production and reduced demand caused by moderate cooling loads and a weakening economy.
We realized an average price on our natural gas of $8.25/Mcf during the three months ended September 30, 2008,
an increase of 48% from $5.59/Mcf for the same period in 2007.

For the nine months ended September 30, 2008 we
realized a 30% increase in our average price of $8.60/Mcf compared to the same period in 2007.

The majority of our
natural gas sales are priced with reference to the monthly or daily AECO indices.

The 30% increase for the nine
month period is comparable to the increases experienced by the AECO indices over the same period.

However, the
increases in our current quarter realized gas prices over the same period in 2007 were lower than the increases in
the AECO indices over the same periods due to lower prices received for our U.S.

natural gas production resulting
from excess supply in the region and the fact that a small portion of our Canadian natural gas sold at a discount to
the August month index with the sharp decline in prices during the month of July.
Crude oil prices fell 37%, from US$145.29/bbl to US$91.15/bbl, during the third quarter in response to demand
destruction as the threat of a global economic slowdown grew.

The average price we received for our crude oil
during the three months ended September 30, 2008 increased 60% to $110.63/bbl compared to $69.16/bbl during
the same period in 2007.

Similarly, the West Texas Intermediate ("WTI") crude oil benchmark price, in Canadian
dollars, increased 57% from the corresponding period in 2007.

For the nine months ended September 30, 2008 our
crude oil price increased 65% to $103.85/bbl, while the WTI benchmark, in Canadian dollars, increased 59%.

The
narrowing of the market differential for our heavy oil production was the main contributor to the higher year-over-year
price increase received on our crude oil relative to the increase in WTI.
For the third quarter of 2008 the Canadian dollar remained unchanged against the U.S.

dollar relative to the same
period in 2007.

The Canadian dollar strengthened against the U.S.

dollar during the nine months ended September
30, 2008 compared to the same period in 2007.

As most of our crude oil and natural gas sales are priced in
reference to U.S.

dollar denominated benchmarks, this movement in the exchange rate reduced the Canadian dollar
prices that we would have otherwise realized.
Page 8 of 40
Since the end of the third quarter there has been a dramatic reduction in crude oil prices and to a lesser extent
natural gas prices in response to the global credit crisis and concerns over the health of economies around the world.
The impact of these lower prices has been partially offset by a weaker Canadian dollar which helps energy producers
such as Enerplus.

As at October 28, 2008 crude oil prices (WTI) and natural gas prices (AECO) had fallen to U.S.
$62.73/bbl and $7.16/Mcf respectively from September 30, 2008 partially offset by a 22% change in the CDN$/US$
exchange rate to 0.77.
Price Risk Management
We continue to evolve our price risk management framework in response to the increased volatility of the commodity
price environment.

Consideration is given to our overall financial position together with the economics of our
development capital program and potential acquisitions.

Consideration is also given to the upfront and potential costs
of our risk management program as we seek to limit our exposure to price downturns.

Hedge positions for any given
term are transacted across a range of prices and time.
Considering all financial contracts transacted as of October 28, 2008, we have protected a portion of our natural gas
price risk through to October 31, 2009 and a portion of our crude oil price risk through to December 31, 2009.

We
have also taken steps to protect our exposure to rising electricity costs for a portion of our consumption in the Alberta
power market through to December 31, 2010.

See Note 9 for a list of our current price risk management positions.
The following is a summary of the financial contracts in place at October 28, 2008, expressed as a percentage of our
forecasted net production volumes:
Natural Gas (CDN$/Mcf)
Crude Oil (US$/bbl)
October 1,
2008 -
October 31,
2008
November 1,
2008 - March
31, 2009
April 1, 2009 -
October 31,
2009
October 1,
2008 -
December 31,
2008
January 1,
2009 -
December 31,
2009
Floor Price (puts) $7.09 $9.20 $9.01 $72.09 $98.08
% (net of royalties) 26% 23% 8% 35% 26%
Fixed Price (swaps) $7.44 $9.35 $7.86 $79.97 $100.05
% (net of royalties) 21% 3% 2% 19% 2%
Capped Price (calls) $8.25 $11.60 - $85.48 $92.98
% (net of royalties) 26% 11% - 22% 11%
Based on weighted average price (before premiums), estimated average annual production of 96,000 BOE/day and assuming a
royalty rate of 19% in 2008 and 22% in 2009.
Accounting for Price Risk Management
During the third quarter of 2008 our price risk management program incurred cash losses of $18.8 million on our
natural gas contracts and $41.2 million on our crude oil contracts, compared to cash gains of $14.1 million and cash
losses of $6.7 million respectively during the third quarter of 2007.

For the nine months ended September 30, 2008
we experienced cash losses of $30.6 million on our natural gas contracts and cash losses of $104.4 million on our
crude oil contracts, compared to a gain of $12.8 million and a gain of $1.4 million respectively for the same period in
2007.

The increase in cash losses for the three and nine months ended September 30, 2008 compared to the
corresponding periods in 2007 was the result of commodity prices rising above our swap and sold call positions.

As
noted above, commodity prices have continued to decrease since the end of the third quarter which we believe will
result in improved performance of our price risk management program in the fourth quarter of 2008.
The fair value of our commodity derivative instruments was impacted by the significant decrease in forward
commodity prices at September 30, 2008 compared to June 30, 2008.

At September 30, 2008 the fair value of our
natural gas derivative instruments represented a gain of $14.0 million and the fair value of our crude oil derivative
instruments represented a loss of $22.4 million.

In comparison, at June 30, 2008 the fair value of our natural gas and
crude oil derivative instruments represented losses of $89.9 million and $199.2 million respectively.

The change in
fair value of our commodity derivative instruments during the third quarter of 2008 resulted in unrealized gains of
$280.7 million which was comprised of $103.9 million for natural gas and $176.8 million for crude oil.

For the nine
months ended September 30, 2008 the change in fair value of our commodity derivative instruments resulted in
unrealized gains of $5.9 million for natural gas and $34.4 million for crude oil.

See Note 9 for details.
The following table summarizes the effects of our financial contracts on income:
Page 9 of 40
Risk Management Costs Three months ended September 30, Three months ended September 30,
($ millions, except per unit amounts) 2008 2007
Cash (losses)/gains:
Natural gas $ (18.8) $ (0.60)/Mcf $ 14.1 $0.61/Mcf
Crude oil (41.2) (13.13)/bbl (6.7) (2.14)/bbl
Total cash (losses)/gains $ (60.0) $(6.82)/BOE $ 7.4 $1.00/BOE
Non-cash gains/(losses) on financial
contracts:
Change in fair value - natural gas $103.9 $3.30/Mcf $2.8 $0.12/Mcf
Change in fair value - crude oil 176.8 56.30/bbl (6.6) (2.12)/bbl
Total non-cash gains/(losses) $280.7 $31.90/BOE $(3.8) $(0.51)/BOE
Total gains $220.7 $25.08/BOE $3.6 $0.49/BOE
Risk Management Costs Nine months ended September 30, Nine months ended September 30,
($ millions, except per unit amounts) 2008 2007
Cash (losses)/gains:
Natural gas $(30.6) $(0.33)/Mcf $12.8 $0.18/Mcf
Crude oil (104.4) (11.11)/bbl 1.4 0.15/bbl
Total cash (losses)/gains $(135.0) $(5.19)/BOE $14.2 $0.63/BOE
Non-cash gains/(losses) on financial
contracts:
Change in fair value - natural gas $5.9 $0.06/Mcf $7.6 $0.11/Mcf
Change in fair value - crude oil 34.4 3.66/bbl (25.8) (2.74)/bbl
Total non-cash gains/(losses) $40.3 $1.55/BOE $(18.2) $(0.81)/BOE
Total (losses) $(94.7) $(3.64)/BOE $(4.0) $(0.18)/BOE
Cash Flow Sensitivity
The sensitivities below reflect the estimated impact on cash flow per trust unit for the remaining quarter of 2008 and
include the commodity contracts described in Note 9 as well as the impact of 2008 forward market prices as at
October 28, 2008.

We have not finalized our budget or plans for 2009 and consequently 2009 sensitivities are not
available.

To the extent the market price of crude oil and natural gas change significantly from the October 28, 2008
levels, the sensitivities will no longer be relevant as the effect of our commodity contracts will change.
Sensitivity Table
Estimated Effect on
Fourth Quarter 2008
Cash Flow per Trust Unit (1)
Change of $0.15 per Mcf in the price of AECO natural gas $0.02
Change of US$1.00 per barrel in the price of WTI crude oil $0.01
Change of 1,000 BOE/day in production $0.02
Change of $0.01 in the US$/CDN$ exchange rate $0.03
Change of 1% in interest rate $0.01
(1) Assumes constant working capital and 165,197,000 units outstanding.
The impact of a change in one factor may be compounded or offset by changes in other factors.

This table does not consider the
impact of any inter-relationship among the factors.
Revenues
Crude oil and natural gas revenues were lower during the third quarter of 2008 compared to the second quarter of
2008 due to decreased commodity prices and lower production.
Crude oil and natural gas revenues for the three months ended September 30, 2008 were $647.8 million ($654.6
million, net of $6.8 million transportation) compared to $364.8 million ($370.2 million, net of $5.4 million
transportation) for the same period in 2007.

For the nine months ended September 30, 2008 revenues were
$1,885.9 million ($1,906.1 million, net of $20.2 million transportation) compared to $1,127.3 million ($1,144.0 million,
net of $16.7 million transportation) during the same period in 2007.

Revenues have increased compared to 2007 due
to higher commodity prices and increased production resulting from the Focus acquisition which closed on February
13, 2008.
The following table summarizes the changes in sales revenue:
Page 10 of 40
Analysis of Sales Revenue (1)
($ millions)
Crude Oil
NGLs Natural Gas
Total
Quarter ended September 30, 2007 $216.8 $18.4 $129.6 $364.8
Price variance(1) 130.2 12.7 86.8 229.7
Volume variance 0.3 2.9 50.1 53.3
Quarter ended September 30, 2008 $347.3 $34.0 $266.5 $647.8
($ millions)
Crude Oil
NGLs Natural Gas
Total
Year-to-date ended September 30, 2007 $592.7 $56.4 $478.2 $1,127.3
Price variance(1) 386.3 35.7 190.7 612.7
Volume variance (3.1) 6.5 142.5 145.9
Year-to-date ended September 30, 2008 $975.9 $98.6 $811.4 $1,885.9
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
Other Income
Other income for the three and nine months ended September 30, 2008 was $0.3 million and $15.8 million
respectively, compared to $0.1 million and $14.6 million for the same periods in 2007.

The first nine months of 2008
includes a gain of $8.3 million on the sale of certain marketable securities and interim receipts from our business
interruption insurance of $6.4 million related to the Giltedge fire.

During the first quarter of 2007 we realized a gain of
$14.1 million on the sale of marketable securities.
Royalties
Royalties are paid to various government entities and other land and mineral rights owners.

For the three and nine
months ended September 30, 2008 royalties were $120.6 million and $352.5 million respectively, compared to $68.2
million and $211.9 million for the same periods in 2007.

Royalties as a percentage of oil and gas sales net of
transportation have been approximately 19% during these periods.

The increases in royalties in 2008 are the result
of higher commodity prices and increased production.

For the remainder of 2008 we expect royalties to continue to
be approximately 19% of oil and gas sales, net of transportation.
In October 2007 the Alberta government announced a ‘New Royalty Framework" ("NRF") which will be effective
January 1, 2009 and is expected to increase our royalties as a percentage of oil and gas sales.

In the context of an
annualized forward market outlook of US$70.00/bbl crude oil and $8.00/Mcf natural gas, and relative to Enerplus"
current properties and production profile in Alberta, we estimate the NRF will increase our average 2009 royalty rate
to approximately 22% of oil and gas sales, net of transportation costs.

If commodity prices are higher than such
estimates, we expect our average royalty rate for 2009 to increase as well.

Further information on the NRF can be
found on the Alberta government"s website at www.gov.ab.ca.
Operating Expenses
Operating expenses for the third quarter of 2008 increased to $89.8 million ($10.21/BOE) from $86.0 million
($9.43/BOE) during the second quarter of 2008 due to lower production volumes along with higher repairs and
maintenance and chemical and supply costs.
Operating expenses for the three months ended September 30, 2008 were $89.8 million ($10.21/BOE) compared to
$71.6 million ($9.73/BOE) for the third quarter of 2007.

For the nine months ended September 30, 2008 operating
expenses were $247.8 million ($9.52/BOE) compared to $210.3 million ($9.31/BOE) for the same period in 2007.
This year-over-year increase is due to additional service rig activity related to our U.S.

optimization program and
higher than expected costs for repairs and maintenance, labour, and chemicals and supplies.
Based on our year to date results and our revised 2008 production expectations we are increasing our annual
operating expense guidance from $9.00/BOE to $9.50/BOE.
General and Administrative Expenses ("G&A")
During the third quarter of 2008 G&A expenses were $1.70/BOE compared to $1.90/BOE for the second quarter of
2008.
G&A expenses for the three months ended September 30, 2008 were $14.9 million ($1.70/BOE) compared to $17.7
million ($2.41/BOE) for the third quarter of 2007.

G&A expenses totaled $48.7 million ($1.87/BOE) for the nine
Page 11 of 40
months ended September 30, 2008 compared to $51.5 million ($2.28/BOE) for the same period in 2007.

G&A
expenses have decreased year over year mainly due to lower long-term incentive plan expenses.

However, higher
production volumes during 2008 which are attributable to the Focus acquisition have helped to reduce G&A costs
per BOE.
We do not expect our long-term compensation expense to change over the next quarter, therefore we are lowering
our annual guidance for G&A expenses from $2.20/BOE to $2.00/BOE for the year.
For the three and nine months ended September 30, 2008 our G&A expenses included non-cash charges of $1.8
million ($0.20/BOE) and $5.4 million ($0.21/BOE) respectively, compared to $2.2 million ($0.30/BOE) and $6.4 million
($0.28/BOE) for the same periods in 2007.

These amounts relate solely to our trust unit rights incentive plan and are
determined using a binomial lattice option-pricing model.

See Note 8 for further details.
The following table summarizes the cash and non-cash expenses recorded in G&A:
General and Administrative Costs Three months ended September 30, Nine months ended September 30,
($ millions) 2008 2007 2008 2007
Cash $13.1 $15.5 $43.3 $45.1
Trust unit rights incentive plan (non-cash) 1.8 2.2 5.4 6.4
Total G&A $14.9 $17.7 $48.7 $51.5
(Per BOE) 2008 2007 2008 2007
Cash $1.50 $2.11 $1.66 $2.00
Trust unit rights incentive plan (non-cash) 0.20 0.30 0.21 0.28
Total G&A $1.70 $2.41 $1.87 $2.28
Interest Expense
Interest expense includes interest on long-term debt, the premium amortization on our US$175 million senior
unsecured notes, unrealized gains and losses resulting from the change in fair value of our interest rate swaps as
well as the interest component on our cross currency interest rate swap ("CCIRS").

See Note 6 for further details.
Interest on long-term debt was $8.8 million for the third quarter of 2008 compared to $10.4 million for the same period
in 2007.

Lower year over year average debt resulting from the July 31, 2008 Joslyn disposition is the primary reason
for the decrease.

For the nine months ended September 30, 2008 interest on long-term debt totaled $35.1 million
compared to $29.8 million for the same period in 2007.

This increase is due to higher average outstanding
indebtedness and higher interest rates for the nine months ended September 30, 2008 over the same period in 2007.
For the three and nine months ended September 30, 2008 we recorded non-cash interest gains of $1.6 million for
both periods compared to gains of $4.0 million and $3.4 million for the same periods in 2007.

The changes in the fair
value of our interest rate swaps and CCIRS that result from movements in forward market interest rates cause noncash
interest to fluctuate between periods.
The following table summarizes our cash and non-cash interest expense:
Interest Expense Three months ended September 30, Nine months ended September 30,
($ millions) 2008 2007 2008 2007
Interest on long-term debt $8.8 $10.4 $35.1 $29.8
Non-cash interest gain (1.6) (4.0) (1.6) (3.4)
Total Interest Expense $7.2 $6.4 $33.5 $26.4
At September 30, 2008 approximately 34% of our debt was based on fixed interest rates while 66% had floating
interest rates.

In comparison, at September 30, 2007 approximately 20% of our debt was based on fixed interest
rates and 80% was floating.
Capital Expenditures
Development capital spending for the three and nine months ended September 30, 2008 was $163.2 million and
$377.5 million respectively, compared to $90.6 million and $281.0 million during the same periods in 2007.

The
increased spending levels in 2008 are largely due to our expanded asset base resulting from the Focus acquisition
and stronger commodity prices.

In addition our 2008 development capital expenditures include approximately $20
million of completed incremental land acquisitions over original budget amounts as we look to increase our efforts on
Page 12 of 40
resource capture in strategic areas.

For the nine months ended September 30, 2008 we have achieved a 99%
drilling success rate on 469 net wells.
Overall our 2008 development capital program is behind schedule mainly due to weather and project delays primarily
in our shallow natural gas program.

Based on our year-to-date spending and project deferrals and cancellations in
the fourth quarter we are revising our annual development capital guidance to $545 million from $580 million, based
on a $55 million reduction in our conventional program which is partially offset by the $20 million we have spent on
additional land acquisitions.

The reduction and reallocation of expenditures within our 2008 development capital
program has modestly lowered our 2008 average annual production and exit rate expectations.
Corporate acquisitions for the nine months ended September 30, 2008 totaled approximately $1.7 billion and relate to
the Focus acquisition which closed February 13, 2008 (refer to Note 4 for further details).

Property dispositions for
the three months ended September 30, 2008 relate to the Joslyn disposition which closed on July 31, 2008.
Property acquisitions for the three and nine months ended September 30, 2008 were $4.6 million and $13.9 million
respectively, compared to $1.8 million and $269.1 million for the same periods in 2007.

Property acquisitions in 2007
included the purchase of our Jonah and Kirby assets in the first and second quarter of 2007 respectively.
Total net capital expenditures for 2008 and 2007 are outlined below:
Three months ended September 30, Nine months ended September 30,
Capital Expenditures ($ millions) 2008 2007 2008 2007
Development expenditures $131.7 $72.1 $299.9 $232.3
Plant and facilities 31.5 18.5 77.6 48.7
Development Capital 163.2 90.6 377.5 281.0
Office 2.4 1.7 6.0 4.6
Sub-total 165.6 92.3 383.5 285.6
Property acquisitions(1) 4.6 1.8 13.9 269.1
Corporate acquisitions - - 1,757.5 -
Capital Expenditures 170.2 94.1 2,154.9 554.7
Property dispositions(1) (502.5) (0.1) (504.7) (5.5)
Total Net Capital Expenditures $(332.3) $94.0 $1,650.2 $549.2
Funding of Capital Expenditures
Capital Expenditures financed with cash flow $ 159.2 $69.7 $ 385.1 $180.1
Capital Expenditures financed with debt and
equity 11.0 24.4
1,769.8 374.6
Total Capital Expenditures $ 170.2 $94.1 $2,154.9 $554.7
(1) Net of post-closing adjustments.
Oil Sands
Our oil sands development projects have not commenced commercial production.

As a result all associated costs
inclusive of acquisition expenditures, development capital spending, salaries and benefits, engineering and planning,
net of revenues generated, are capitalized and excluded from our depletion calculation.

At September 30, 2008
capitalized costs life-to-date for our oil sands development were $246.0 million compared to $351.1 million at June
30, 2008, prior to our disposition of Joslyn on July 31, 2008 for cash consideration of $502.0 million after transaction
costs.
During the third quarter of 2008 we capitalized costs of $4.4 million associated with advancing our regulatory
application for our Kirby project, which we successfully filed on September 26, 2008.
We continue to hold an interest in Laricina Energy Ltd., a private company with significant resources in the Alberta oil
sands.

This interest represents approximately 12% of Laricina"s outstanding equity.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on
proved reserves.
For the three months ended September 30, 2008, DDA&A increased to $18.32/BOE compared to $15.78/BOE during
the corresponding period in 2007.

For the nine months ended September 30, 2008 DDA&A increased to $18.19/BOE
Page 13 of 40
compared to $15.58/BOE during the corresponding period in 2007.

The increase is attributable to additional PP&E
and production from the Focus acquisition.
No impairment of the Fund"s assets existed at September 30, 2008 using year-end reserves updated for acquisitions,
divestitures and management"s estimates of future prices.
Asset Retirement Obligations
In connection with our operations, we anticipate we will incur abandonment and reclamation costs for surface leases,
wells, facilities and pipelines.

Total future asset retirement obligations included on the Fund"s balance sheet are
estimated by management based on the Fund"s net ownership interest in wells and facilities, estimated costs to
abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods.
The Fund has estimated the net present value of its total asset retirement obligations to be approximately $203.8
million at September 30, 2008 compared to $165.7 million at December 31, 2007.

The increase of $38.1 million
relates primarily to the Focus acquisition.

See Note 3.
The following chart compares the amortization of the asset retirement cost, accretion of the asset retirement
obligation and asset retirement obligations settled during the period:
Three months ended September 30, Nine months ended September 30,
($ millions) 2008 2007 2008 2007
Amortization of the asset retirement cost $ 4.9 $3.4 $ 14.7 $6.9
Accretion of the asset retirement
obligation 3.1 1.7 8.7 5.0
Total Amortization and Accretion $ 8.0 $5.1 $ 23.4 $11.9
Asset Retirement Obligations Settled $ 4.7 $3.5 $ 13.5 $10.7
The timing of actual asset retirement costs will differ from the timing of amortization and accretion charges.

Actual
asset retirement costs will be incurred over the next 66 years with the majority between 2038 and 2047.

For
accounting purposes, the asset retirement cost is amortized using a unit-of-production method based on proved
reserves before royalties while the asset retirement obligation accretes until the time the obligation is settled.
Taxes
Future Income Taxes
Future income taxes arise from differences between the accounting and tax bases of assets and liabilities.

A portion
of the future income tax liability that is recorded on the balance sheet will be recovered through earnings before 2011.
Our future income tax expense was $1.4 million for the quarter ended September 30, 2008 compared to a recovery of
$8.8 million for the same period in 2007.

The increased expense is the result of commodity derivative instrument
gains during the third quarter of 2008 which were partially offset by a future tax recovery related to the Joslyn
disposition that closed July 31, 2008.
In July 2008, the Department of Finance issued draft amendments to the Income Tax Regulations regarding the
provincial tax rate for new specified investment flow through ("SIFT") entities.

These amendments are generally
designed to tax SIFT entities at the same level as a corporation and are expected to be enacted later in 2008 and be
effective January 1, 2011.

The amendments were not considered substantively enacted at September 30, 2008.

As a
result there was no consequential impact on future income taxes in the third quarter however this will result in a future
income tax recovery when enacted.
The Department of Finance has released draft legislative proposals which include amendments to allow a SIFT to
convert into a corporation without adverse Canadian tax consequences for the trust or its Canadian unitholders.

We
believe that a trust conversion under the proposed rules would qualify as a U.S.

tax deferred transaction for our U.S.
unitholders as well.

Enerplus submitted comments on these proposals as permitted by the Canadian Department of
Finance.

We continue to review the legislative proposals to determine the impact to Enerplus should we convert into
a corporation.
Page 14 of 40
Current Income Taxes
In our current structure payments are made between the operating entities and the Fund, which ultimately transfers
both the income and future tax liability to our unitholders.

As a result no cash income taxes have been paid by our
Canadian operating entities.

However, an income tax liability of $24.3 million was triggered on the acquisition of
Focus.

This liability was included in Focus" assumed working capital and was paid in April 2008.

We expect to
recover the majority of this amount during 2008 as a result of claiming taxable deductions.

For the nine months
ended September 30, 2008 we have recorded $16.9 million in recoveries related to the $24.3 million.
The amount of current taxes recorded with respect to our U.S.

operations is dependent upon income levels along with
the timing of capital expenditures and the repatriation of funds to Canada.

For the three and nine months ended
September 30, 2008 our U.S.

operations incurred taxes (income and withholding) in the amount of $14.2 million and
$47.9 million respectively, compared to $5.1 and $10.4 million during the same periods in 2007.

The increase in
current taxes was due to an increase in net income combined with a decrease in capital expenditures
in 2008.
We expect our U.S.

current income and withholding taxes to average approximately 25% of cash flow from U.S.
operations based on current commodity prices, our current development capital program and assuming excess funds
are repatriated to Canada.
Net Income
Net income for the third quarter of 2008 was $465.8 million or $2.82 per trust unit compared to $93.0 million or $0.72
per trust unit in the same period for 2007.

The third quarter 2008 increase compared to the same period in 2007 is
primarily due to an increase in oil and gas sales of $284.4 million and an increase in cash and non-cash commodity
derivative instrument gains of $217.1 million, which were offset by increased royalties of $52.5 million and a $45.2
million increase in DDA&A.
Net income for the nine months ended September 30, 2008 was $699.4 million or $4.40 per trust unit compared to
$241.0 million or $1.90 per trust unit for the same period in 2007.

The $458.4 million increase in net income for the
nine months ended September 30, 2008 was primarily due to an increase in oil and gas sales of $762.2 million and a
$122.7 million increase in the future tax recovery, which were partially offset by increases in royalties of $140.6
million, cash and non-cash commodity derivative instrument losses of $90.7 million and DDA&A of $121.5 million.
Cash Flow from Operating Activities
Cash flow for the three and nine months ended September 30, 2008 was $383.6 million ($2.33 per trust unit) and
$1,004.2 million ($6.32 per trust unit) respectively, compared to $232.8 million ($1.80 per trust unit) and $663.5
million ($5.22 per trust unit) for the three and nine months ended September 30, 2007.

The increases per trust unit
were primarily a result of higher commodity prices combined with increased oil and gas sales resulting from the
Focus acquisition.
Page 15 of 40
Selected Financial Results
Three months ended September 30,
2008
Three months ended September 30,
2007
Per BOE of production (6:1)
Operating
Cash
Flow(1)
Non-Cash
& Other
Items
Total
Operating
Cash
Flow(1)
Non-Cash &
Other Items
Total
Production per day 95,644 79,891
Weighted average sales price (2) $ 73.62 $ - $ 73.62 $49.64 $ - $49.64
Royalties (13.71) - (13.71) (9.28) - (9.28)
Commodity derivative instruments (6.82) 31.90 25.08 1.00 (0.51) 0.49
Operating costs (10.10) (0.11) (10.21) (9.61) (0.12) (9.73)
General and administrative (1.50) (0.20) (1.70) (2.11) (0.30) (2.41)
Interest expense, net of other income (0.97) 0.18 (0.79) (1.40) 0.54 (0.86)
Foreign exchange gain/(loss) (0.49) 0.19 (0.30) 0.06 0.03 0.09
Current income tax (0.59) - (0.59) (0.70) - (0.70)
Restoration and abandonment cash costs (0.54) 0.54 - (0.48) 0.48 -
Depletion, depreciation, amortization and
accretion - (18.32) (18.32) - (15.78) (15.78)
Future income tax recovery/(expense) - (0.15) (0.15) - 1.20 1.20
Total per BOE $ 38.90 $ 14.03 $ 52.93 $27.12 $(14.46) $ 12.66
(1) Cash Flow from Operating Activities before changes in non-cash working capital.
(2) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
Nine months ended September 30,
2008
Nine months ended September 30,
2007
Per BOE of production (6:1)
Operating
Cash
Flow(1)
Non-Cash
& Other
Items
Total
Operating
Cash
Flow(1)
Non-Cash &
Other Items
Total
Production per day 95,010 82,777
Weighted average sales price (2) $ 72.44 $ - $ 72.44 $49.89 $ - $49.89
Royalties (13.54) - (13.54) (9.38) - (9.38)
Commodity derivative instruments (5.19) 1.55 (3.64) 0.63 (0.81) (0.18)
Operating costs (9.51) (0.01) (9.52) (9.32) 0.01 (9.31)
General and administrative (1.66) (0.21) (1.87) (2.00) (0.28) (2.28)
Interest expense, net of other income (1.06) 0.06 (1.00) (1.29) 0.15 (1.14)
Foreign exchange (loss)/gain (0.17) (0.02) (0.19) (0.05) 0.23 0.18
Current income tax (1.19) - (1.19) (0.46) - (0.46)
Restoration and abandonment cash costs (0.52) 0.52 - (0.47) 0.47 -
Depletion, depreciation, amortization and
accretion - (18.19) (18.19) - (15.58) (15.58)
Future income tax recovery/(expense) - 3.24 3.24 - (1.70) (1.70)
Gain on sale of marketable securities(3) - 0.32 0.32 - 0.62 0.62
Total per BOE $ 39.60 $ (12.74) $ 26.86 $27.55 $(16.89) $10.66
(1) Cash Flow from Operating Activities before changes in non-cash working capital.
(2)
Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
(3) Gain on sale of marketable securities was a cash item however it is included in cash flow from investing activities not cash flow
from operating activities.
Page 16 of 40
Selected Canadian and U.S.

Results
The following tables provide a geographical analysis of key operating and financial results for the three and nine
months ended September 30, 2008 and 2007.
Three months ended September 30,
2008
Three months ended September 30,
2007
(CDN$ millions, except per unit amounts) Canada U.S.

Total Canada U.S.

Total
Daily Production Volumes
Natural gas (Mcf/day) 329,047 12,756 341,803 241,196 10,068 251,264
Crude oil (bbls/day) 25,484 8,635 34,119 24,236 9,841 34,077
Natural gas liquids (bbls/day) 4,557 - 4,557 3,937 - 3,937
Total Daily Sales (BOE/day) 84,883 10,761 95,644 68,372 11,519 79,891
Pricing (1)
Natural gas (per Mcf) $ 8.17 $ 10.39 $ 8.25 $ 5.58 $ 5.67 $ 5.59
Crude oil (per bbl) 110.10 112.02 110.63 65.78 77.49 69.16
Natural gas liquids (per bbl) 81.20 - 81.20 50.79 - 50.79
Capital Expenditures
Development capital and office $ 146.7 $ 18.9 $ 165.6 $ 70.5 $ 21.8 $ 92.3
Acquisitions of oil and gas properties 4.5 0.1 4.6 1.8 - 1.8
Dispositions of oil and gas properties (502.6) 0.1 (502.5) (0.1) - (0.1)
Revenues
Oil and gas sales (1) $546.5 $ 101.3 $647.8 $ 289.4 $ 75.4 $ 364.8
Royalties (2) (98.8) (21.8) (120.6) (52.6) (15.6) (68.2)
Financial contracts 220.7 - 220.7 3.6 - 3.6
Expenses
Operating $ 85.1 $ 4.7 $ 89.8 $68.9 $2.7 $71.6
General and administrative 13.6 1.3 14.9 16.3 1.4 17.7
Depletion, depreciation, amortization and
accretion 139.2 22.0 161.2 88.9 27.1 116.