Exhibit
99.3




MANAGEMENT’S
DISCUSSION AND ANALYSIS (“MD&A”)
 
 The
following discussion and analysis of financial results is dated February 27,
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. 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 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. In addition to disclosing reserves under the requirements of NI 51-101,
we also disclose our reserves on a company interest basis which is not a term
defined under NI 51-101. This information may not be comparable to similar
measures presented by other issuers. 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.
 
 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 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.
 
 2007
OVERVIEW
  Cash
flow from operating activities totaled $868.5 million in 2007, essentially flat
over 2006. Higher realized crude oil prices, cash gains generated from our price
risk management program and a decrease in our non-cash working capital helped to
mitigate the impact of lower production, reduced natural gas prices and
increased operating costs. Monthly cash distributions remained constant at $0.42
per trust unit throughout 2007 for an annual total of $5.04 per trust
unit.
 
 Our
2007 development capital spending totaled $387.2 million, resulting in the
drilling of 252 net wells with a 99% success rate. On January 31, 2007 we
acquired gross-overriding royalty interests in the Jonah natural gas field in
Wyoming U.S. (“Jonah”) for approximately $61 million. In the second quarter we
acquired the Kirby Oil Sands Partnership (“Kirby”), an operated Steam Assisted
Gravity Drainage (“SAGD”) project, for $203.1 million ($148.3 million in cash
and $54.8 million in equity). An equity offering consisting of 4.25 million
trust units for gross proceeds of $210.6 million was also completed in
conjunction with the Kirby acquisition.
 
 During
2007 production averaged 82,319 BOE/day, in-line with our third quarter guidance
of 82,500 BOE/day and 4% below our 2006 production of 85,779 BOE/day. Reduced
development capital spending, unplanned downtime, lower initial production rates
on our third well per section Bakken oil wells and natural reservoir declines
are the primary reasons for the decrease.
 
 On June
22, 2007 the Federal Government enacted a new tax on publicly traded income
trusts and limited partnerships (specified investment flow-through entities, or
“SIFTs”) effective January 1, 2011. As a result we recorded a $78.1 million
future income tax expense. We are currently evaluating alternatives to determine
the optimal structure for Enerplus post 2010 to maximize the return to
investors. However, we see value in the remaining three-year tax exemption
period through 2010 and currently look to maintaining our current structure
during this period unless there are compelling reasons to change.  In
the fourth quarter of 2007 the Alberta Government also announced proposed
changes to the provincial royalty program effective January 1, 2009 which have
not yet been enacted into law.
 
 On
February 13, 2008 we successfully closed the largest transaction in our 22 year
history, acquiring Focus Energy Trust (“Focus”) for total consideration of $1.7
billion including approximately $340 million of assumed debt. Under the plan of
arrangement, Focus unitholders received 0.425 of an Enerplus trust unit for each
Focus trust unit. We believe the combined entity is well positioned for future
growth with a strong balance sheet and production expected to be approximately
98,000 BOE/day in 2008.
 
 
 HIGHLIGHTS
 
 •
              Cash
      flow from operating activities totaled $868.5 million in 2007, essentially
      flat over 2006.
 •
              Distributions
      have remained constant at $0.42 per trust unit for the past 28 months
      resulting in annual cash distributions of $5.04 per trust
      unit.
 •
              Net
      income totaled $339.7 million, a decrease of $205.1 million from
      2006.
 •
              Our
      payout ratio increased slightly to 74% from
71%.
 •
              Our
      price risk management program realized cash gains of $13.6 million or
      $0.45/BOE on our commodity financial contracts, an increase compared to
      cash losses of $34.3 million or $1.10/BOE in
  2006.
 •
              General
      and Administrative (“G&A”) expenses were $2.26/BOE, 6% lower than our
      guidance of $2.40/BOE and 18% higher than $1.91/BOE in
    2006.
 •
              Operating
      costs were $9.12/BOE for 2007, slightly below our third quarter guidance
      of $9.20/BOE and a year-over-year increase of
  14%.
 
 •
              On
      January 31, 2007 we acquired an overriding royalty interest in the Jonah
      field in Wyoming for total consideration of approximately $61.0
      million.
 •
              In
      the second quarter we acquired Kirby for a total purchase price of $203.1
      million, consisting of $148.3 million in cash and $54.8 million in
      equity.
 •
              In
      conjunction with the Kirby acquisition, on April 10, 2007 an equity
      offering was completed consisting of 4.25 million trust units raising
      gross proceeds of $210.6 million.
 
 •
              Our
      development capital spending of $387.2 million was in-line with our
      guidance of $390.0 million and resulted in drilling of 252 net wells with
      a 99% success rate.
 •
              Production
      averaged 82,319 BOE/day, in-line with our third quarter guidance of 82,500
      BOE/day.
 •
              Our
      proved plus probable finding, development and acquisition costs
      (“FD&A”) costs on our conventional oil and gas activities were
      $19.79/BOE for the year and when we include our oil sands activities,
      FD&A costs were $27.69/BOE.
 •
              Reserve
      additions from development capital spending and acquisitions replaced 90%
      of 2007 production on a proved plus probable basis and 67% on a proved
      basis.
 •
              Our
      conventional recycle ratio (operating income divided by FD&A) was 1.5x
      on a three-year basis and 1.6x for 2007 using proved plus probable
      reserves.
 •
              We
      added 6.8 million barrels of probable reserves relating to our Joslyn
      steam assisted gravity drainage
project.
 •
              Proved
      plus probable reserves decreased 1% to 440.2 MMBOE and proved reserves
      decreased 3% to 289.9 MMBOE.
 •
              Our
      Reserve Life Index (“RLI”) continued to be one of the longest in the
      sector at 14.8 years on a proved plus probable basis and 10.3 years on a
      proved basis, including both conventional and non-conventional
      reserves.
 
 •
              On
      February 13, 2008 we acquired Focus creating an entity with a combined
      market capitalization of approximately $7.6
  billion.
 •
              In
      conjunction with the Focus acquisition we increased our bank credit
      facility from $1.0 billion to $1.4 billion on February 13,
      2008.
 •
              We
      continue to maintain a conservative balance sheet with a net debt to
      trailing 12 month cash flow ratio of 0.8x at December 31,
      2007.
 
 RESULTS
OF OPERATIONS
 Production
 
 Production
during 2007 averaged 82,319 BOE/day, in-line with our third quarter guidance of
82,500 BOE/day and 4% lower than 85,779 BOE/day in 2006. Our 2007 production was
impacted by the fact that we spent $104 million or 21% less development capital
than the prior year. In addition we experienced unexpected down time and
turn-around activities at partner operated facilities. Our third well per
section program at our U.S. Bakken property had lower initial production rates
than originally forecast; however the program continues to deliver attractive
economics and reserves. These decreases were partially offset by production from
our acquisition of Jonah that closed January 31, 2007.
 Page 2 of
27
 Average
production during the year was weighted 53% to natural gas and 47% to liquids on
a BOE basis. Average production volumes for the years ended December 31, 2007
and 2006 are outlined below:
 
 Daily
      Production Volumes
              
              2007
              
              
              2006
              
              
              %
      ChangeNatural
      gas (Mcf/day)
              
              
              262,254
              
              
              
              270,972
              
              
              
              (3
              )%Crude
      oil (bbls/day)
              
              
              34,506
              
              
              
              36,134
              
              
              
              (5
              )%Natural
      gas liquids (bbls/day)
              
              
              4,104
              
              
              
              4,483
              
              
              
              (8
              )%Total
      daily sales (BOE/day)
              
              
              82,319
              
              
              
              85,779
              
              
              
              (4
              )%
 
 We
exited the year with production of approximately 79,800 BOE/day based on
December’s average production rate, 4% below our exit target of 83,000 BOE/day.
Approximately 2,000 BOE/day of the decrease related to a previously announced
fire that occurred at our Giltedge property on November 30, 2007. We expect
production from this property to be back on-line by mid-2008. We have both
business interruption insurance and property insurance which we anticipate will
mitigate the majority of these losses. The remainder of the 1,200 BOE/day
difference related to tie-in delays primarily on non-operated capital projects
at year end and pipeline problems at our non-operated Mitsue
property.
 
 Considering
our acquisition of Focus that closed on February 13, 2008 and our current
development capital program, we expect 2008 annual production volumes to average
98,000 BOE/day, weighted 60% to natural gas and 40% to liquids. We expect to
exit 2008 with production of approximately 100,000 BOE/day. This guidance does
not contemplate any other potential acquisitions or dispositions.
 
 Pricing
 
 The
prices received for our natural gas and crude oil production directly impact our
earnings, cash flow and financial condition.The following table
compares our average selling prices for 2007 with those of 2006. It also
compares the benchmark price indices for the same periods.
 
 Average
      Selling Price(1)
              
              2007
              
              
              2006
              
              
              %
      ChangeNatural
      gas (per Mcf)
              
              $
              6.45
              
              
              $
              6.81
              
              
              
              (5
              )%Crude
      oil (per bbl)
              
              $
              65.11
              
              
              $
              61.80
              
              
              
              5
              %Natural
      gas liquids (per bbl)
              
              $
              51.35
              
              
              $
              50.90
              
              
              
              1
              %Per
      BOE
              
              $
              50.48
              
              
              $
              50.23
              
              
              
              -
              %
 (1) Net of
oil and gas transportation costs, but before the effects of commodity derivative
instruments
 
 Average
      Benchmark Pricing
              
              2007
              
              
              2006
              
              
              %
      ChangeAECO
      natural gas - monthly index (CDN$/Mcf)
              
              $
              6.61
              
              
              $
              6.99
              
              
              
              (5
              )%AECO
      natural gas - daily index (CDN$/Mcf)
              
              $
              6.45
              
              
              $
              6.53
              
              
              
              (1
              )%NYMEX
      natural gas - monthly NX3 index (US$/Mcf)
              
              $
              6.92
              
              
              $
              7.26
              
              
              
              (5
              )%NYMEX
      natural gas - monthly NX3 index: CDN$ equivalent
(CDN$/Mcf)
              
              $
              7.44
              
              
              $
              8.25
              
              
              
              (10
              )%WTI
      crude oil (US$/bbl)
              
              $
              72.34
              
              
              $
              66.22
              
              
              
              9
              %WTI
      crude oil: CDN$ equivalent (CDN$/bbl)
              
              $
              77.78
              
              
              $
              75.25
              
              
              
              3
              %CDN$/US$
      exchange rate
              
              
              0.93
              
              
              
              0.88
              
              
              
              6
              %
 
 Natural
Gas
 
 Natural
gas prices started 2007 in a weak position due to a mild December 2006. However
cold weather across key consuming regions of the United States from the latter
part of January 2007 through to March resulted in increased prices. Early
forecasts for an active hurricane season led to an expectation that strong
prices would carry into and through the summer. However, this past year marked a
changing dynamic in global liquefied natural gas (“LNG”) trade, with cargos more
readily shifting between Asia, Europe, and North America depending on spot
market prices and access to storage. Accordingly, low demand in Europe pushed
significant volumes of LNG to North America from March through August. This LNG,
along with continued strong North American production, resulted in high U.S. and
Canadian storage balances by the end of the summer which depressed prices.
Natural gas prices during the year traded within a band that saw highs of
approximately $8.00/Mcf during the winter and lows of around $5.00/Mcf at the
end of the summer injection season. This was a narrower band than was
experienced during 2006 where natural gas prices fluctuated between $12.00/Mcf
and $4.00/Mcf.
 
 Our
natural gas portfolio in 2007 was comprised of aggregator, AECO, and downstream
direct sales. In 2007 we sold 40% of our natural gas on the daily AECO market
and 40% on the monthly AECO market, as well as 20% against the day and month
NYMEX indices. During 2007 we realized an average price for our natural gas
sales of $6.45/Mcf (net of transportation costs), a decrease of 5% from
$6.81/Mcf realized in 2006. This reduction is comparable to the price decreases
realized in each of: the AECO monthly index which decreased by 5%; the AECO
daily index which decreased by 1%; and the NYMEX monthly index (converted to
CDN$/Mcf) which decreased by 10%.
 
 Page 3 of
27
 Natural
Gas Prices
 
 
  Crude
Oil
 
 Crude
prices were weak in the first quarter of 2007, with a low of US$50.48/bbl.
Prices rose steadily through the remaining months reaching a high of
US$98.18/bbl in mid November. In terms of market fundamentals, OPEC kept its
supply constant, non-OPEC production was lower than expected and growth demands
in Asia remained strong. As a result, global crude and refined product
inventories declined. In addition there was growing concern global production
was reaching its peak. These fundamentals placed steady upward pressure on crude
oil prices through the year.
 
 Our
crude oil portfolio in 2007 was approximately 74% light/medium and 26% heavy.
The average price received for our crude oil (net of transportation costs) was
CDN$65.11/bbl during 2007, a 5% increase over 2006. The West Texas Intermediate
(“WTI”) crude oil benchmark price, after adjusting for the change in the US$
exchange rate, increased 3% year-over-year. On average for 2007, the slight
narrowing of the light to heavy differential had a positive effect on our
overall crude oil and gas sales. However, in the fourth quarter of 2007, and in
particular in December, absolute heavy oil differentials to WTI widened
significantly due to a number of factors, including: outages of refineries with
heavy oil conversion capabilities; drawdown of inventories prior to year end;
and operational issues on key intra-Alberta and export pipelines. These
differentials reverted to historical levels in January 2008.
 
 Crude
Oil Prices
 
 
 
 The
Canadian dollar opened 2007 at an exchange rate of $0.86/US$ and strengthened
throughout the year hitting a high in November of $1.09/US$ and ending the year
at $0.99/US$. On average it strengthened 6% against the U.S. dollar during 2007
compared to 2006 based on the annual average exchange rate. As most of our crude
oil and a portion of our natural gas 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 4 of
27
 Historically
we have not attempted to hedge against fluctuations in the foreign exchange
value of our oil and gas sales. In the fourth quarter of 2007 we entered into a
foreign exchange swap on our US$54 million debentures which effectively fixed
the principal repayments at a CDN/US dollar exchange rate of 1.02.
 
 Price
Risk Management
 
 While
we believe that the overall energy outlook remains generally bullish long term,
the threat of a U.S. recession reducing demand for crude oil and natural gas
requires prudent management of our commodity price exposure.
  We have
developed a price risk management framework to respond to the volatile price
environment in a measured manner. Consideration is given to our overall
financial position together with the economics of our acquisitions and capital
development program. Consideration is also given to the upfront costs of our
risk management program as we seek to limit our exposure to price downturns and
maintain participation in upside potential should commodity prices
increase.
 
 Consistent
with our price risk management framework, we entered into additional commodity
contracts during the fourth quarter of 2007 and during the first quarter of
2008. These contracts are designed to protect a portion of our natural gas sales
for the period January 2008 through March 2009 and to protect a portion of our
crude oil sales for the period January 2008 through December 2009. We have also
hedged electricity volumes for the period January 2008 through December 2009 to
protect against rising electricity costs in the Alberta power market. See Note
12 for a detailed list of our current price risk management positions including
positions we assumed through the Focus acquisition.
 
 The
following is a summary of the financial contracts in place at February 20, 2008,
including positions entered into by Focus, expressed as a percentage of our
forecasted net production volumes:
 
 Natural
      Gas
                (CDN$/Mcf)
              
              
              Crude
      Oil
                (US$/bbl)January
      1,
                2008
      -
                March
      31,
                2008
              
              
              April
      1,
                2008-
                October
      31, 2008
              
              
              November
      1, 2008 -
                March
      31,
                2009
              
              
              January
      1,
                2008
      -
                June
      30,
                2008
              
              
              July
      1,
                2008
      -December
      31, 2008
              
              
              January
      1,
                2009
      -
                December
      31, 2009Floor
      Prices (puts)
              
              $
              8.28
              
              
              $
              7.06
              
              
              $
              8.18
              
              
              $
              70.91
              
              
              $
              72.09
              
              
              $
              77.63%
      (net of royalties)
              
              
              18
              %
              
              
              24
              %
              
              
              4
              %
              
              
              35
              %
              
              
              35
              %
              
              
              10
              %Fixed
      Price (swaps)
              
              $
              8.73
              
              
              $
              7.16
              
              
              $
              -
              
              
              $
              79.95
              
              
              $
              79.97
              
              
              $
              -%
      (net of royalties)
              
              
              11
              %
              
              
              16
              %
              
              
              -
              %
              
              
              17
              %
              
              
              19
              %
              
              
              -
              %Capped
      Price (calls)
              
              $
              10.12
              
              
              $
              8.22
              
              
              $
              10.10
              
              
              $
              85.09
              
              
              $
              85.48
              
              
              $
              92.98%
      (net of royalties)
              
              
              19
              %
              
              
              24
              %
              
              
              4
              %
              
              
              23
              %
              
              
              22
              %
              
              
              10
              %
 Based
on weighted average price (before premiums), estimated average annual production
of 98,000 BOE/day and assuming a 19% royalty rate.
 
 Accounting
for Price Risk Management
 
 During
2007, our commodity price risk management program generated cash gains of $23.6
million on our natural gas contracts and cash losses of $10.0 million on our
crude oil contracts. The natural gas cash gains are due to contracts in place
during 2007 that provided floor protection as the price of natural gas declined.
The crude oil cash losses are due to crude oil prices rising above our swap
positions. In comparison, our 2006 commodity price risk management program
resulted in cash losses of $7.1 million on our natural gas contracts and $27.2
million on our crude oil contracts.
 
 At
December 31, 2007 the fair value of our natural gas and crude oil derivative
instruments, net of premiums, represents a gain of $9.7 million and a loss of
$52.5 million, respectively. The natural gas gain is recorded as a current
deferred financial asset on our balance sheet and the crude oil loss is recorded
as a current deferred financial credit. In comparison, at December 31, 2006 the
fair value of our natural gas and crude oil derivative instruments represented
gains of $12.7 million and $10.9 million respectively, both of which were
recorded on our balance sheet as deferred financial assets. The change in the
fair value of these financial contracts year-over-year resulted in unrealized
losses of $3.0 million for natural gas and $63.4 million for crude oil. As the
forward markets for natural gas and crude oil fluctuate and new contracts are
executed and existing contracts are realized, changes in fair value are
reflected as a non-cash charge or non-cash gain in earnings. See Note 3 for
details.
 
 Page 5 of
27
 The
following table summarizes the effects of our financial contracts on income for
the years ended December 31, 2007 and 2006.
 
 Risk
      Management Costs($
      millions, except per unit amounts)
              
              2007
              
              2006Cash
      gains/(losses):Natural
      gas
              
              $
              23.6
              
              $
              0.25/Mcf
              
              $
              (7.1
              )
              $
              (0.07)/McfCrude
      oil
              
              
              (10.0
              )
              $
              (0.79)/bbl
              
              
              (27.2
              )
              $
              (2.06)/bblTotal
      cash gains/(losses)
              
              $
              13.6
              
              $
              0.45/BOE
              
              $
              (34.3
              )
              $
              (1.10)/BOENon-cash
      (losses)/gains on financial contracts:Change
      in fair value - natural gas
              
              $
              (3.0
              )
              $
              (0.03)/Mcf
              
              $
              50.6
              
              $
              0.51/McfChange
      in fair value - crude oil
              
              
              (63.4
              )
              $
              (5.03)/bbl
              
              
              30.4
              
              $
              2.30/bblAmortization
      of deferred financial assets
              
              
              -
              
              $
              -
      /BOE
              
              
              (49.9
              )
              $
              (1.59)/BOETotal
      non-cash (losses)/gains
              
              $
              (66.4
              )
              $
              (2.21)/BOE
              
              $
              31.1
              
              $
              0.99/BOETotal
      (losses)
              
              $
              (52.8
              )
              $
              (1.76)/BOE
              
              $
              (3.2
              )
              $
              (0.11)/BOE
 
 
 Cash
Flow Sensitivity
 
 The
sensitivities below reflect all commodity contracts as described in Note 12
(including those entered into by Focus) and are based on 2008 forward markets as
at February 20, 2008. To the extent the market price of crude oil and natural
gas change significantly from current levels, the sensitivities will no longer
be relevant as the effect of our commodity contracts will change.
 
 Sensitivity
      Table
              
              Estimated
      Effect
                on
      2008
                Cash
      Flow per
                Trust
      Unit (1)Change
      of $0.15 per Mcf in the price of AECO natural gas
              
              $
              0.08Change
      of US$1.00 per barrel in the price of WTI crude oil
              
              $
              0.06Change
      of 1,000 BOE/day in production
              
              $
              0.10Change
      of $0.01 in the US$/CDN$ exchange rate
              
              $
              0.12Change
      of 1% in interest rate
              
              $
              0.07
 (1)
Assumes constant working capital and 129,813,000 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 for the year ended December 31, 2007 were $1,517.1
million ($1,539.2 million, net of $22.1 million of transportation costs), a
decrease of 4% or $55.6 million compared to $1,572.7 million ($1,595.3 million,
net of $22.6 million of transportation costs) during 2006. Decreased production
and lower natural gas prices were partially offset by an increase in realized
crude oil prices.
 
 Analysis of Sales
      Revenue(1)($
      millions)
              
              Crude
      oil
              
              
              NGLs
              
              
              Natural
      Gas
              
              
              Total2006
      Sales Revenue
              
              $
              815.0
              
              
              $
              83.3
              
              
              $
              674.4
              
              
              $
              1,572.7Price
      variance(1)
              
              
              41.8
              
              
              
              0.7
              
              
              
              (33.8
              )
              
              
              8.7Volume
      variance
              
              
              (36.7
              )
              
              
              (7.1
              )
              
              
              (20.5
              )
              
              
              (64.3
              )2007
      Sales Revenue
              
              $
              820.1
              
              
              $
              76.9
              
              
              $
              620.1
              
              
              $
              1,517.1
 (1)           Net
of oil and gas transportation costs, but before the effects of commodity
derivative instruments.
 
 Royalties
 
 Royalties
are paid to various government entities and other land and mineral rights
owners. Royalties in 2007 and 2006 were approximately 19% of oil and gas sales,
net of transportation costs. Overall, royalties decreased marginally in 2007 to
$285.1 million compared to $296.6 million during 2006 primarily as a result of
the decrease in natural gas revenue experienced over the period.
 
 We
expect royalties to be approximately 19% of oil and gas sales, net of
transportation costs for 2008.
 
 Page 6 of
27
 Alberta
Royalty Review
 
 On
October 25, 2007 the Alberta government announced the 'New Royalty Framework'
("NRF"), an updated royalty regime proposed to be effective January 1, 2009
which is intended to increase Government royalty revenue by 20%.  On
conventional oil and gas production during 2007, Alberta Crown royalties were
$122.1 million (43%) of our total royalties. Based on this royalty rate and in
the context of our production and pricing experienced during 2007, we estimate
that the NRF would have increased the royalties on our conventional production
by approximately $15 to $20 million. The acquisition of Focus in 2008 will help
to mitigate the effects of the Alberta royalty review as the production from
Focus is concentrated in Saskatchewan and British Columbia.
 
 The
moderate royalty increase is a reflection of the NRF's sensitivity to our
portfolio, which includes lower productivity wells combined with the low natural
gas prices experienced in 2007. It is important to note that this context may
not be indicative of the environment in 2009 when the NRF comes into effect. The
fundamental design of the new Alberta regime (which increases royalty rates as
commodity prices increase) has removed some of the price upside producers had
previously factored into their risk assessments for capital investment. As a
result, Alberta will not be as attractive to invest in as other jurisdictions
that allow greater participation in price upside.
 
 The
Alberta government is currently working with industry to address "unintended
consequences" of economic issues related to the NRF and as at the date of this
MD&A the Alberta government had not yet made the necessary legislative and
administration changes to implement the NRF. The NRF announcement can be found
on the Alberta government’s website at www.gov.ab.ca.
 
 Operating
Expenses
 
 Operating
expenses during 2007 were $9.12/BOE or $274.2 million, representing a 1%
decrease from our third quarter guidance of $9.20/BOE and a 14% increase from
$8.02/BOE in 2006. Operating expenses for the year were lower than our guidance
primarily due to lower than expected electricity charges during the fourth
quarter. The increase in operating costs over 2006 was due to the combination of
increased labour, well servicing, and repairs and maintenance costs along with
lower production volumes during 2007. A field training initiative in 2007
directed at optimizing production and reducing the time required to drill,
complete and bring new wells on stream also contributed to the year-over-year
increase.
 
 By
combining the lower cost operating expenses associated with the Focus properties
we expect operating costs for 2008 to average $8.65/BOE, representing a decrease
of 5% per BOE compared to 2007.
 
 General
and Administrative Expenses (“G&A”)
 
 G&A
expenses were $2.26/BOE or $67.9 million for the year ended December 31, 2007,
approximately 6% lower than our guidance of $2.40/BOE and 18% higher than
$1.91/BOE in 2006.  G&A expenses were lower than our guidance
primarily due to lower than anticipated long term cash compensation charges
related to our performance trust unit plan (“PTU”) which is impacted by our
trust unit price. The increase in general and administrative costs over 2006 was
mainly due to increased overall salary and benefits as a result of continued
wage inflation, increased staff and lower production volumes during
2007.
 
 For the
year ended December 31, 2007 our G&A expenses included non-cash charges for
our trust unit rights incentive plan of $8.4 million or $0.28/BOE compared to
$6.3 million or $0.20/BOE for 2006. These amounts relate solely to our trust
unit rights incentive plan and are determined using a binomial lattice
option-pricing model. The volatility of our trust unit price combined with the
increased number of rights outstanding associated with additional employees
increased the non-cash cost of the plan. Although non-cash charges have
increased as a result of the option pricing model, the proportion of rights that
are “in-the-money” has decreased in comparison with 2006. See Note 10 for
further details.
 
 The
following table summarizes the cash and non-cash expenses recorded in
G&A:
 
 General and Administrative
      Costs($ millions)
              
              2007
              
              
              2006Cash
              
              $
              59.5
              
              
              $
              53.6Trust
      unit rights incentive plan (non-cash)
              
              
              8.4
              
              
              
              6.3Total
      G&A
              
              $
              67.9
              
              
              $
              59.9
 
 
 (Per
      BOE)
              
              2007
              
              
              2006Cash
              
              $
              1.98
              
              
              $
              1.71Trust
      unit rights incentive plan (non-cash)
              
              
              0.28
              
              
              
              0.20Total
      G&A
              
              $
              2.26
              
              
              $
              1.91
  
 Page 7 of
27
 In 2008
we expect total G&A costs to decrease slightly to approximately $2.20/BOE,
including non-cash G&A costs of approximately $0.20/BOE.
 
 Interest
Expense
 
 With
the adoption of the new accounting standards on January 1, 2007 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 (see Note 8).
 
 Interest
on long-term debt during 2007 totaled $41.9 million, a $9.7 million increase
from $32.2 million in 2006. The increase was due to higher average indebtedness
and a higher weighted average interest rate of 5.1% during 2007 compared to 4.8%
in 2006.
 
 The
following table summarizes the cash and non-cash interest expense
recorded.
 
 Interest Expense($
      millions)
              
              2007
              
              
              2006Interest
      on long-term debt
              
              $
              41.9
              
              
              $
              32.2Unrealized
      gain
              
              
              (8.3
              )
              
              
              -Total
      Interest Expense
              
              $
              33.6
              
              
              $
              32.2
 
 At
December 31, 2007 approximately 18% of our debt was based on fixed interest
rates while 82% had floating interest rates.
 
 Capital
Expenditures
 
 During
2007 we spent $387.2
million on development capital and facilities, which is $104.0 million or
21% less than 2006. Spending in 2007 was in-line with our guidance of $390.0
million. Development capital spending was lower in 2007 as we spent less on
natural gas development due to decreasing natural gas prices and increasing
drilling and servicing costs. Development in 2007 focused primarily on Bakken
oil and waterfloods. We achieved a 99% success rate with our drilling program on
252 net wells drilled during 2007.
 
 Property
acquisitions were $274.2 million during 2007 compared to $51.3 million in 2006.
The majority of our 2007 acquisitions related to the purchase of Kirby for total
consideration of $203.1 million and the purchase of gross-overriding royalty
interests in the Jonah area for approximately $61.0 million. Property
dispositions were $9.6 million during 2007 compared to $21.1 million in 2006.
Our 2007 divestments included $5.6 million of property interests in the Thorhild
area and the sale of 36,000 net acres of undeveloped land in North Dakota for
approximately $3.6 million. Divestments in 2006 primarily related to the $19.7
million sale of a 1% working interest in the Joslyn property.
 
 
 Capital Expenditures($
      millions)
              
              2007
              
              
              2006Development
      expenditures
              
              $
              321.3
              
              
              $
              380.5Plant
      and facilities
              
              
              65.9
              
              
              
              110.7Development
      Capital
              
              
              387.2
              
              
              
              491.2Office
              
              
              6.5
              
              
              
              5.0Sub-total
              
              
              393.7
              
              
              
              496.2Acquisitions
      of oil and gas properties(1)
              
              
              274.2
              
              
              
              51.3Dispositions
      of oil and gas properties(1)
              
              
              (9.6
              )
              
              
              (21.1
              )Total
      Net Capital Expenditures
              
              $
              658.3
              
              
              $
              526.4Total
      Capital Expenditures financed with cash flow
              
              $
              221.7
              
              
              $
              249.4Total
      Capital Expenditures financed with debt and equity
              
              
              443.2
              
              
              
              296.5Total
      non-cash consideration for property dispositions
              
              
              (6.6
              )
              
              
              (19.5
              )Total
      Net Capital Expenditures
              
              $
              658.3
              
              
              $
              526.4
 (1)Net of
post-closing adjustments.
  
 Page 8 of
27
 The
following is a summary by play type of our development capital expenditures
during 2007 and 2006, as well as our current expectations for 2008 including
Focus.
 
 
 Play type($
      millions)
              
              2008
      Estimate
              
              
              2007
              
              
              2006Shallow
      Gas and CBM
              
              $
              128
              
              
              $
              39.3
              
              
              $
              94.0Crude
      Oil Waterfloods
              
              
              105
              
              
              
              54.2
              
              
              
              66.0Deep
      Tight Gas
              
              
              53
              
              
              
              34.7
              
              
              
              34.1Bakken
      Oil
              
              
              47
              
              
              
              106.2
              
              
              
              116.7Other
      Conventional Oil and Gas
              
              
              142
              
              
              
              113.9
              
              
              
              141.3Oil
      Sands
              
              
              105
              
              
              
              38.9
              
              
              
              39.1Total
              
              $
              580
              
              
              $
              387.2
              
              
              $
              491.2
 
 We
currently expect total development capital expenditures in 2008 to be
approximately $580 million. Conventional development capital is presently
anticipated to be approximately $475 million with a slight bias to oil related
projects over natural gas projects. Oil sands development capital is currently
projected to be approximately $105 million.
 
 
 Oil
Sands
 
 Our
Joslyn and Kirby development projects have not commenced commercial production.
As a result all associated costs, net of revenues generated, are capitalized and
excluded from our depletion calculation. During 2007 we capitalized costs of
$35.2 million on Joslyn and $205.4 million on Kirby, inclusive of acquisition
costs, development capital spending, salaries and benefits, engineering and
planning. At December 31, 2007 capitalized costs life-to-date for Joslyn were
$116.4 million and for Kirby were $205.4 million for a combined total of $321.8
million.
 
 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 year ended December
31, 2007 DDA&A of $15.43/BOE is comparable to $15.38/BOE during the year
ended December 31, 2006.
 
 No
impairment existed at December 31, 2007 using year-end reserves and management’s
estimates of future prices. Our future price estimates are more fully discussed
in Note 4.
 
 Asset
Retirement Obligations
 
 We have
estimated our total future asset retirement obligations based on our net
ownership interest in wells and facilities, along with the estimated cost and
timing to abandon and reclaim wells and facilities in future periods. Our asset
retirement obligation was $165.7 million at December 31, 2007 compared to $123.6
million at December 31, 2006. The majority of the $42.1 million increase was due
to increased cost estimates as a result of enhanced regulatory requirements on
abandonment and reclamation activities. The remainder of the change was due to
retirement costs incurred, offset by accretion expense for the year. See Note 5
for further details.
 
 The
following chart compares the amortization of the asset retirement cost,
accretion of the asset retirement obligation, and asset retirement obligations
settled.
 
 ($
      millions)
              
              2007
              
              
              2006Amortization
      of the asset retirement cost
              
              $
              11.4
              
              
              $
              12.6Accretion
      of the asset retirement obligation
              
              
              6.7
              
              
              
              6.2Total
      Amortization and Accretion
              
              $
              18.1
              
              
              $
              18.8Asset
      Retirement Obligations Settled
              
              $
              16.3
              
              
              $
              11.5
 
 Actual
asset retirement costs are incurred at different times compared to the recording
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
 
 Canadian
Government’s tax changes
 
 On June
22, 2007 Bill C-52, which contained legislative provisions to implement the
proposals to tax publicly traded income trusts in Canada became law. As a
result, our second quarter future income tax provision included a future income
tax expense of $78.1 million related to this legislation. This non-cash expense
related to temporary differences between the accounting and tax basis of the
Fund’s assets and liabilities at that time and had no immediate impact on cash
flow.
 
 Page 9 of
27
 On
December 14, 2007, Bill C-28, which contained legislative provisions to
implement corporate income tax rate reductions announced in the October 30, 2007
fall economic statement, became law. The general corporate tax rate will
decrease by 1.0% in 2008 from 20.5% to 19.5%. There are additional rate
reductions scheduled until the target federal tax rate of 15.0% is reached as of
January 1, 2012. These rate reductions will also apply to the SIFT tax on income
trusts. As a result, our fourth quarter future income tax provision includes a
future income tax recovery of $22.6million related to this
legislation.
 
 Future
Income Taxes
 
 Future
income taxes arise from differences between the accounting and tax basis 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.
The balance will be realized when future income tax assets and liabilities are
realized or settled.
 
 As a
result of the SIFT tax, all entities within our organization are now subject to
future income taxes whereas prior to the SIFT tax enactment only incorporated
entities in our organization were subject to future income taxes. As a result
our future income tax recovery was $1.0 million for the year ended December 31,
2007 compared to a recovery of $112.0 million for the same period in 2006. The
changes in future income taxes compared to 2006 are primarily a result of the
following:
 
 •
              The
      SIFT tax resulted in a future income tax expense of $78.1 million in the
      second quarter of 2007; and
 •
              Corporate
      income tax rate changes enacted during the year have resulted in a
      year-to-date future tax recovery of $22.6 million compared to a $35.5
      million recovery in 2006.
 
 After
consideration of the above items, the future income tax provisions were
comparable between the periods.
 
 
 Current
Income Taxes
 
 In our
current structure, payments are made between the operating entities and the Fund
which ultimately transfers both income and future income tax liability to our
unitholders. As a result, no cash income taxes have been paid by our Canadian
operating entities. However, effective January 1, 2011 we will be subject to the
SIFT tax should we remain a trust.
 
 The
amount of current taxes recorded throughout the year on our U.S. operations is
dependent upon the timing of both capital expenditures and repatriation of the
funds to Canada. Our U.S. taxes as a percentage of cash flow, assuming constant
working capital, were 11% in 2007 compared to our guidance of 10%. We expect the
current income and withholding taxes to average approximately 20% of cash flow
from U.S. operations in 2008 based on our current development capital program
and assuming all funds are repatriated to Canada after U.S. development capital
spending. The increase for 2008 is a result of plans for reduced development
capital spending in the U.S. during the year.
 
 During
2007 our U.S. operations incurred income related taxes in the amount of $23.0
million compared to $18.2 million in 2006. The increase in current taxes is due
to an increase in net income combined with a modest decrease in drilling and
completion expenditures for the year.
 
 Tax
Pools
 
 We
estimate our tax pools at December 31, 2007 to be as follows:
 
 Pool Type($
      millions)
              
              Trust
              
              
              Operating
      entities
              
              
              TotalCOGPE
              
              $
              470
              
              
              $
              100
              
              
              $
              570CDE
              
              
              -
              
              
              
              340
              
              
              
              340UCC
              
              
              -
              
              
              
              600
              
              
              
              600Tax
      losses and other
              
              
              30
              
              
              
              600
              
              
              
              630Foreign
      tax pools
              
              
              -
              
              
              
              140
              
              
              
              140Total
              
              $
              500
              
              
              $
              1,780
              
              
              $
              2,280
 
 We
acquired approximately $200 million in tax pools related to the Focus
acquisition (net of any pools required to offset partnership
deferrals).
 
 Page 10 of
27
 Net
Income
 
 Net
income in 2007 was $339.7 million or $2.66 per trust unit compared to $544.8
million or $4.48 per trust unit in 2006. The $205.1 million decrease in net
income was primarily due to a $111.0 million decrease in future income tax
recovery, a $49.6
million increase in cash and non-cash risk management costs,a $55.6
million decrease in oil
and gas sales (net of transportation costs) and a $22.9 million increase in
operating costs, partially offset by an increase in other income of $12.5
million and decreased DDA&A charges of $17.9 million.
 
 Cash
Flow from Operating Activities
 
 Cash
flow from operating activities in 2007 was $868.5 million or $6.80 per trust
unit compared to $863.7 million or $7.10 per trust unit in 2006. The decrease on
a per unit basis is largely due to the April 2007 equity offering, which was
primarily used to purchase Kirby, a development project that is not currently
generating cash flow.
 
 Selected
Financial Results
 
 Year
      ended December 31,
                2007
              
              
              Year
      ended December 31,
                2006Per
      BOE of production (6:1)
              
              Operating
                Cash Flow(1)
              
              Non-Cash
      & Other Items
              
              
              Total
              
              
              Operating
                Cash
      Flow(1)
              
              
              Non-Cash
      & Other Items
              
              
              TotalProduction
      per day
              
              
              
              
              
              
              
              
              82,319
              
              
              
              
              
              
              
              
              
              85,779Weighted
      average sales price (2)
              
              $
              50.48
              
              
              $
              -
              
              
              $
              50.48
              
              
              $
              50.23
              
              
              $
              -
              
              
              $
              50.23Royalties
              
              
              (9.49
              )
              
              
              -
              
              
              
              (9.49
              )
              
              
              (9.47
              )
              
              
              -
              
              
              
              (9.47
              )Commodity
      derivative instruments
              
              
              0.45
              
              
              
              (2.21
              )
              
              
              (1.76
              )
              
              
              (1.10
              )
              
              
              0.99
              
              
              
              (0.11
              )Operating
      costs
              
              
              (9.11
              )
              
              
              (0.01
              )
              
              
              (9.12
              )
              
              
              (8.02
              )
              
              
              -
              
              
              
              (8.02
              )General
      and administrative
              
              
              (1.98
              )
              
              
              (0.28
              )
              
              
              (2.26
              )
              
              
              (1.71
              )
              
              
              (0.20
              )
              
              
              (1.91
              )Interest
      expense, net of interest income
              
              
              (1.37
              )
              
              
              0.28
              
              
              
              (1.09
              )
              
              
              (0.95
              )
              
              
              -
              
              
              
              (0.95
              )Foreign
      exchange gain / (loss)
              
              
              (0.06
              )
              
              
              0.30
              
              
              
              0.24
              
              
              
              0.02
              
              
              
              -
              
              
              
              0.02Current
      income tax
              
              
              (0.77
              )
              
              
              -
              
              
              
              (0.77
              )
              
              
              (0.59
              )
              
              
              -
              
              
              
              (0.59
              )Restoration
      and abandonment cash costs
              
              
              (0.54
              )
              
              
              0.54
              
              
              
              -
              
              
              
              (0.37
              )
              
              
              0.37
              
              
              
              -Depletion,
      depreciation, amortization and accretion
              
              
              -
              
              
              
              (15.43
              )
              
              
              (15.43
              )
              
              
              -
              
              
              
              (15.38
              )
              
              
              (15.38
              )Future
      income tax (expense) / recovery
              
              
              -
              
              
              
              0.04
              
              
              
              0.04
              
              
              
              -
              
              
              
              3.58
              
              
              
              3.58Marketable
      securities(3)
              
              
              -
              
              
              
              0.47
              
              
              
              0.47
              
              
              
              -
              
              
              
              -
              
              
              
              -Total
      per BOE
              
              $
              27.61
              
              
              $
              (16.30
              )
              
              $
              11.31
              
              
              $
              28.04
              
              
              $
              (10.64
              )
              
              $
              17.40
 (1)Cash Flow from Operating Activities before changes in non-cash operating
working capital.
 (2)Net of
oil and gas transportation costs, but before the effects of commodity derivative
instruments.
 (3)In
addition to non-cash shares of marketable securities, a gain on sale of
marketable securities was a cash item; however the cash item is included in cash
flow from investing activities not cash flow from operating
activities.
 
 Selected
Annual Canadian and U.S. Financial Results
 
 The
following table provides a geographical analysis of key operating and financial
results for 2007 and 2006.
 
 Year
      ended December 31, 2007
              
              
              Year
      ended December 31, 2006(CDN$
      millions, except per unit amounts)
              
              Canada
              
              
              U.S.
              
              
              Total
              
              
              Canada
              
              
              U.S.
              
              
              TotalDaily
      Production VolumesNatural
      gas (Mcf/day)
              
              
              251,561
              
              
              
              10,693
              
              
              
              262,254
              
              
              
              265,019
              
              
              
              5,953
              
              
              
              270,972Crude
      oil (bbls/day)
              
              
              24,590
              
              
              
              9,916
              
              
              
              34,506
              
              
              
              25,858
              
              
              
              10,276
              
              
              
              36,134Natural
      gas liquids (bbls/day)
              
              
              4,104
              
              
              
              -
              
              
              
              4,104
              
              
              
              4,483
              
              
              
              -
              
              
              
              4,483Total
      daily sales (BOE/day)
              
              
              70,621
              
              
              
              11,698
              
              
              
              82,319
              
              
              
              74,511
              
              
              
              11,268
              
              
              
              85,779Pricing
      (1)Natural
      gas (per Mcf)
              
              $
              6.45
              
              
              $
              6.55
              
              
              $
              6.45
              
              
              $
              6.79
              
              
              $
              7.78
              
              
              $
              6.81Crude
      oil (per bbl)
              
              $
              62.27
              
              
              $
              72.17
              
              
              $
              65.11
              
              
              $
              59.36
              
              
              $
              67.93
              
              
              $
              61.80Natural
      gas liquids (per bbl)
              
              $
              51.35
              
              
              $
              -
              
              
              $
              51.35
              
              
              $
              50.90
              
              
              $
              -
              
              
              $
              50.90Capital
      ExpendituresDevelopment
      capital and office
              
              $
              287.3
              
              
              $
              106.4
              
              
              $
              393.7
              
              
              $
              378.5
              
              
              $
              117.7
              
              
              $
              496.2Acquisitions
      of oil and gas properties
              
              $
              213.3
              
              
              $
              60.9
              
              
              $
              274.2
              
              
              $
              35.3
              
              
              $
              16.0
              
              
              $
              51.3Dispositions
      of oil and gas properties
              
              $
              (6.0
              )
              
              $
              (3.6
              )
              
              $
              (9.6
              )
              
              $
              (21.1
              )
              
              $
              -
              
              
              $
              (21.1
              )RevenuesOil
      and gas sales (1)
              
              $
              1,230.4
              
              
              $
              286.7
              
              
              $
              1,517.1
              
              
              $
              1,301.0
              
              
              $
              271.7
              
              
              $
              1,572.7Royalties
              
              $
              (226.4
              )
              
              $
              (58.7
              ) (2)
              
              $
              (285.1
              )
              
              $
              (244.4
              )
              
              $
              (52.2
              )(2)
              
              $
              (296.6
              )Commodity
      derivative instruments
              
              $
              (52.8
              )
              
              $
              -
              
              
              $
              (52.8
              )
              
              $
              (3.2
              )
              
              $
              -
              
              
              $
              (3.2
              )ExpensesOperating
              
              $
              264.4
              
              
              $
              9.8
              
              
              $
              274.2
              
              
              $
              243.8
              
              
              $
              7.4
              
              
              $
              251.2General
      and administrative
              
              $
              62.6
              
              
              $
              5.3
              
              
              $
              67.9
              
              
              $
              51.4
              
              
              $
              8.5
              
              
              $
              59.9Depletion,
      depreciation, amortization and accretion
              
              $
              359.8
              
              
              $
              103.9
              
              
              $
              463.7
              
              
              $
              369.6
              
              
              $
              112.0
              
              
              $
              481.6Current
      income taxes
              
              $
              -
              
              
              $
              23.0
              
              
              $
              23.0
              
              
              $
              -
              
              
              $
              18.2
              
              
              $
              18.2
 (1)           Net
of oil and gas transportation costs, but before the effects of commodity
derivative instruments.
 (2)           Royalties
include U.S. state production tax.
 
 
 Page 11 of
27
 Three
Year Summary of Key Measures
 
 Overall,
lower production volumes have resulted in lower oil and gas sales and net income
during 2007 as compared to 2006. The rise in crude oil prices during 2005, 2006
and 2007 contributed to higher oil and gas sales, however sales moderated in
2007 as a result of lower natural gas prices and production. The following table
provides a summary of net income, cash flow and other key measures.
 
 ($
      millions, except per unit amounts)
              
              2007
              
              
              2006
              
              
              2005Oil
      and gas sales(1)
              
              $
              1,517.1
              
              
              $
              1,572.7
              
              
              $
              1,523.7Net
      income
              
              
              339.7
              
              
              
              544.8
              
              
              
              432.0Per
      unit (Basic) (2)
              
              
              2.66
              
              
              
              4.48
              
              
              
              3.96Per
      unit (Diluted)
              
              
              2.66
              
              
              
              4.47
              
              
              
              3.95Cash
      flow from operating activities
              
              
              868.5
              
              
              
              863.7
              
              
              
              774.6Per
      unit (Basic)(2)
              
              
              6.80
              
              
              
              7.10
              
              
              
              7.10Cash
      distributions
              
              
              646.8
              
              
              
              614.3
              
              
              
              498.2Per
      unit (Basic) (2)
              
              
              5.07
              
              
              
              5.05
              
              
              
              4.57Payout
      ratio
              
              
              74
              %
              
              
              71
              %
              
              
              64
              %Total
      assets
              
              
              4,303.1
              
              
              
              4,203.8
              
              
              
              4,130.6Long-term
      debt, net of cash
              
              
              725.0
              
              
              
              679.7
              
              
              
              649.8
 (1) Net
of oil and gas transportation costs, but before the effects of commodity
derivative instruments.
 (2) Based
on weighted average trust units outstanding. Cash distributions to unitholders
per unit will not correspond to actual distributions as a result of using the
annual weighted average trust units outstanding.
 
 Page 12 of
27
 Liquidity
and Capital Resources
 
 Sustainability
of our Distributions and Asset Base
 
 As an
oil and gas producer we have a declining asset base and therefore rely on
ongoing development activities and acquisitions to replace production and add
additional reserves. Our future oil and natural gas production is highly
dependent on our success in exploiting our asset base and acquiring or
developing additional reserves. To the extent we are unsuccessful in these
activities our cash distributions could be reduced.
 
 Development
activities and acquisitions may be funded internally by withholding a portion of
cash flow or through external sources of capital such as debt or the issuance of
equity. To the extent that we withhold cash flow to finance these activities,
the amount of cash distributions to our unitholders may be reduced. Should
external sources of capital become limited or unavailable, our ability to make
the necessary development expenditures and acquisitions to maintain or expand
our asset base may be impaired and ultimately reduce the amount of cash
distributions.
 
 Following
the completion of the Focus acquisition, Enerplus has approximately $10 billion
of safe harbor growth capacity within the context of the Government’s “normal
growth” guidelines associated with Bill C-52. This amount is calculated in
reference to the combined market capitalizations of Enerplus and Focus on
October 31, 2006 and also includes equity that may be issued to replace existing
debt of both entities at that time.
 
 Distribution
Policy
 
 The
amount of cash distributions is proposed by management and approved by the Board
of Directors. We continually assess distribution levels with respect to
forecasted cash flows, debt levels and capital spending plans. The level of cash
withheld has historically varied between 10% and 40% of annual cash flow from
operating activities and is dependent upon numerous factors, the most
significant of which are the prevailing commodity price environment, our current
levels of production, debt obligations, our access to equity markets and funding
requirements for our development capital program.
 
 Although
we intend to continue to make cash distributions to our unitholders, these
distributions are not guaranteed. To the extent there is taxable income at the
trust level, determined in accordance with the Canadian Income Tax
Act, the distribution of that taxable income is
non-discretionary.
 
 Cash
Flow from Operating Activities, Cash Distributions and Payout Ratio
 
 Cash
flow from operating activities and cash distributions are reported on the
Consolidated Statements of Cash Flows. During 2007 cash distributions of $646.8
million were funded entirely through cash flow of $868.5 million. Our payout
ratio, which is calculated as cash distributions divided by cash flow, was 74%
for 2007 compared to 71% in 2006.
 
 Our
cash outlays in 2007 were comprised of: $646.8 million of distributions to
unitholders, $393.7 million of development capital and office expenditures, and
$209.8 million of acquisitions (net of dispositions) for a total of $1,250.3
million. These cash outlays were financed with a combination of: $868.5 million
from cash flow from operating activities, $199.6 million from the equity issue,
$56.8 million from our distribution reinvestment plan and trust unit rights
incentive plan and an increase in our credit facility of $148.8
million.
 
 In
aggregate, our 2007 cash distributions of $646.8 million and our development
capital and office of $393.7 million totaled $1,040.5 million, or approximately
120% of our cash flow of $868.5 million. We rely on access to capital markets to
the extent cash distributions and development capital exceeds cash flow. Over
the long term we would expect to support our distributions and capital
expenditures with our cash flow, however we would continue to fund acquisitions
and growth through additional debt and equity. There will be years when we are
investing capital in opportunities that do not immediately generate cash flow
(such as our Joslyn and Kirby oil sands projects) where this relationship will
vary. Despite our 2007 cash flow being less than the aggregate of our cash
distributions and development capital, we continue to have conservative debt
levels with a trailing twelve month debt-to-cash flow ratio of 0.8x at December
31, 2007.
 
 For the
year ended December 31, 2007 our cash distributions exceeded our net income by
$307.1 million (2006 - $69.5 million). Net income includes $520.3 million of
non-cash items (2006 - $344.7 million) such as DDA&A, changes in the fair
value of our derivative instruments, and future income taxes that do not reduce
our cash flow from operations. Future income taxes can fluctuate from period to
period as a result of changes in tax rates (such as the enactment of the SIFT
tax during the second quarter of 2007), changes in the inter-company royalty,
interest and dividends from our operating subsidiaries paid to the Fund. In
addition, other non-cash charges such as DDA&A are not a good proxy for the
cost of maintaining our productive capacity as they are based on the historical
costs of our PP&E and not the fair market value of replacing those assets
within the context of the current environment.
 
 Page 13 of
27
 The
level of investment in a given period may not be sufficient to replace
productive capacity given the natural declines associated with oil and natural
gas assets. In these instances a portion of the cash distributions paid to
unitholders may represent a return of the unitholders’ capital.
 
 The
following table compares cash distributions to cash flow and net
income.
 
 ($ millions,
      except per unit amounts)
              
              2007
              
              
              2006
              
              
              2005Cash
      flow  from operating activities
              
              $
              868.5
              
              
              $
              863.7
              
              
              $
              774.6Cash
      Distributions
              
              
              646.8
              
              
              
              614.3
              
              
              
              498.2Excess
      of cash flow over cash distributions
              
              $
              221.7
              
              
              $
              249.4
              
              
              $
              276.4Net
      income
              
              $
              339.7
              
              
              $
              544.8
              
              
              $
              432.0Shortfall
      of net income over cash distributions
              
              $
              (307.1
              )
              
              $
              (69.5
              )
              
              $
              (66.2
              )Cash
      distributions per weighted average trust unit
              
              $
              5.07
              
              
              $
              5.05
              
              
              $
              4.57Payout
      ratio (1)
              
              
              74
              %
              
              
              71
              %
              
              
              64
              %
 (1)Based
on cash distributions divided by cash flow from operating
activities.
 
 It is
not possible to distinguish between capital spent on maintaining productive
capacity and capital spent on growth opportunities in the oil and gas sector due
to the nature of reserve reporting, natural reservoir declines and the risks
involved with capital investment. Therefore we do not disclose maintenance
capital separately from development capital spending.
 
 Asset
Retirement Costs
 
 Actual
asset retirement costs incurred in the period are deducted for purposes of
calculating cash flow. Differences between actual asset retirement costs
incurred and the amortization and accretion of the asset retirement obligation
are discussed in the Asset Retirement Obligations section of the MD&A and
Note 5.
 
 Long-Term
Debt
 
 Long-term
debt at December 31,
2007 was $726.7 million, an increase of $46.9 million from $679.8 million
at December 31, 2006. Long-term debt at December 31, 2007 is comprised of $497.3 million of
bank indebtedness, which increased $148.8 million from prior year and $229.3
million of senior unsecured notes. With the adoption of the financial instrument
accounting standards (see Note 2) on January 1, 2007 we adjusted the carrying
value of our US$175 million senior unsecured notes to fair value of $208.2
million from their previous carrying value of $268.3 million, a decrease of
$60.1 million. Subsequent to this adoption entry, our $175 million senior notes
have decreased a further $32.2 million as a result of the strengthening Canadian
dollar. Increases in long-term debt resulting from the Jonah and Kirby
acquisitions along with our development capital program more than offset
decreases resulting from the April 2007 equity issue and the foreign exchange
impact of the strengthening Canadian dollar on our U.S. dollar denominated
senior notes.
 
 In the
fourth quarter of 2007 we extended our bank credit facility by one year to
November 2010 and increased the facility size to $1.0 billion. Subsequent to
December 31, 2007, in conjunction with the Focus acquisition, we increased the
bank credit facility size to $1.4 billion. On February 13, 2008 an additional
$340 million was drawn on the bank credit facility to settle outstanding
indebtedness of Focus.
 
 Our
working capital, excluding cash, at December 31, 2007 decreased $73.2 million
compared to December 31, 2006. Excluding deferred financial assets and credits,
working capital decreased $7.3 million compared to the prior year. This is
primarily due to lower accounts receivable in 2007 as a result of lower sales in
December 2007 compared to 2006.
 
 Page 14 of
27
 We
continue to maintain a conservative balance sheet as demonstrated
below:
 
 Financial
      Leverage and Coverage
              
              Year
      ended
                Dec.
      31, 2007
              
              
              Year
      ended
                Dec.
      31, 2006Long-term
      debt to trailing cash flow
              
              
              0.8
              x
              
              
              0.8
              xCash
      flowto
      interest expense
              
              
              25.8
              x
              
              
              26.8
              xLong-term
      debt to long-term debt plus equity
              
              
              22
              %
              
              
              20
              %
 Long-term
debt is measured net of cash.
 Cash
flow and interest expense are 12-months trailing.
 
 Enerplus
currently has a $1.4 billion ($1.0 billion at December 31, 2007) unsecured
covenant based three-year term bank facility ending November 2010, through its
wholly-owned subsidiary EnerMark Inc. We have the ability to extend the facility
each year or repay the entire balance at the end of the three-year term. This
bank debt carries floating interest rates that we expect to range between 55.0
and 110.0 basis points over Bankers’ Acceptance rates, depending on Enerplus’
ratio of senior debt to earnings before interest, taxes and non-cash
items.
 
 Payments
with respect to the bank facilities, senior unsecured notes and other third
party debt have priority over claims of and future distributions to the
unitholders. Unitholders have no direct liability should cash flow be
insufficient to repay this indebtedness. The agreements governing these bank
facilities and senior unsecured notes stipulate that if we default or fail to
comply with certain covenants, the ability of the Fund’s operating subsidiaries
to make payments to the Fund and consequently the Fund’s ability to make
distributions to the unitholders may be restricted. At December 31, 2007 we are
in compliance with our debt covenants, the most restrictive of which limits our
long-term debt to three times trailing cash flow reflecting acquisitions on a
pro forma basis. Refer to “Debt of Enerplus” in our Annual Information Form for
the year ended December 31, 2006 for a detailed description of these
covenants.
 
 Principal
payments on Enerplus’ senior unsecured notes are required commencing in 2010 and
2011 and are more fully discussed in Note 7.
 
 We
anticipate that we will continue to have adequate liquidity to fund planned
development capital spending during 2008 through a combination of cash flow
retained by the business and debt.
 
 Commitments
 
 Enerplus
has contracted to transport 104 MMcf/day of natural gas on the Nova system in
the province of Alberta as well as 20 MMcf/day of natural gas on various
pipelines to the U.S. midwest. Enerplus also has a contract to transport a
minimum of 2,480 bbls/day of crude oil from field locations to suitable
marketing sales points within western Canada.
 
 Including
Focus, approximately 24% of our current gas production is dedicated to
aggregator sales arrangements. Under these arrangements, we receive a price
based on the average netback price of the pool, net of transportation costs
incurred by the aggregator for the life of the reserves.
 
 In 2007
we extended our Canadian office lease commitments. Our Canadian and U.S. leases
now expire in 2014 and 2011, respectively. Annual costs of these lease
commitments, include rent and operating fees. The Fund’s commitments,
contingencies and guarantees are more fully described in Note 13.
 
 As at
December 31, 2007 Enerplus has the following minimum annual commitments
including long-term debt:
  Minimum
      Annual Commitment Each Year
                
                
                TotalCommittedafter($
      millions)
                
                Total
                
                
                2008
                
                
                2009
                
                
                2010
                
                
                2011
                
                
                2012
                
                
                2012Bank
      credit facility
                
                $
                497.3
                (1)
                
                $
                -
                
                
                $
                -
                
                
                $
                497.3
                
                
                $
                -
                
                
                $
                -
                
                
                $
                -Senior
      unsecured notes
                
                
                323.4
                (1)
      (2)
                
                
                -
                
                
                
                -
                
                
                
                53.7
                
                
                
                64.7
                
                
                
                64.7
                
                
                
                140.3Pipeline
      commitments
                
                
                31.1
                
                
                
                10.0
                
                
                
                5.9
                
                
                
                4.0
                
                
                
                2.8
                
                
                
                2.4
                
                
                
                6.0Office
      lease
                
                
                67.9
                
                
                
                6.9
                
                
                
                7.6
                
                
                
                10.3
                
                
                
                10.8
                
                
                
                11.1
                
                
                
                21.2Total
      commitments (3)
                
                $
                919.7
                
                
                $
                16.9
                
                
                $
                13.5
                
                
                $
                565.3
                
                
                $
                78.3
                
                
                $
                78.2
                
                
                $
                167.5
 (1)
Interest payments have not been included since future debt levels and interest
rates are not known at this time.
 (2)
Includes the economic impact of derivative instruments directly related to the
senior unsecured notes (CCIRS and foreign exchange swap - see Note
12).
 (3)Crown
and surface royalties, lease rentals, mineral taxes, and abandonment and
reclamation costs (hydrocarbon production rights) have not been included as
amounts paid depend on future ownership, production, prices and the legislative
environment.
 
 Page 15 of
27
 Not
reflected in the above schedule are those term contracts for transportation and
the office lease that Enerplus assumed upon the completion of the Focus
acquisition. The Focus term transportation contracts consist of 45 MMcf/day of
natural gas in British Columbia, and 60 MMcf/day of natural gas in
Saskatchwan.
 
 
 Accumulated
Deficit
 
 We have
historically paid cash distributions in excess of accumulated earnings as cash
distributions are based on cash flow generated in the period whereas accumulated
earnings are based on net income which includes non-cash items such as DDA&A
charges, derivative instrument mark-to-market gains and losses, unit based
compensation charges, future income tax provisions and non-cash charges
resulting from the adoption of the financial instrument accounting standards
(see Note 2).
 
 Trust
Unit Information
 
 We had
129,813,000 trust units outstanding at December 31, 2007 compared to 123,151,000
trust units at December 31, 2006. The weighted average number of trust units
outstanding during 2007 was 127,691,000 (2006 - 121,588,000). At February 20,
2008 we had 160,022,000 trust units outstanding, which reflects the additional
trust units issued to acquire Focus, and 9,087,000 exchangeable partnership
units outstanding that were assumed with the Focus acquisition and are
convertible at the option of the holder into 0.425 of an Enerplus trust unit
(3,862,000 trust units).
 
 On
April 10, 2007 in conjunction with the acquisition of Kirby we issued 1,105,000
trust units as part of the purchase price consideration representing $54.8
million and also closed a public offering of 4,250,000 trust units for net
proceeds of $199.6 million.
 
 In
addition 1,307,000 trust units (2006 - 1,242,000) were issued pursuant to the
Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and
the trust unit rights incentive plan, net of redemptions. This resulted in $56.8
million (2006 - $55.9 million) of additional equity to the Fund.
 
 Income
Taxes
 
 The
following is a general discussion of the Canadian and U.S. tax consequences of
holding Enerplus trust units as capital property. The summary is not exhaustive
in nature and is not intended to provide legal or tax advice. Investors or
potential unitholders should consult their own legal or tax advisors as to their
particular tax consequences, as well as consider the Government’s proposal to
implement a tax on trusts.
 
 Canadian
Unitholders
 
 The
Fund qualifies as a mutual fund trust under the Income Tax Act (Canada) and
accordingly, trust units of the Fund are qualified investments for RRSPs, RRIFs,
RESPs, and DPSPs. Each year the Fund has historically transferred all of its
taxable income to the unitholders by way of distributions.
 
 In
computing income, unitholders are required to include the taxable portion of
distributions received in that year. An investor’s adjusted cost base (“ACB”) in
a trust unit equals the purchase price of the trust unit less any non-taxable
cash distributions received from the date of acquisition. To the extent a
unitholder’s ACB is reduced below zero, such amount will be deemed to be a
capital gain to the unitholder and the unitholder’s ACB will be brought to
$nil.
 
 We paid
$5.04 per trust unit in cash distributions to unitholders on record during 2007.
For Canadian tax purposes, approximately 2% of these distributions, or $0.12 per
trust unit was a tax deferred return of capital, approximately 98% or $4.92 per
trust unit was taxable to unitholders as other income, and there was no eligible
dividend income.
 
 For
2008, we estimate that 95% of cash distributions will be taxable and 5% will be
a tax deferred return of capital. Actual taxable amounts may vary depending on
actual distributions which are dependent upon, among other things, production,
commodity prices and cash flow experienced throughout the year.
 
 U.S.
Unitholders
 
 U.S.
unitholders who received cash distributions were subject to at least a 15%
Canadian withholding tax. The withholding tax is applied to both the taxable
portion of the distribution as computed under Canadian tax law and the
non-taxable portion of the distribution. U.S. taxpayers may be eligible for a
foreign tax credit with respect to Canadian withholding taxes paid.
 
 Page 16 of
27
 For
U.S. taxpayers the taxable portion of cash distributions are considered to be a
dividend for U.S. tax purposes. For most U.S. taxpayers this should be a
“Qualified Dividend” eligible for the reduced tax rate. This preferential rate
of tax for "Qualified Dividends" is set to expire at the end of 2010. On March
24, 2007, Bill 1672 was introduced into the U.S. House of Representatives which,
if enacted as presented, would make dividends from Canadian income funds
such as Enerplus ineligible for treatment as a "Qualified Dividend". The
dividends would then become a "non-qualified dividend from a foreign
corporation" subject to the normal rates of tax commencing with dividends
received after the date of enactment. The proposed bill still requires the
approval of the House of Representatives, the Senate and the President prior to
it being enacted. Therefore, we are unable to determine when or even if the
bill will become enacted as presented.
 
 We paid
US$4.71 per trust unit to U.S. residents during the 2007 calendar year of which
7% or US$0.33 per trust unit was a tax deferred return of capital and 93% or
US$4.38 per unit was a taxable qualified dividend.
 
 For
2008, we estimate that 90% of cash distributions will be taxable to most U.S.
investors and 10% will be a tax deferred return of capital. Actual taxable
amounts may vary depending on actual distributions which are dependent upon
production, commodity prices and cash flow experienced throughout the
year.
 
 Quarterly
Financial Information
 
 In
general, oil and gas sales have been decreasing since the first quarter of 2006
due mainly to lower natural gas prices and lower production. Sales increased
slightly in the fourth quarter of 2007 due to higher crude oil
prices.
 
 Net
income has been affected by fluctuating commodity prices and risk management
costs, the fluctuating Canadian dollar, higher operating and G&A costs,
changes in future tax provisions due to changes in government legislation (SIFT
tax and corporate rate reductions) as well as changes to accounting policies
adopted during 2007. Furthermore, changes in the fair value of our commodity
derivative instruments along with changes in fair value of other financial
instruments cause net income to fluctuate between quarters.
  Oil
      and
                
                
                
                
                
                Net
      Income Per Trust UnitQuarterly
      Financial Information
                
                Gas
                
                
                Net(CDN$
      millions, except per trust unit amounts)
                
                Sales(1)
                
                
                Income
                
                
                Basic
                
                
                Diluted2007Fourth
      Quarter
                
                $
                389.8
                
                
                $
                98.7
                
                
                $
                0.76
                
                
                $
                0.76Third
      Quarter
                
                
                364.8
                
                
                
                93.0
                
                
                
                0.72
                
                
                
                0.72Second
      Quarter
                
                
                382.5
                
                
                
                40.1
                
                
                
                0.31
                
                
                
                0.31First
      Quarter
                
                
                380.0
                
                
                
                107.9
                
                
                
                0.88
                
                
                
                0.87Total
                
                $
                1,517.1
                
                
                $
                339.7
                
                
                $
                2.66
                
                
                $
                2.662006Fourth
      Quarter
                
                $
                369.5
                
                
                $
                110.2
                
                
                $
                0.90
                
                
                $
                0.89Third
      Quarter
                
                
                398.0
                
                
                
                161.3
                
                
                
                1.31
                
                
                
                1.31Second
      Quarter
                
                
                403.5
                
                
                
                146.0
                
                
                
                1.19
                
                
                
                1.19First
      Quarter
                
                
                401.7
                
                
                
                127.3
                
                
                
                1.08
                
                
                
                1.07Total
                
                $
                1,572.7
                
                
                $
                544.8
                
                
                $
                4.48
                
                
                $
                4.47
 (1) Net
of oil and gas transportation costs, but before the effects of commodity
derivative instruments
 
 
 Summary
Fourth Quarter Information
 
 In
comparing the fourth quarter of 2007 with the same period in
2006:
 •
                Net
      income decreased 10% to $98.7 million due to increased commodity
      derivative instrument losses, partially offset by higher oil and gas
      sales.
 •
                Cash
      flow was $205.1 million in 2007 similar to $207.1 million in
      2006.
 •
                Average
      daily production decreased 7% to 80,959
      BOE/day due to the fire at Giltedge, operational interruptions and
      reductions in our development capital
program.
 •
                The
      average selling price per BOE increased 13% to $52.33 due to stronger
      crude oil prices.
 •
                Operating
      expenses of $8.57/BOE (including non-cash amounts) were similar to the
      fourth quarter of 2006 at
$8.52/BOE.
 •
                G&A
      expenses including non-cash amounts increased 4% on a BOE basis to$2.21/BOE from
      $2.13/BOE as a result of lower
production.
 •
                Development
      capital spending decreased 14% compared to the fourth quarter of 2006 as a
      result of a reduced development capital spending program in
      2007.
   Page 17 of
27
 
 The
following tables provide an analysis of key financial and operating results for
the three months ended December 31, 2007 and 2006.
 
 
 (CDN$
      millions, except per unit amounts)
              
              Three
      Months Ended
                December
      31, 2007
              
              
              Three
      Months Ended
                December
      31, 2006Financial
      (000’s)
 Net
      Income
              
              $
              98.7
              
              
              $
              110.2Cash
      Flow from Operating Activities
              
              $
              205.1
              
              
              $
              207.1Cash
      Distributions to Unitholders(1)
              
              $
              163.4
              
              
              $
              155.0Financial
      per Unit (2)Net
      Income
              
              $
              0.76
              
              
              $
              0.90Cash
      Flow from Operating Activities
              
              $
              1.58
              
              
              $
              1.69Cash
      Distributions to Unitholders(1)
              
              $
              1.26
              
              
              $
              1.26Payout
      Ratio(3)
              
              
              80
              %
              
              
              75
              %Average
      Daily Production
              
              
              80,959
              
              
              
              87,092Selected
      Financial Results per BOE(4)Oil
      and Gas Sales(5)
              
              $
              52.33
              
              
              $
              46.11Royalties
              
              
              (9.83
              )
              
              
              (8.26
              )Commodity
      Derivative Instruments
              
              
              (0.08
              )
              
              
              0.75Operating
      Costs
              
              
              (8.53
              )
              
              
              (8.52
              )General
      and Administrative
              
              
              (1.94
              )
              
              
              (1.88
              )Interest
      and Foreign Exchange
              
              
              (1.70
              )
              
              
              (1.02
              )Taxes
              
              
              (1.70
              )
              
              
              (0.64
              )Restoration
      and Abandonment
              
              
              (0.75
              )
              
              
              (0.54
              )Cash
      Flow from Operating Activities before changes in non-cash working
      capital
              
              $
              27.80
              
              
              $
              26.00Weighted
      Average Number of Units Outstanding (thousands)
              
              
              129,658
              
              
              
              122,971Development
      Capital
              
              
              106.1
              
              
              
              123.1Net
      Wells Drilled
              
              
              76
              
              
              
              89Success
      Rate
              
              
              100
              %
              
              
              100
              %Average
      Benchmark PricingAECO
      natural gas - monthly index (CDN$/Mcf)
              
              $
              6.00
              
              
              $
              6.36AECO
      natural gas - daily index (CDN$/Mcf)
              
              $
              6.14
              
              
              $
              6.91NYMEX
      natural gas - monthly NX3 index (US$/Mcf)
              
              $
              7.03
              
              
              $
              6.62NYMEX
      natural gas - monthly NX3 index: CDN$ equivalent
(CDN$/Mcf)
              
              $
              6.89
              
              
              $
              7.52WTI
      crude oil (US$/bbl)
              
              $
              90.68
              
              
              $
              60.21WTI
      crude oil: CDN$ equivalent (CDN$/bbl)
              
              $
              88.90
              
              
              $
              68.42CDN$/US$
      exchange rate
              
              
              1.02
              
              
              
              0.88
 (1)  
Calculated based on distributions paid or payable. Cash distributions to
unitholders per unit may not correspond to actual distributions of $1.26 per
trust unit as a result of using the annual weighted average trust units
outstanding.
 (2)  Based on weighted average trust units
outstanding.
 (3)Based
on cash distributions divided by cash flow from operating
activities.
 (4)  Non-cash
amounts have been excluded.
 (5)  Net
of oil and gas transportation costs, but before the effects of commodity
derivative instruments.
 
 Page 18 of
27
 Selected
Quarterly Canadian and U.S. Financial Results
 
 Three
      months ended December 31, 2007
              
              Three
      months ended December 31, 2006(CDN$
      millions, except per unit amounts)
              
              Canada
              
              
              U.S.
              
              
              Total
              
              
              Canada
              
              
              U.S.
              
              
              TotalDaily
      Production VolumesNatural
      gas (Mcf/day)
              
              
              245,219
              
              
              
              12,196
              
              
              
              257,415
              
              
              
              271,061
              
              
              
              6,654
              
              
              
              277,715Crude
      oil (bbls/day)
              
              
              24,248
              
              
              
              9,973
              
              
              
              34,221
              
              
              
              25,903
              
              
              
              10,436
              
              
              
              36,339Natural
      gas liquids (bbls/day)
              
              
              3,836
              
              
              
              -
              
              
              
              3,836
              
              
              
              4,467
              
              
              
              -
              
              
              
              4,467Total
      daily sales (BOE/day)
              
              
              68,953
              
              
              
              12,006
              
              
              
              80,959
              
              
              
              75,547
              
              
              
              11,545
              
              
              
              87,092Pricing
      (1)Natural
      gas (per Mcf)
              
              $
              5.91
              
              
              $
              5.98
              
              
              $
              5.91
              
              
              $
              6.57
              
              
              $
              6.81
              
              
              $
              6.58Crude
      oil (per bbl)
              
              $
              68.94
              
              
              $
              80.16
              
              
              $
              72.21
              
              
              $
              52.39
              
              
              $
              59.85
              
              
              $
              54.53Natural
      gas liquids (per bbl)
              
              $
              58.12
              
              
              $
              -
              
              
              $
              58.12
              
              
              $
              46.15
              
              
              $
              -
              
              
              $
              46.15Capital
      ExpendituresDevelopment
      capital and office
              
              $
              94.3
              
              
              $
              13.7
              
              
              $
              108.0
              
              
              $
              96.7
              
              
              $
              29.1
              
              
              $
              125.8Acquisitions
      of oil and gas properties
              
              $
              5.0
              
              
              $
              0.1
              
              
              $
              5.1
              
              
              $
              4.1
              
              
              $
              0.7
              
              
              $
              4.8Dispositions
      of oil and gas properties
              
              $
              (0.4
              )
              
              $
              (3.6
              )
              
              $
              (4.0
              )
              
              $
              (0.1
              )
              
              $
              -
              
              
              $
              (0.1
              )RevenuesOil
      and gas sales (1)
              
              $
              309.5
              
              
              $
              80.3
              
              
              $
              389.8
              
              
              $
              307.9
              
              
              $
              61.6
              
              
              $
              369.5Royalties
              
              $
              (56.1
              )
              
              $
              (17.1
              ) (2)
              
              $
              (73.2
              )
              
              $
              (54.1
              )
              
              $
              (12.1
              )(2)
              
              $
              (66.2
              )Commodity
      derivative instruments
              
              $
              (48.8
              )
              
              $
              -
              
              
              $
              (48.8
              )
              
              $
              (5.4
              )
              
              $
              -
              
              
              $
              (5.4
              )ExpensesOperating
              
              $
              61.0
              
              
              $
              2.8
              
              
              $
              63.8
              
              
              $
              66.4
              
              
              $
              1.9
              
              
              $
              68.3General
      and administrative
              
              $
              16.5
              
              
              $
              (0.1
              )
              
              $
              16.4
              
              
              $
              14.6
              
              
              $
              2.5
              
              
              $
              17.1Depletion,
      depreciation, amortization and accretion
              
              $
              89.9
              
              
              $
              21.8
              
              
              $
              111.7
              
              
              $
              93.3
              
              
              $
              26.2
              
              
              $
              119.5Current
      income taxes
              
              $
              -
              
              
              $
              12.6
              
              
              $
              12.6
              
              
              $
              -
              
              
              $
              5.1
              
              
              $
              5.1
 (1)   Net
of oil and gas transportation costs, but before the effects of commodity
derivative instruments.
 (2)  Royalties
include U.S. state production tax.
  Critical
Accounting Policies
  The
financial statements have been prepared in accordance with GAAP. A summary of
significant accounting policies is presented in Note 1. A reconciliation of
differences between Canadian and United States GAAP is presented in Note 16.
Most accounting policies are mandated under GAAP. However, in accounting for oil
and gas activities, we have a choice between two acceptable accounting policies:
the full cost and the successful efforts methods of
accounting.
 The
Fund follows the full cost method of accounting for oil and natural gas
activities. Using the full cost method of accounting, all costs of acquiring,
exploring and developing oil and natural gas properties are capitalized,
including unsuccessful drilling costs and administrative costs associated with
acquisitions and development. Under the successful efforts method of accounting,
all exploration costs, except costs associated with drilling successful
exploration wells, are expensed in the period in which they are incurred. The
difference between these two methodologies is not expected to be significant to
the Fund’s net income or net income per unit as the majority of the Fund’s
drilling activity is not exploration in nature and is more focused on low risk
development drilling that has traditionally achieved high success
rates.
   Under
the full cost method of accounting, an impairment test is applied to the overall
carrying value of property, plant and equipment, on a country by country cost
centre basis with the reserves valued using estimated future commodity prices at
period end. Under the successful efforts method of accounting, the costs are
aggregated on a property-by-property basis. The carrying value of each property
is subject to an impairment test. Each method may generate a different carrying
value of property, plant and equipment and a different net income depending on
the circumstances at period end. Net costs related to operating and
administrative activities during the development of large capital projects are
capitalized until commercial production has commenced and are tested for
impairment separately.
 
 Critical
Accounting Estimates
  The
preparation of financial statements in accordance with GAAP requires management
to make certain judgments and estimates. Due to the timing of when activities
occur compared to the reporting of those activities, management must estimate
and accrue operating results and capital spending. Changes in these judgments
and estimates could have a material impact on our financial results and
financial condition.
  Reserves
  The
process of estimating reserves is critical to several accounting estimates. It
requires significant judgments based on available geological, geophysical,
engineering and economic data. These estimates may change substantially as data
from ongoing development and production activities becomes available, and as
economic conditions impacting oil and gas prices, operating costs and royalty
burdens change. Reserve estimates impact net income through depletion, the
determination of asset retirement obligations and the application of an
impairment test. Revisions or changes in the reserve estimates can have either a
positive or a negative impact on net income and the asset retirement
obligation.
 Page 19 of
27
  
 Asset
Retirement Obligation
 
 Management
calculates the asset retirement obligation based on estimated costs to abandon
and reclaim its net ownership interest in all wells and facilities and the
estimated timing of the costs to be incurred in future periods. The fair value
estimate is capitalized to PP&E as part of the cost of the related asset and
amortized over its useful life.
 
 Business
Combinations
  Management
makes various assumptions in determining the fair values of any acquired
company’s assets and liabilities in a business combination. The most significant
assumptions and judgments made relate to the estimation of the fair value of the
oil and gas properties. To determine the fair value of these properties, we
estimated (a) oil and gas reserves in accordance with NI 51-101 reserve
standards, and (b) future prices of oil and gas.
  Commodity
Prices
  Management’s
estimates of future crude oil and natural gas prices are critical as these
prices are used to determine the carrying amount of PP&E, amounts recorded
for depletion, impairment in the cost centre, and the change in fair value of
financial contracts.
  Trust
Unit Rights
 
 Management
calculates the fair value of rights granted under our trust unit rights
incentive plan using a binomial lattice option-pricing model. This process
involves the use of significant estimates and assumptions, which may change over
time. The values calculated under the option-pricing model may not reflect the
actual value realized by trust unit rights holders.
 
 Derivative
Financial Instruments
 
 Management
uses derivative financial instruments to manage its exposure to market risks
relating to commodity prices, foreign currency exchange rates and interest
rates. Fair values of derivative contracts are subject to fluctuation depending
on the underlying estimate of future commodity prices, foreign currency exchange
rates and interest rates.
 
 
 RECENT
CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
 
 Convergence
of Canadian GAAP with International Financial Reporting Standards
 
 In
2006, Canada’s Accounting Standards Board (AcSB) ratified a strategic plan that
will result in Canadian GAAP, as used by public entities, being converged with
International Financial Reporting Standards (IFRS) by 2011. On February 13, 2008
the AcSB confirmed that use of IFRS will be required for public companies
beginning January 1, 2011. We continue to assess the impact of adopting IFRS and
implementing plans for transition.
 
 Financial
Instruments, Comprehensive Income and Hedges
 
 CICA
Section 3862 - Financial Instruments - Disclosures
 
 This
standard requires entities to provide disclosures in their financial statements
that enable users to evaluate the significance of financial instruments to the
entity’s financial position and performance. It also requires that entities
disclose the nature and extent of risks arising from financial instruments and
how the entity manages those risks.
 
 This
standard is effective for reporting periods beginning January 1, 2008 and will
result in additional disclosures for our financial
instruments.
 
 CICA
Section 3863 - Financial Instruments - Presentation
 
 This
standard establishes presentation guidelines for financial instruments and
non-financial derivatives and deals with the classification of financial
instruments, from the perspective of the issuer, between liabilities and equity,
the classification of related interest, dividends, losses and gains, and the
circumstances in which financial assets and financial liabilities are
offset.
 
 Page 20 of
27
 This
standard is effective for reporting periods beginning January 1, 2008 and should
have a minimal impact on our reporting.
 
 CICA
Section 1535 - Capital Disclosures
 
 This
section details disclosures that must be made regarding an entity’s capital and
how it is managed. The standard requires qualitative information about an
entity’s objectives, policies and processes for managing capital and
quantitative data about what the entity regards as capital. It requires
disclosure of compliance with any capital requirements and consequences of any
non-compliance.
 
 This
standard is effective for reporting periods beginning January 1, 2008 and will
result in additional disclosures around managing capital.
 
 RISK
FACTORS AND RISK MANAGEMENT
 
 Enerplus
investors are participating in the net cash flow from a portfolio of crude oil
and natural gas producing properties. As such, the cash distributions and the
value of Enerplus units are subject to numerous risk factors. These risk
factors, many of which are associated with the oil and gas industry, include,
but are not limited to, the following influences:
 
 Canadian
Government Tax on Income Trusts
 
 On June
22, 2007, Bill C-52 was passed by the Senate and was given royal assent by the
Governor General. As a result, our second quarter future income tax provision
includes a future income tax expense of $78.1 million related to this
legislation. This non-cash expense relates to temporary differences between the
accounting and tax basis of the Fund’s assets and liabilities and has no
immediate impact on cash flow. Tax pools in 2011 may not be sufficient to
shelter taxable income from the new SIFT tax and as a result increased tax may
reduce cash flow available for distributions and development
spending.
 
 We
are currently evaluating alternatives to determine the optimal business
structure for our unitholders. However, we currently see value in the three-year
tax exemption period through 2010 as a distributing entity and would be hesitant
to make major structural changes during this period without compelling reasons
that we do not currently foresee.
 
 Commodity
Price Risk
 
 Enerplus’
operating results and financial condition are dependent on the prices we receive
for our crude oil and natural gas production. These prices may fluctuate widely
in response to a variety of factors including global and domestic economic
conditions, weather conditions, the supply and price of imported oil and
liquefied natural gas, the production and storage levels of North American
natural gas, political stability, transportation facilities, the price and
availability of alternative fuels and government regulations.
 
 We
may use financial derivative instruments and other hedging mechanisms to help
limit the adverse effects of natural gas and oil price volatility. However, we
do not hedge all of our production and expect there will always be a portion
that remains unhedged. Furthermore, we may use financial instruments that offer
only limited protection within selected price ranges. To the extent price
exposure is hedged, we may forego the benefits that would otherwise be
experienced if commodity prices increase, and may be exposed to risk of default
by the counterparties. Refer to the price risk management section.
 
 Oil
and Gas Reserves and Resources Risk
 
 The
value of our trust units are based on, among other things, the underlying value
of the oil and gas reserves and resources. Geological and operational risks can
affect the quantity and quality of reserves and resources and the cost of
ultimately recovering those reserves and resources. Lower oil and natural gas
prices may increase the risk of write-downs of our oil and gas property
investments. Regulatory changes to reporting practices can also result in
reserve or resource write-downs.
 
 We
strive to acquire low risk, mature properties with a high proportion of proved
reserves, positive operating metrics, long reserve lives and predictable
production. Similarly, we generally participate in lower-risk development
projects while farming out or monetizing higher risk exploratory
prospects.
 
 Page 21 of
27
 Each
year, independent engineers evaluate a significant portion of our proved and
probable reserves as well as the resources attributable to our oil sands
properties
 .
 Sproule
Associates Limited (“Sproule”) evaluated 92% of the total proved plus probable
value (discounted at 10%) of our Canadian conventional year-end reserves, in
accordance with NI 51-101 and has reviewed the remainder of the reserves
Enerplus evaluated internally. GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated
the Joslyn bitumen reserves as they have previously performed such evaluations
for the operator of the Joslyn project. Netherland, Sewell & Associates Inc.
(“NSA”) of Dallas, Texas, evaluated the reserves attributed to our assets in the
United States. Both GLJ and NSA evaluated 100% of the reserves in their
respective areas. Both GLJ and NSA utilized Sproule’s forecast and constant
price and cost assumptions as of December 31, 2007 in their evaluations to
maintain consistency. GLJ also evaluated the resources attributable to our
Joslyn and Kirby oil sands projects. The Reserves Committee of the Board of
Directors has reviewed and approved the reserve and resource reports of the
independent evaluators.
 
 Operational
Inflation Risk
 
 Over
      the last few years we have experienced inflationary pressures on both our
      development capital costs and our operating costs. Higher costs decrease
      the amount of cash flow from our operating activities which may affect the
      amount of distributions to
unitholders.
 
 We
strive to control costs through incentive-based compensation plans that reward
employees for such things as cost control and value-added initiatives. We
attempt to minimize costs by exploiting our purchasing strength with suppliers.
We use detailed budgeting and accounting practices to monitor costs.
Multi-functional teams regularly perform integrated field reviews designed to
reduce costs and increase revenues from our properties.
 
 Despite
      these efforts, it can be difficult to control costs in the oil and gas
      industry, especially in periods of high commodity prices when the demand
      for goods and services is strong. Oil and gas production involves a
      significant amount of fixed costs that are difficult to reduce without
      decreasing production. In addition, subsequent to the Focus acquisition,
      approximately 30% of our production is operated by third parties. We have
      limited ability to influence costs on partner-operated
      properties.
 
 Access
to Transportation Capacity
 
 Market
access for crude oil and natural gas production in Canada and the United States
is dependent on the ability of Enerplus and the buyers of our production to
access sufficient transportation capacity on third party pipelines to transport
all production volumes. While the third party pipelines generally expand
capacity to meet market needs, there can be differences in timing between the
growth of production and the growth of pipeline capacity. There are also
occasionally operational reasons for curtailing transportation capacity.
Accordingly, there can be periods where pipeline capacity is insufficient to
transport all of the production from a given region, causing volume curtailments
for all shippers, including Enerplus and its production buyers.
 
 We
continuously monitor this risk for both the short and longer term through
dialogue with the third party pipelines and other market participants, as well
as by review of supply and demand studies prepared by third party experts. Where
available and commercially appropriate given the production profile and
commodity, we attempt to mitigate this risk by contracting for firm
transportation capacity or by using other means of transportation.
 
 Production
Replacement Risk
 
 Oil and
natural gas reserves naturally deplete as they are produced over time. Our
ability to replace production depends on our success in acquiring new reserves
and resources and developing existing reserves and resources. Acquisitions of
oil and gas assets depend on our assessment of value at the time of acquisition.
Incorrect assessments of value can adversely affect distributions to unitholders
and the value of our trust units.
 
 Acquisitions
and our development capital program are subject to investment guidelines, due
diligence and review. Major acquisitions are approved by the Board of Directors
and, where appropriate, independent reserve engineer evaluations are
obtained.
 
 Page 22 of
27
 Non-Resident
Ownership and Mutual Fund Trust Status
 
 Since
our listing on the New York Stock Exchange in November of 2000, we have seen
increased trading volumes and levels of ownership by non-residents of Canada.
Based on information received from our transfer agent and financial
intermediaries in February 2008, an estimated 72% of our outstanding trust units
were held by non-residents. Immediately after the acquisition of Focus, on
February 13, 2008, we estimate that approximately 63% of our trust units were
held by non-residents. However, this estimate may not be accurate as it is based
on certain assumptions and data from the securities industry that does not have
a well-defined methodology to determine the residency of beneficial holders of
securities.
 
 Enerplus
currently meets the requirements of a Mutual Fund Trust as defined in the Income
Tax Act (Canada). Our trust indenture does not have a specific limit on the
percentage of trust units that may be owned by non-residents.
 
 At
this time, management does not anticipate any legislative changes that would
affect our status as a mutual fund trust; however, we have implemented
provisions in our trust indenture to allow the Board of Directors to adopt
non-resident ownership constraints, if required, in order to ensure Enerplus
maintains its mutual fund trust status.
 
 Regulatory
Risk
 
 Government
royalties, income tax laws, environmental laws and regulatory requirements can
have a significant financial and operational impact on Enerplus. During 2007 the
Alberta government announced proposed changes to the provincial royalty program
expected to be effective on January 1, 2009 (see the Royalties section of this
MD&A for further details). Canada ratified the Kyoto Protocol in late 2002,
which requires countries to reduce their emissions of carbon dioxide and other
greenhouse gases. The Canadian federal government is currently gathering
information to set emission targets for the industry. The details are projected
to be announced by 2010 and could affect capital expenditures and operating
costs.
 
 Our
operations expose us to possible regulatory changes by both Canadian and U.S.
governments. As an oil and gas producer, we are subject to a broad range of
regulatory requirements. Similarly, as a mutual fund trust, we have a unique
structure that is vulnerable to changes in legislation or income tax
law.
 
 Although
we have no control over these regulatory risks, we continuously monitor changes
in these areas through such activities as participating in industry
organizations and conferences, the exchange of information with third party
experts and employing qualified individuals to assess the impact of such changes
on our financial and operating results.
 
 Access
to Capital Markets
 
 Our
access to capital has allowed us to fund a portion of our acquisitions and
development capital program through equity and debt and as a result distribute
the majority of our cash flow to our unitholders. As such, we are dependent on
continued access to the capital markets to fund our activities directed towards
maintaining and increasing value for our unitholders. To the extent the cash
flow retained by the Fund together with new equity and debt financing is not
sufficient to cover required capital expenditures then cash distributions to
unitholders may be reduced. Furthermore, current tightening global credit
markets may have an adverse effect on our ability to access these capital
markets.
 
 Enerplus
has listings on the Toronto and New York stock exchanges and maintains an active
investor relations
program.
 
 We
maintain a prudent capital structure by retaining a portion of cash flow for
capital spending and utilizing the equity markets when deemed
appropriate.
 
 Continued
access to capital is dependent on our ability to maintain our track record of
performance and to demonstrate the advantages of the acquisition or development
program that we are financing at the time.
 
 Health,
Safety and Environmental Risk (“HSE”)
 
 Health,
safety and environmental risks influence the workforce, operating costs and the
establishment of regulatory
standards.
 
 Page 23 of
27
 We
have established a HSE Management System designed to:
 
 •
              provide staff with the
      training and resources needed to complete work safely and
      effectively;
 •
              incorporate hazard assessment
      and risk management as an integral part of everyday
      business;
 •
              monitor performance to ensure
      that our operations comply with legal obligations and the standards we set
      for ourselves; and
 •
              identify and manage
      environmental liabilities associated with our existing asset base
      and
 potential
      acquisitions.
 
 We
have a site inspections program and a corrosion risk management program designed
to ensure compliance with environmental laws and regulations. We carry insurance
to cover a portion of our property losses, liability and business interruption.
HSE risks are reviewed regularly by the HSE committee comprised of members of
the Board of Directors.
 
 Interest
Rate Exposure
 
 The
Fund has exposure to movements in interest rates. Changing interest rates can
affect borrowing costs and the trust unit price of yield-based investments such
as Enerplus.
 
 We
monitor the interest rate forward market and have fixed the interest rate on
approximately 18% of our debt through our senior unsecured notes and interest
rate swaps.
 
 Foreign
Currency Exposure
 
 We have
exposure to fluctuations in foreign currency as a result of the issuance of
senior unsecured notes denominated in U.S. dollars. Our U.S. operations are
directly exposed to fluctuations in the U.S. dollar when translated to our
Canadian dollar denominated financial statements.
 
 We also
have indirect exposure to fluctuations in foreign currency as our crude oil
sales and a portion of our natural gas sales are based on U.S. dollar indices.
Our oil and gas revenues are negatively impacted as the Canadian dollar
strengthens relative to the U.S. dollar.
 
 We
have hedged our foreign currency exposure on both our US$175 million and US$54
million of senior unsecured notes using financial swaps that convert the U.S.
denominated debt to Canadian dollar debt. In addition we have hedged our
interest obligation on our US$175 million notes.
 
 We
have not entered into any other foreign currency derivatives with respect to oil
and gas sales or our U.S. operations.
 
 Counterparty
Risk
 
 We
assume customer credit risk associated with oil and gas sales, financial hedging
transactions and joint venture
participants.
 
 We
have established credit policies and controls designed to mitigate the risk of
default or non-payment with respect to oil and gas sales, financial hedging
transactions and joint venture participants. We maintain a diversified sales
customer base and we review our single-entity exposure on a regular basis. We do
not have exposure to asset backed commercial paper, however we do have exposure
to Canadian and U.S. banks as a counterparty to financial hedging
transactions.
 
 Unitholder
Liability
 
 In the
past, there has been some concern that trust unitholders might be held
personally liable for the indebtedness of the Fund.
 
 Enerplus
is registered in Alberta, which passed legislation in June 2005 to provide
statutory protection for unitholders similar to the protection afforded
shareholders in a corporation. Three other provinces (Ontario, Quebec, and
Manitoba) also have statutory protection for unitholders. Our bank credit
agreement and our debenture agreements do not allow the creditors to extend
recourse to unitholders beyond the unitholders’ equity investment in the
Fund.
 
 Recruitment
and Retention of Qualified Personnel
 
 There
is strong competition in all aspects of the oil and gas industry. Enerplus
competes with a substantial number of other organizations for capital,
acquisitions of reserves, undeveloped lands, access to drilling rigs, service
rigs and other equipment, access to processing facilities, pipeline and refining
capacity and in all other aspects of our operations. Other organizations may
have greater technical and financial resources than Enerplus which leads to
increased competition. Another rising challenge is the recruitment and retention
of qualified professional staff at all levels in the organization. Increased
activity within the oil and gas sector can create a competitive marketplace
which presents challenges in recruiting and retaining key
personnel.
 
 Page 24 of
27
 In
order to attract and retain qualified personnel we offer competitive
compensation including performance based plans.
 
 
 SUMMARY
2008 OUTLOOK
 
 Enerplus
offers investors the benefits of owning a large, diversified portfolio of
producing oil and natural gas properties within Canada and the United States. As
such, our business prospects are closely linked to the opportunities and
challenges associated with oil and natural gas production. In particular, we are
strongly influenced by the price of crude oil and natural gas, both of which
have been volatile in recent years. Our comments with respect to our 2008
outlook should be taken within the context of the current commodity price
environment.
 
 The
following summarizes Enerplus’ 2008 guidance as provided throughout this
MD&A and includes the acquisition of Focus at the closing date of February
13, 2008. We do not attempt to forecast commodity prices and, as a result, we do
not forecast future cash flow or cash distributions. Readers are encouraged to
apply their own price expectations to the following factors to arrive at an
expected cash distribution.
 
 Summary
      of 2008 Expectations
              Target
              CommentsAverage
      annual production
              98,000
      BOE/day
              Does
      not include any further potential acquisitions/divestmentsExit
      rate December 2008 production
              100,000
      BOE/day
              Assumes
      $580 million development capital spending2008
      production mix
              60%
      gas, 40% liquidsAverage
      royalty rate
              19%
              Percentage
      of gross unhedged salesOperating
      costs
              $8.65/BOEG&A
      costs
              $2.20/BOE
              Includes
      non-cash charges of $0.20/BOE (unit rights incentive plan)U.S.
      income and withholding tax - cash costs
              20%
              Applied
      to net cash flow generated by U.S. operations and assumes repatriation of
      the funds to Canada after U.S. development capital spendingAverage
      interest cost
              4.5%
              Based
      on current fixed rates and forward marketPayout
      ratio
              60%
      - 90%Development
      capital spending
              $580
      million
 
 We
expect our 2008 development capital spending to be $580 million, which is 50%
higher than our 2007 spending. We plan to continue to withhold a portion of our
cash flow to finance this capital program and we expect the payout ratio to be
within our 60-90% guidance range. We believe it is important to maintain a
conservative balance sheet as a defense against commodity price changes and to
be positioned to capture acquisition opportunities.
  We will
continue to focus on low-risk development opportunities and review our risk
management strategies in response to changing prices and the economics of our
acquisition and development projects.
  For
2008, we estimate that 95% of cash distributions will be taxable and 5% will be
a tax-deferred return of capital for our Canadian unitholders. For our U.S.
unitholders, we estimate that 90% of cash distribution will be taxable and 10%
will be a tax-deferred return of capital.
 
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 DISCLOSURE
CONTROLS ANDPROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
 
 Under
the supervision of our Chief Executive Officer and Chief Financial Officer we
have evaluated the effectiveness of our disclosure controls and procedures as of
the end of the period covered by this report and concluded that our disclosure
controls and procedures are effective. There were no changes in our internal
control over financial reporting during the quarter ended December 31, 2007 that
have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
 
 ADDITIONAL
INFORMATION
 
 Additional
information relating to Enerplus Resources Fund, including our Annual
Information Form, is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at
www.sec.govand at www.enerplus.com.
 
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27
 FORWARD-LOOKING
INFORMATION AND STATEMENTS
 
 This
management's discussion and analysis ("MD&A") contains certain
forward-looking information and statements within the meaning of applicable
securities laws. The use of any of the words "expect", "anticipate", "continue",
"estimate", "objective", "ongoing", "may", "will", "project", "should",
"believe", "plans", "intends" and similar expressions are intended to identify
forward-looking information or statements. In particular, but without limiting
the foregoing, this MD&A contains forward-looking information and statements
pertaining to the following: the amount, timing and tax treatment of cash
distributions to unitholders; future payout ratio; future tax treatment of
income trusts such as the Fund; future structure of the Fund and its
subsidiaries; the Fund’s tax pools; the volumes and estimated value of the
Fund's oil and gas reserves and resources; the volume and product mix of the
Fund's oil and gas production; future oil and natural gas prices and the Fund's
commodity risk management programs; the amount of future asset retirement
obligations; future liquidity and financial capacity; future results from
operations, cost estimates and royalty rates; future development, exploration,
and acquisition and development activities and related expenditures, including
with respect to both our conventional and oil sands activities.
 
 The
forward-looking information and statements contained in this MD&A reflect
several material factors and expectations and assumptions of the Fund including,
without limitation: that the Fund will continue to conduct its operations in a
manner consistent with past operations; the general continuance of current
industry conditions; the continuance of existing and in certain circumstances,
proposed tax and royalty regimes; the accuracy of the estimates of the Fund's
reserve volumes; and certain commodity price and other cost assumptions. The
Fund believes the material factors, expectations and assumptions reflected in
the forward-looking information and statements are reasonable but no assurance
can be given that these factors, expectations and assumptions will prove to be
correct.
 
 The
forward-looking information and statements included in this MD&A are not
guarantees of future performance and should not be unduly relied upon. Such
information and statements involve known and unknown risks, uncertainties and
other factors that may cause actual results or events to differ materially from
those anticipated in such forward-looking information or statements including,
without limitation: changes in commodity prices; unanticipated operating results
or production declines; changes in tax or environmental laws or royalty rates;
increased debt levels or debt service requirements; inaccurate estimation of the
Fund's oil and gas reserves volumes; limited, unfavourable or no access to
capital markets; increased costs; the impact of competitors; and certain other
risks detailed from time to time in the Fund's public disclosure documents
including, without limitation, those risks identified in this MD&A, our
MD&A for the year ended December 31, 2007 and in the Fund's Annual
Information Form.
 
 The
forward-looking information and statements contained in this MD&A speak only
as of the date of this MD&A, and none of the Fund or its subsidiaries
assumes any obligation to publicly update or revise them to reflect new events
or circumstances, except as may be required pursuant to applicable
laws.
 
 
 
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