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.

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:

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.

⁽¹⁾ Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

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%.

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.

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:

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.

The following table summarizes the effects of our financial contracts on income for the years ended December 31, 2007 and 2006.

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.

⁽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.

⁽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.

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:

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.

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.

⁽¹⁾Net of post-closing adjustments.

The following is a summary by playtype of our development capital expenditures during 2007 and 2006, as well as our current expectations for 2008 including Focus.

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.

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. 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 $22.6 million 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: