TSX: ERF.un NYSE: ERF CALGARY, Aug. 7 /CNW/ - Enerplus Resources Fund is pleased to report one of the most successful quarters in our operating history. Highlights are as follows: - Cash flow from operating activities was $364.5 million, up 53% over the second quarter of 2007 due to strong commodity prices and record production volumes. - Cash distributions for the quarter were maintained at $0.42 per unit per month ($1.26 per unit for the quarter) resulting in a payout ratio of 56% versus 68% for the second quarter of 2007. Including our development capital expenditures, our adjusted payout ratio for the second quarter was approximately 80% indicating that our cash flow was more than covering both distributions and capital spending. - Given the strength in commodity prices, the performance of our operations and the health of our balance sheet, we will be increasing the monthly cash distribution to unitholders by 12% to $0.47 per unit per month effective with the September 20, 2008 cash distribution payment. - Daily production volumes averaged a record 100,188 BOE during the quarter, reflecting the full integration of the Focus assets within our portfolio, the earlier than expected return of our Giltedge production and the continued success of our development capital program. - With the exception of a small increase in operating costs, we remain on track to meet our operational guidance for 2008. We continue to expect to produce an average of 98,000 BOE/day for the year with an exit rate of 100,000 BOE/day. - We have completed the analysis of the core holes drilled in our winter delineation program on our Kirby oil sands lease. Preliminary estimates from our third party reserves engineers indicate a revised best estimate contingent resource of approximately 414 million barrels, representing an increase of 170 million barrels (70%) over our original estimate of 244 million barrels for the entire lease. We continue to prepare our regulatory application for the first 10,000 bbl/day project and expect to file the application later this fall. - Subsequent to quarter end we successfully divested our working interest in the Joslyn oil sands lease for net proceeds of approximately $500 million compared to our investment of approximately $115 million. - We continue to maintain a conservative balance sheet with a debt-to-cash flow ratio of approximately 0.4x after using the Joslyn sale proceeds to pay down bank debt. The flexibility of a strong balance sheet will allow us to continue to develop our existing conventional resource plays, fully develop our growing Kirby oil sands resource and pursue high quality acquisitions to add accretive cash flow to our business. - We realized an average sales price of $9.87/Mcf on our natural gas production and approximately $114.04/bbl on our crude oil production. These represent increases of 40% and 84% respectively over the second quarter of 2007. With the increase in commodity prices, we realized cash hedging losses of $64 million in the quarter. - We invested $88 million on our development program drilling 100 gross wells. 60% of our expenditures were focused on crude oil, but the majority of our wells drilled were in our shallow gas resource play. - Our cash operating costs were $9.43/BOE compared to $9.80/BOE last year at this time. We are raising our guidance on operating costs for the year to approximately $9.00/BOE from $8.65/BOE, primarily due to increased service rig activity on optimization efforts in the U.S. and additional costs for fuel and supplies. Although the well optimization efforts in the U.S. have increased our overall operating costs, we are pleased with the production performance from our Bakken Oil resource play as a result. - Cash general and administrative expenses were $1.67/BOE versus $1.94/BOE during the second quarter of 2007. SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS All amounts are stated in Canadian dollars unless otherwise specified. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading. Certain prior year amounts have been restated to reflect current year presentation. Readers are also urged to review the Management's Discussion & Analysis (MD&A) and Audited Financial Statements for more fulsome disclosure on our operations. These reports can be found on our website at www.enerplus.com, our SEDAR profile at www.sedar.com and as part of our SEC filings available on www.sec.gov. SELECTED FINANCIAL RESULTS Three months Six months ended June 30, ended June 30, (in Canadian dollars) 2008 2007 2008 2007 ------------------------------------------------------------------------- Financial (000's) Cash Flow from Operating Activities $ 364,457 $ 237,482 $ 620,673 $ 430,663 Cash Distributions to Unitholders(1) 202,346 162,607 394,704 320,278 Cash Withheld for Acquisitions and Capital Expenditures 162,111 74,875 225,969 110,385 Net Income 112,230 40,084 233,624 147,957 Debt Outstanding (net of cash) 1,027,578 657,945 1,027,578 657,945 Development Capital Spending 88,008 80,446 214,270 190,398 Acquisitions 1,740 204,016 1,766,809 267,394 Divestments 86 5,518 2,208 5,473 Actual Cash Distributions paid to Unitholders $ 1.26 $ 1.26 $ 2.52 $ 2.52 Financial per Weighted Average Trust Units(2) Cash Flow from Operating Activities $ 2.22 $ 1.85 $ 3.98 $ 3.42 Cash Withheld for Acquisitions and Capital Expenditures 0.99 0.58 1.45 0.88 Net Income 0.68 0.31 1.50 1.18 Payout Ratio(3) 56% 68% 64% 74% Selected Financial Results per BOE(4) Oil & Gas Sales(5) $ 80.56 $ 50.96 $ 71.85 $ 50.00 Royalties (15.14) (9.63) (13.46) (9.43) Commodity Derivative Instruments (7.03) (0.15) (4.35) 0.45 Operating Costs (9.43) (9.80) (9.21) (9.16) General and Administrative (1.67) (1.94) (1.75) (1.93) Interest and Other Income and Foreign Exchange (1.32) (1.36) (1.10) (1.34) Taxes (1.78) (0.43) (1.49) (0.35) Restoration and Abandonment (0.52) (0.51) (0.51) (0.48) ------------------------------------------------------------------------- Cash Flow from Operating Activities before changes in non-cash working capital $ 43.67 $ 27.14 $ 39.98 $ 27.76 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted Average Number of Trust Units Outstanding Including Equivalent Exchangeable Limited Partnership Units (thousands) 164,483 128,361 155,984 125,849 Debt/Trailing 12 Month Cash Flow Ratio(6) 0.9x 0.7x 0.9x 0.7x ------------------------------------------------------------------------- SELECTED OPERATING RESULTS Three months Six months ended June 30, ended June 30, 2008 2007 2008 2007 ------------------------------------------------------------------------- Average Daily Production Natural gas (Mcf/day) 359,349 264,946 333,559 270,300 Crude oil (bbls/day) 35,486 34,178 34,376 34,869 NGLs (bbls/day) 4,810 4,143 4,712 4,325 Total (BOE/day) 100,188 82,478 94,681 84,244 % Natural gas 60% 54% 59% 53% Average Selling Price(5) Natural gas (per Mcf) $ 9.87 $ 7.04 $ 8.79 $ 7.13 Crude oil (per bbl) 114.04 61.93 100.47 59.56 NGLs (per bbl) 80.55 53.34 75.29 48.55 US$ exchange rate 0.99 0.91 0.99 0.88 Net Wells drilled 72 36 197 75 Success Rate 100% 100% 100% 99% ------------------------------------------------------------------------- (1) Calculated based on distributions paid or payable. (2) Based on weighted average trust units outstanding for the period, including the exchangeable limited partnership units assumed through the Focus Energy Trust acquisition. (3) Calculated as Cash Distributions to Unitholders divided by Cash Flow from Operating Activities. (4) Non-cash amounts have been excluded. (5) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. (6) Including the trailing 12 month cash flow of Focus Energy Trust. TRUST UNIT TRADING SUMMARY for the three months TSX - ERF.un NYSE - ERF ended June 30, 2008 (CDN$) (US$) ------------------------------------------------------------------------- High $ 49.85 $ 50.63 Low $ 43.44 $ 42.43 Close $ 47.18 $ 46.24 2008 CASH DISTRIBUTIONS PER TRUST UNIT Production Month Payment Month CDN$ US$ ------------------------------------------------------------------------- First Quarter Total $ 1.26 $ 1.24 April June $ 0.42 $ 0.41 May July 0.42 0.42 June August 0.42 0.41(*) ------------------------------------------------------------------------- Second Quarter Total $ 1.26 $ 1.24 Total Year-to-Date $ 2.52 $ 2.48 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Calculated using a Canadian/US$ exchange rate of 1.02 2008 PRODUCTION AND DEVELOPMENT ACTIVITY Three months ended June 30, --------------------------------------------------- Wells Drilled(*) ------------------------- Production Capital Play Type Volumes Spending (BOE/day) ($ millions) Gross Net ------------------------------------------------------------------------- Shallow Gas & CBM 25,438 $ 23.9 68 67.4 Crude Oil Waterfloods 16,484 10.7 - - Deep Tight Gas 15,613 8.9 2 1.2 Bakken Oil 11,346 13.5 4 2.9 Other Conventional Oil & Gas 31,307 18.1 26 0.8 ------------------------------------------------------------------------- Total Conventional 100,188 75.1 100 72.3 Oil Sands Kirby - 3.9 - - Joslyn - 8.5 - - Laricina - 0.5 - - ------------------------------------------------------------------------- Total Oil Sands - 12.9 - - Total 100,188 88.0 100 72.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Six months ended June 30, --------------------------------------------------- Wells Drilled(*) ------------------------- Production Capital Play Type Volumes Spending (BOE/day) ($ millions) Gross Net ------------------------------------------------------------------------- Shallow Gas & CBM 22,939 $ 46.3 217 159.4 Crude Oil Waterfloods 15,777 27.9 22 10.5 Deep Tight Gas 14,407 31.8 30 5.2 Bakken Oil 11,124 33.0 8 6.0 Other Conventional Oil & Gas 30,434 40.9 79 16.0 ------------------------------------------------------------------------- Total Conventional 94,681 179.9 356 197.1 Oil Sands Kirby - 24.5 - - Joslyn - 9.2 - - Laricina - 0.7 - - ------------------------------------------------------------------------- Total Oil Sands - 34.4 - - Total 94,681 214.3 356 197.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Drilling totals do not include delineation wells at Kirby or service wells drilled during the quarter Drilling success rate year-to-date: 100% OPERATIONS REVIEW Weather delays, a reduction in non-operated spending and lower than budgeted spending at Joslyn resulted in slightly lower than planned development capital spending of $88 million in the quarter. Redeployment of approximately $40 million of development capital from oil sands (Joslyn) to our conventional business, an increase in other operated conventional development spending across our resource plays and an expectation of increased non-operated spending for the balance of the year allows us to maintain our annual development capital spending guidance of $580 million. We are raising our guidance on operating costs for the year to approximately $9.00/BOE from $8.65/BOE, primarily due to increased service rig activity on optimization efforts in the U.S. and additional costs for fuel and supplies. Although the well optimization efforts in the U.S. have increased our overall operating costs, we are pleased with the production performance from our Bakken Oil resource play as a result of these activities. Approximately 60% of our capital spending this quarter was directed toward crude oil development opportunities, although the majority of the wells drilled were in our shallow gas resource play. Wet weather caused a delay on some of our development capital expenditures in the quarter but significant drilling and tie-ins prior to break-up in the first quarter and better than expected production performance in key areas throughout the second quarter resulted in strong overall operational performance. Efficient planning and execution of turnarounds by our staff minimized facility downtime, offset weather delays and also helped us meet our production targets. In our shallow gas resource play, we invested nearly a third of our quarterly conventional spending by drilling 68 gross wells in the second quarter. At Shackleton, we drilled 48 wells and are expanding our development program for the rest of the year to drill 60 additional wells above our original plans, significantly increasing recompletion work and adding more compression by the end of 2008. Our Giltedge waterflood property, which was shut down late in 2007 due to a facility fire and had been partially operating with temporary facilities early in 2008, resumed full operations on April 14, 2008. The restart was two weeks earlier than we anticipated and production has returned to near normal levels. Optimization efforts in the U.S. continued during the second quarter and we anticipate resuming our refrac and 3rd well per section program in the third quarter, increasing our development capital spending in the U.S. throughout the balance of the year. Our safety performance in the field for both employees and contractors improved this quarter over last with no medical aid incidents. This was due primarily to our increased emphasis on motor vehicle safety, proactive hazard identification and improvements in near miss reporting. CANADIAN FEDERAL TAX LEGISLATION On July 14, 2008, the Canadian Department of Finance released draft amendments to the Canadian Income Tax Act which included provisions to facilitate the tax efficient conversion of a specified investment flow through ("SIFT") trust into a corporation. These draft provisions are designed to ensure that the conversion of a trust to a corporation can be structured in such a manner that neither the trust nor its unitholders will be subject to Canadian tax on the transaction. We believe that any corporate conversion transaction should be tax deferred for our U.S. unitholders as well. The Department of Finance is accepting comments on these proposals until September 15, 2008 after which it intends to present the amendments as part of a tax reform bill in the Fall of 2008. As we have stated since the 2006 trust taxation announcement, we believe that there is value in retaining the trust structure until the end of 2010. We currently do not foresee any compelling reasons to make major changes to our corporate structure before 2011. MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") The following discussion and analysis of financial results is dated August 6, 2008 and is to be read in conjunction with: - the audited consolidated financial statements as at and for the years ended December 31, 2007 and 2006; and - the unaudited interim consolidated financial statements as at and for the three and six months ended June 30, 2008 and 2007. All amounts are stated in Canadian dollars unless otherwise specified. All references to GAAP refer to Canadian generally accepted accounting principles. All note references relate to the notes included with the accompanying unaudited interim consolidated financial statements. In accordance with Canadian practice revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading. The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our disclaimer on forward-looking information and statements. NON-GAAP MEASURES Throughout the MD&A we use the term "payout ratio" to analyze operating performance, leverage and liquidity. We calculate payout ratio by dividing cash distributions to unitholders ("cash distributions") by cash flow from operating activities ("cash flow"), both of which are measures prescribed by GAAP which appear on our consolidated statements of cash flows. The term "payout ratio" does not have a standardized meaning or definition as prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other entities. Refer to the "Liquidity and Capital Resources" section of the MD&A for further information on cash flow, cash distributions and payout ratio. OVERVIEW Production for the second quarter was in-line with our expectations averaging 100,188 BOE/day. Cash flow from operating activities totaled $364.5 million representing an increase of $108.3 million or 42% from the first quarter of 2008 and $127.0 million or 53% from the second quarter of 2007. The increases are mainly due to higher commodity prices along with increased production as a result of the acquisition of Focus Energy Trust ("Focus"). The higher commodity prices also impacted our price risk management costs as we incurred cash losses of $64.0 million and non-cash losses of $161.0 million due to higher forward commodity prices at quarter end. For the second quarter of 2008 our development capital spending was $88.0 million as we drilled 72 net wells with a 100% success rate. Operating costs were slightly higher than anticipated due to optimization work in the United States. All of our 2008 guidance targets remain unchanged with the exception of our annual operating costs which we are increasing to $9.00/BOE, primarily as a result of our U.S. optimization efforts. On July 31, 2008, subsequent to quarter end, we successfully disposed of our Joslyn oil sands lease ("Joslyn") for net proceeds of approximately $500 million. The proceeds have been used to pay down bank debt which further strengthens our balance sheet and positions us well for future growth. Given the strength in commodity prices and the performance of our operations we are increasing monthly cash distributions to $0.47/unit effective September 20, 2008. RESULTS OF OPERATIONS Production Production in the second quarter of 2008 was in-line with our expectations averaging 100,188 BOE/day, an increase of 12% from 89,150 BOE/day in the first quarter of 2008. For the three and six months ended June 30, 2008 production increased 21% and 12% respectively, compared to the same periods in 2007. The increases are primarily due to the additional production from the Focus assets acquired on February 13, 2008. Average production volumes for the three and six months ended June 30, 2008 and 2007 are outlined below: Daily Three months ended June 30, Six months ended June 30, Production Volumes 2008 2007 % Change 2008 2007 % Change ------------------------------------------------------------------------- Natural gas (Mcf/day) 359,349 264,946 36% 333,559 270,300 23% Crude oil (bbls/day) 35,486 34,178 4% 34,376 34,869 (1)% Natural gas liquids (bbls/day) 4,810 4,143 16% 4,712 4,325 9% Total daily sales (BOE/day) 100,188 82,478 21% 94,681 84,244 12% ------------------------------------------------------------------------- Based on the results of our second quarter we continue to expect 2008 annual production volumes to average 98,000 BOE/day and our 2008 exit rate to be approximately 100,000 BOE/day. Pricing The prices received for our natural gas and crude oil production have a direct impact on our earnings, cash flow and financial condition. The following table compares our average selling prices for the three and six months ended June 30, 2008 and 2007. It also compares the benchmark price indices for the same periods: Three months ended June 30, Six months ended June 30, % % Average Selling Price(1) 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Natural gas (per Mcf) $ 9.87 $ 7.04 40% $ 8.79 $ 7.13 23% Crude oil (per bbl) $114.04 $61.93 84% $100.47 $59.56 69% Natural gas liquids (per bbl) $ 80.55 $53.34 51% $ 75.29 $48.55 55% Per BOE $ 80.56 $50.96 58% $ 71.85 $50.00 44% Average Benchmark Pricing ------------------------------------------------------------------------- AECO natural gas - monthly index (CDN$/Mcf) $ 9.35 $ 7.37 27% $ 8.24 $ 7.42 11% AECO natural gas - daily index (CDN$/Mcf) $ 10.22 $ 7.07 45% $ 9.06 $ 7.23 25% NYMEX natural gas - monthly NX3 index (US$/Mcf) $ 10.80 $ 7.56 43% $ 9.43 $ 7.26 30% NYMEX natural gas - monthly NX3 index CDN$ equivalent (CDN$/Mcf) $ 10.91 $ 8.31 31% $ 9.53 $ 8.25 16% WTI crude oil (US$/bbl) $123.98 $ 65.03 91% $110.95 $ 61.65 80% WTI crude oil CDN$ equivalent (CDN$/bbl) $125.23 $ 71.46 75% $112.07 $ 70.06 60% CDN$/US$ exchange rate 0.99 0.91 9% 0.99 0.88 13% ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. During the quarter the AECO natural gas price rose 30% from a low of $9.08/Mcf to a high of $11.80/Mcf. This price increase during the second quarter was supported by the strength of crude oil, lower storage inventories, lower liquefied natural gas imports into the U.S. and weather concerns. We realized an average price on our natural gas of $9.87/Mcf (net of transportation costs) during the three months ended June 30, 2008, an increase of 40% from $7.04/Mcf for the same period in 2007. For the six months ended June 30, 2008 we realized a 23% increase in our average price of $8.79/Mcf compared to the same period in 2007. The majority of our natural gas sales are priced with reference to the monthly or daily AECO indices. The 40% and 23% increases for the three and six month periods ended June 30, 2008 are comparable to the changes experienced at AECO. Crude oil prices rose steadily during the second quarter as a result of low inventories, a weak U.S. dollar and supply risks related to Nigeria and Iran. The average price we received for our crude oil during the three months ended June 30, 2008 increased 84% to $114.04/bbl (net of transportation costs) compared to $61.93/bbl during the same period in 2007. Similarly, the West Texas Intermediate ("WTI") crude oil benchmark price, in Canadian dollars, increased 75% from the corresponding period in 2007. For the six months ended June 30, 2008 our crude oil price increased 69% to $100.47/bbl (net of transportation costs), while the WTI benchmark, in Canadian dollars, increased 60%. Medium and heavy differentials narrowed as a percentage of WTI compared to the prior period of 2007. The Canadian dollar strengthened against the U.S. dollar during the three and six months ended June 30, 2008 compared to the same periods in 2007. As most of our crude oil and natural gas is priced in reference to U.S. dollar denominated benchmarks, this movement in the exchange rate reduced the Canadian dollar prices that we would have otherwise realized. Price Risk Management We have developed a price risk management framework to respond to the volatile commodity price environment in a prudent manner. Consideration is given to our overall financial position together with the economics of our development capital program and acquisitions. Consideration is also given to the upfront costs of our risk management program as we seek to limit our exposure to price downturns. Hedge positions for any given term are transacted across a range of prices and time. With respect to our natural gas and crude oil hedges for 2008, our overall hedge position was influenced by our desire to provide a level of protection to the downside on cash flow. Considering all financial contracts transacted as of July 25, 2008, we have protected a portion of our natural gas price risk through to October 31, 2009 and a portion of our crude oil price risk through to December 31, 2009. We have also taken steps to protect our exposure to rising electricity costs for some of our consumption in the Alberta power market through to December 31, 2009. See Note 9 for a list of our current price risk management positions. The following is a summary of the financial contracts in place at July 25, 2008, expressed as a percentage of our forecasted net production volumes: Natural Gas (CDN$/Mcf) Crude Oil (US$/bbl) ---------------------------------------------------------------------- July 1, November 1, April 1, July 1, January 1, 2008 - 2008 - 2009 - 2008 - 2009 - October 31, March 31, October 31, December December 2008 2009 2009 31, 2008 31, 2009 ------------------------------------------------------------------------- Floor Prices (puts) $ 7.09 $ 9.20 $ 9.48 $72.09 $94.62 % (net of royalties) 25% 21% 4% 34% 21% Fixed Price (swaps) $ 7.44 $ 9.35 $ 7.86 $79.97 $100.05 % (net of royalties) 20% 3% 2% 18% 2% Capped Price (calls) $ 8.25 $11.24 - $85.48 $92.98 % (net of royalties) 25% 12% - 22% 11% ------------------------------------------------------------------------- Based on weighted average price (before premiums), estimated average annual production of 98,000 BOE/day and assuming a royalty rate of 19% for 2008. For 2009 we have assumed a 26% royalty rate reflecting the increased royalties for Alberta production at the current forward commodity price levels. Accounting for Price Risk Management During the second quarter of 2008 our price risk management program incurred cash losses of $16.0 million on our natural gas contracts and $48.0 million on our crude oil contracts, compared to cash losses of $0.8 million and $0.3 million respectively during the second quarter of 2007. For the six months ended June 30, 2008 we experienced cash losses of $11.8 million on our natural gas contracts and cash losses of $63.2 million on our crude oil contracts, compared to a loss of $1.3 million and a gain of $8.1 million respectively for the same period in 2007. The increase in cash losses for the three and six months ended June 30, 2008 is the result of commodity prices rising above our swap and sold call positions. At June 30, 2008 both the current and forward commodity prices for crude oil and natural gas were at all time highs which impacted the fair value of our commodity derivative instruments. The fair value of our natural gas and crude oil derivative instruments, net of premiums, represented losses of $89.9 million and $199.2 million respectively at June 30, 2008. These loss positions are based on forward natural gas and crude oil prices and are recorded as current deferred financial credits on our balance sheet. In comparison, at March 31, 2008 the fair value of our natural gas and crude oil derivative instruments represented losses of $50.2 million and $77.9 million respectively. The change in the fair value of our commodity derivative instruments during the second quarter of 2008 resulted in unrealized losses of $39.7 million for natural gas and $121.3 million for crude oil. For the six months ended June 30, 2008 the change in fair value of our commodity derivative instruments resulted in unrealized losses of $98.0 million for natural gas and $142.4 million for crude oil. See Note 9 for details. Between June 30, 2008 and July 25, 2008 the market prices for crude oil decreased by 12% while natural gas prices decreased by 31%. If the forward market remains at these lower levels relative to June 30, 2008 we would expect to record recoveries on our unrealized non-cash losses in subsequent quarters. The following table summarizes the effects of our financial contracts on income: Risk Management Costs Three months ended Three months ended ($ millions, except June 30, June 30, per unit amounts) 2008 2007 ------------------------------------------------------------------------- Cash losses: Natural gas $ (16.0) $(0.49)/Mcf $ (0.8) $(0.03)/Mcf Crude oil (48.0) (14.86)/bbl (0.3) (0.10)/bbl ---------- ---------- Total Cash losses $ (64.0) $(7.03)/BOE $ (1.1) $(0.15)/BOE Non-cash (losses)/gains on financial contracts: Change in fair value - natural gas $ (39.7) $(1.21)/Mcf $ 25.4 $1.05/Mcf Change in fair value - crude oil (121.3) (37.56)/bbl (6.3) (2.03)/bbl ---------- ---------- Total non-cash (losses)/gains $ (161.0) $(17.65)/BOE $ 19.1 $2.54/BOE ---------- ---------- Total (losses)/gains $ (225.0) $(24.68)/BOE $ 18.0 $2.39/BOE ------------------------------------------------------------------------- ------------------------------------------------------------------------- Risk Management Costs Six months ended Six months ended ($ millions, except June 30, June 30, per unit amounts) 2008 2007 ------------------------------------------------------------------------- Cash (losses)/gains: Natural gas $ (11.8) $(0.19)/Mcf $ (1.3) $(0.03)/Mcf Crude oil (63.2) (10.10)/bbl 8.1 1.28/bbl ---------- ---------- Total Cash (losses)/gains $ (75.0) $(4.35)/BOE $ 6.8 $0.45/BOE Non-cash (losses)/ gains on financial contracts: Change in fair value - natural gas $ (98.0) $(1.61)/Mcf $ 4.8 $0.10/Mcf Change in fair value - crude oil (142.4) (22.77)/bbl (19.2) (3.04)/bbl ---------- ---------- Total non-cash losses $ (240.4) $(13.95)/BOE $ (14.4) $(0.95)/BOE ---------- ---------- Total losses $ (315.4) $(18.30)/BOE $ (7.6) $(0.50)/BOE ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash Flow Sensitivity The sensitivities below reflect the estimated impact on cash flow per trust unit for the remaining two quarters of 2008 and include the commodity contracts described in Note 9 as well as the impact of 2008 forward market prices as at July 25, 2008. To the extent the market price of crude oil and natural gas change significantly from the July 25, 2008 levels, the sensitivities will no longer be relevant as the effect of our commodity contracts will change. Estimated Effect on 2008 Sensitivity Table Cash Flow per Trust Unit(1) ------------------------------------------------------------------------- Change of $0.15 per Mcf in the price of AECO natural gas $0.03 Change of US$1.00 per barrel in the price of WTI crude oil $0.02 Change of 1,000 BOE/day in production $0.07 Change of $0.01 in the US$/CDN$ exchange rate $0.06 Change of 1% in interest rate $0.03 ------------------------------------------------------------------------- (1) Assumes constant working capital and 164,709,000 units outstanding. The impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the impact of any inter-relationship among the factors. Revenues Crude oil and natural gas revenues were higher during the second quarter of 2008 compared to the first quarter of 2008 due to an increase in commodity prices and a full quarter of production from the Focus assets. Crude oil and natural gas revenues for the three months ended June 30, 2008 were $734.4 million ($741.5 million, net of $7.1 million transportation) compared to $382.5 million ($387.9 million, net of $5.4 million transportation) for the same period in 2007. For the six months ended June 30, 2008 revenues were $1,238.1 million ($1,251.5 million, net of $13.4 million transportation) compared to $762.5 million ($773.8 million, net of $11.3 million transportation) during the same period in 2007. The majority of the increase in revenues of $351.9 million or 92% and $475.6 million or 62% for the three and six months ended June 30, 2008 compared to the same period in 2007 was due to higher commodity prices. The following table summarizes the changes in sales revenue: Analysis of Sales Revenue(1) ($ millions) Crude Oil NGLs Natural Gas Total ------------------------------------------------------------------------- Quarter ended June 30, 2007 $ 192.6 $ 20.1 $ 169.8 $ 382.5 Price variance(1) 168.3 12.0 96.4 276.7 Volume variance 7.4 3.3 64.5 75.2 ------------------------------------------------------------------------- Quarter ended June 30, 2008 $ 368.3 $ 35.4 $ 330.7 $ 734.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- ($ millions) Crude Oil NGLs Natural Gas Total ------------------------------------------------------------------------- Year-to-date ended June 30, 2007 $ 375.9 $ 38.0 $ 348.6 $ 762.5 Price variance(1) 256.0 23.0 106.8 385.8 Volume variance (3.3) 3.6 89.5 89.8 ------------------------------------------------------------------------- Year-to-date ended June 30, 2008 $ 628.6 $ 64.6 $ 544.9 $ 1,238.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. Other Income Other income for the three and six months ended June 30, 2008 was $0.4 million and $15.5 million respectively, compared to $0.3 million and $14.4 million for the same periods in 2007. Included in the first six months of 2008 was a gain of $8.3 million on the sale of certain marketable securities, as well as interim payments for our business interruption insurance of $6.4 million related to the Giltedge fire. During the first quarter of 2007 we realized a gain of $14.1 million on the sale of certain marketable securities. Royalties Royalties are paid to various government entities and other land and mineral rights owners. For the three and six months ended June 30, 2008 royalties were $138.0 million and $231.9 million respectively, both approximately 19% of oil and gas sales net of transportation. For the three and six months ended June 30, 2007 royalties were $72.2 million and $143.8 million, both approximately 19% of oil and gas sales net of transportation respectively. Increases in royalties for the three and six months ended June 30, 2008 of $65.8 million and $88.1 million respectively, compared to the same periods in 2007 were the result of higher commodity prices and increased production. We continue to expect royalties to be approximately 19% of oil and gas sales net of transportation during 2008. In October 2007 the Alberta government announced a 'New Royalty Framework' ("NRF") which will be effective January 1, 2009 and is expected to increase our royalties as a percentage of oil and gas sales. In the context of an annualized forward market of $130.00/bbl crude oil and $10.00/Mcf natural gas, and relative to Enerplus' current properties and production profile, we estimate the NRF will result in an average 2009 royalty rate for the Fund of approximately 26% of oil and gas sales, net of transportation costs. As at the date of this MD&A the Alberta government had not yet made the necessary legislative and administrative 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 the second quarter of 2008 were $9.43/BOE or 6% higher than the first quarter of 2008. This increase can be attributed to additional service rig activity related to optimization work on our U.S. properties. Operating expenses for the three months ended June 30, 2008 were $86.0 million or $9.43/BOE compared to $72.8 million or $9.69/BOE for the second quarter of 2007. For the six months ended June 30, 2008 operating costs were $158.0 million or $9.17/BOE compared to $138.8 million or $9.10/BOE for the same period in 2007. Operating expenses are generally in-line with our expectations however we have experienced a slight increase in costs for fuel and supplies which can be attributed to higher oil prices. In addition, we are continuing to spend more on optimization efforts on our U.S. properties which has resulted in increased production. As a result of the increased costs to date we are raising our annual guidance for operating costs from $8.65/BOE to $9.00/BOE. General and Administrative Expenses ("G&A") During the second quarter of 2008 G&A expenses decreased 6% per BOE to $1.90/BOE compared to $2.03/BOE for the first quarter of 2008. G&A expenses for the three months ended June 30, 2008 were $17.3 million or $1.90/BOE compared to $16.7 million or $2.22/BOE for the second quarter of 2007. G&A expenses totaled $33.8 million or $1.96/BOE for the six months ended June 30, 2008 compared to $33.8 million or $2.21/BOE for the same period in 2007. G&A expenses remained relatively unchanged year-over-year however the reduction on a $/BOE basis compared to 2007 is primarily due to the additional volumes associated with the Focus acquisition. For the three and six months ended June 30, 2008 our G&A expenses included non-cash charges of $2.1 million or $0.23/BOE and $3.6 million or $0.21/BOE respectively, compared to $2.1 million or $0.28/BOE and $4.2 million or $0.28/BOE for the same periods in 2007. These amounts relate solely to our trust unit rights incentive plan and are determined using a binomial lattice option-pricing model. See Note 8 for further details. The following table summarizes the cash and non-cash expenses recorded in G&A: General and Administrative Costs Three months ended June 30, Six months ended June 30, ($ millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- Cash $ 15.2 $ 14.6 $ 30.2 $ 29.6 Trust unit rights incentive plan (non-cash) 2.1 2.1 3.6 4.2 ------------------------------------------------------------------------- Total G&A $ 17.3 $ 16.7 $ 33.8 $ 33.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (Per BOE) 2008 2007 2008 2007 ------------------------------------------------------------------------- Cash $ 1.67 $ 1.94 $ 1.75 $ 1.93 Trust unit rights incentive plan (non-cash) 0.23 0.28 0.21 0.28 ------------------------------------------------------------------------- Total G&A $ 1.90 $ 2.22 $ 1.96 $ 2.21 ------------------------------------------------------------------------- ------------------------------------------------------------------------- We are maintaining our guidance for G&A expenses at $2.20/BOE, which includes non-cash G&A costs of approximately $0.20/BOE. Interest Expense Interest expense includes interest on long-term debt, the premium amortization on our US$175 million senior unsecured notes, unrealized gains and losses resulting from the change in fair value of our interest rate swaps as well as the interest component on our cross currency interest rate swap ("CCIRS"). See Note 6 for further details. Interest on long-term debt excluding non-cash charges totaled $12.9 million and $26.2 million for the three and six months ended June 30, 2008, compared to $9.7 million and $19.5 million respectively for the same periods in 2007. The increases in 2008 are due to higher average outstanding indebtedness as a result of the Focus acquisition, partially offset by lower interest rates. Non-cash interest charges totaled $6.4 million and nil for the three and six months ended June 30, 2008, compared to $2.1 million and $0.5 million respectively for the same periods in 2007. The changes in the fair value of our interest rate swaps and CCIRS that result from movements in forward market interest rates cause non-cash interest to fluctuate between periods. The following table summarizes the cash and non-cash interest expense recorded: Interest Expense Three months ended June 30, Six months ended June 30, ($ millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- Interest on long-term debt $ 12.9 $ 9.7 $ 26.3 $ 19.5 Non-cash interest loss 6.4 2.1 - 0.5 ------------------------------------------------------------------------- Total Interest Expense $ 19.3 $ 11.8 $ 26.3 $ 20.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- At June 30, 2008 approximately 15% of our debt was based on fixed interest rates while 85% had floating interest rates. In comparison, at June 30, 2007 approximately 20% of our debt was based on fixed interest rates and 80% was floating. Capital Expenditures During the three and six months ended June 30, 2008 we spent $88.0 million and $214.3 million on capital development respectively, compared to $80.4 million and $190.4 million during the same periods in 2007. The increase experienced during 2008 is largely due to drilling activities associated with our shallow gas properties and additional activity on our Focus assets. To date we have achieved a 100% success rate with our drilling program on 197 net wells. Corporate acquisitions for the six months ending June 30, 2008 totaled approximately $1.7 billion and relate to the Focus acquisition which closed February 13, 2008. Refer to Note 4 for further details. Property acquisitions for the three and six months ended June 30, 2008 totaled $1.8 million and $9.3 million respectively, compared to $204.0 million and $267.4 million for the same periods in 2007. Property acquisitions in 2007 included the purchase of our Jonah and Kirby assets in the first and second quarter of 2007 respectively. Total net capital expenditures for 2008 and 2007 are outlined below: Capital Expenditures Three months ended June 30, Six months ended June 30, ($ millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- Development expenditures $ 56.0 $ 69.4 $ 165.3 $ 160.2 Plant and facilities 32.0 11.0 49.0 30.2 ------------------------------------------------------------------------- Development Capital 88.0 80.4 214.3 190.4 Office 2.0 1.6 3.6 3.0 ------------------------------------------------------------------------- Sub-total 90.0 82.0 217.9 193.4 Property acquisitions(1) 1.8 204.0 9.3 267.4 Corporate acquisitions - - 1,757.5 - Property dispositions(1) (0.1) (5.5) (2.2) (5.5) ------------------------------------------------------------------------- Total Net Capital Expenditures $ 91.7 $ 280.5 $ 1,982.5 $ 455.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capital Expenditures financed with cash flow $ 91.7 $ 74.9 $ 226.0 $ 110.4 Capital Expenditures financed with debt and equity - 205.6 1,756.5 344.9 ------------------------------------------------------------------------- Total Net Capital Expenditures $ 91.7 $ 280.5 $ 1,982.5 $ 455.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net of post-closing adjustments. Our year-to-date development capital spending is slightly behind schedule and although we disposed of our interest in Joslyn subsequent to the quarter end, we are maintaining our 2008 guidance of $580 million. Approximately $40 million of planned spending for Joslyn will be redirected to conventional development capital spending during the remainder of the year. Due to the timing of these additional conventional capital expenditures we are not expecting a significant impact to 2008 production volumes. Oil Sands Our oil sands development projects have not commenced commercial production. As a result all associated costs inclusive of acquisition expenditures, development capital spending, salaries and benefits, engineering and planning, net of revenues generated, are capitalized and excluded from our depletion calculation. At June 30, 2008 capitalized costs life-to-date for Joslyn including other minor interests were $121.2 million and for Kirby were $229.9 million for a combined total of $351.1 million. During the second quarter of 2008 we capitalized costs of $3.9 million associated with advancing our regulatory application for our Kirby project. On July 31, 2008 we disposed of our interest in Joslyn for total cash consideration of approximately $500 million. Proceeds from the disposition have been used to pay down debt, improving our debt-to-cash flow ratio which reinforces our borrowing capacity, supports our ability to fund future development capital and acquisition activities and minimizes the need to issue additional equity. We continue to hold an interest in Laricina Energy Ltd., a private company with significant resources in the Alberta oil sands. This interest represents approximately 12% of the outstanding equity. Depletion, Depreciation, Amortization and Accretion ("DDA&A") DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the three months ended June 30, 2008, DDA&A increased to $18.93/BOE compared to $15.58/BOE during the corresponding period in 2007. For the six months ended June 30, 2008 DDA&A increased to $18.12/BOE compared to $15.48/BOE during the corresponding period in 2007. The increase is primarily due to additional PP&E and production as a result of the Focus acquisition. No impairment of the Fund's assets existed at June 30, 2008 using year-end reserves updated for acquisitions, divestitures and management's estimates of future prices. Asset Retirement Obligations In connection with our operations, we anticipate we will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. Total future asset retirement obligations are estimated by management based on the Fund's net ownership interest in wells and facilities, estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods and such obligations are included on the Fund's balance sheet. The Fund has estimated the net present value of its total asset retirement obligations to be approximately $203.4 million at June 30, 2008 compared to $165.7 million at December 31, 2007. The increase of $37.7 million relates primarily to the acquisition of Focus. See Note 3. The following chart compares the amortization of the asset retirement cost, accretion of the asset retirement obligation and asset retirement obligations settled during the period: Three months ended June 30, Six months ended June 30, ($ millions) 2008 2007 2008 2007 ------------------------------------------------------------------------- Amortization of the asset retirement cost $ 5.1 $ 3.3 $ 9.8 $ 6.7 Accretion of the asset retirement obligation 3.1 1.6 5.6 3.3 ------------------------------------------------------------------------- Total Amortization and Accretion $ 8.2 $ 4.9 $ 15.4 $ 10.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Asset Retirement Obligations Settled $ 4.8 $ 3.8 $ 8.8 $ 7.1 ------------------------------------------------------------------------- The timing of actual asset retirement costs will differ from the timing of amortization and accretion charges. Actual asset retirement costs will be incurred over the next 66 years with the majority between 2038 and 2047. For accounting purposes, the asset retirement cost is amortized using a unit-of-production method based on proved reserves before royalties while the asset retirement obligation accretes until the time the obligation is settled. Taxes Future Income Taxes Future income taxes arise from differences between the accounting and tax bases of assets and liabilities. A portion of the future income tax liability that is recorded on the balance sheet will be recovered through earnings before 2011. The balance will be realized when future income tax assets and liabilities are realized or settled. Our future income tax recovery was $50.4 million for the quarter ended June 30, 2008 compared to an expense of $71.0 million for the same period in 2007. During the second quarter of 2007, the Canadian Federal Government enacted the new specified investment flow through ("SIFT") tax on publicly traded income trusts effective January 1, 2011 which resulted in a one-time future income tax expense of $78.1 million. After consideration of the SIFT tax, the increased recovery in 2008 is due to higher income at the trust level and the recording of a future tax asset relating to a previously unrecognized tax pool. Subsequent to June 30, 2008, the Department of Finance issued draft amendments to the Income Tax Regulations regarding the provincial tax rate for SIFT entities. These amendments are generally designed to tax SIFT entities at the same level as a corporation and are expected to be enacted later in 2008. The amendments were not considered substantively enacted at June 30, 2008. As a result there was no consequential impact on future income taxes in the second quarter however this will result in a future income tax recovery when enacted. On July 14, 2008, the Department of Finance released draft legislative proposals which included proposed amendments which would allow a SIFT to convert into a corporation on a tax efficient basis without adverse Canadian tax consequences for the trust or its Canadian unitholders. We believe that the trust conversion under the proposed rules would qualify as a U.S. tax deferred transaction for our U.S. unitholders as well. The Canadian Department of Finance is accepting comments on these proposals until September 15, 2008 and intends to introduce the amendments into Parliament later this year. We are currently reviewing the legislative proposals to determine the impact to Enerplus should we eventually decide to convert into a corporation. Current Income Taxes In our current structure payments are made between the operating entities and the Fund, which ultimately transfers both the income and future tax liability to our unitholders. As a result no cash income taxes have been paid by our Canadian operating entities. However an income tax liability of $24.3 million was triggered on the acquisition of Focus on February 13, 2008. This liability was included in Focus' assumed working capital and was paid in April 2008. We expect to recover these taxes over the next twelve months and as such we have recorded a cash income tax recovery of $7.9 million for six months ended June 30, 2008. The amount of current taxes recorded in the year with respect to our U.S. operations is dependent upon income levels, and the timing of both capital expenditures and the repatriation of funds to Canada. For the three and six months ended June 30, 2008 our U.S. operations incurred taxes (income and withholding) in the amount of $21.5 million and $34.0 million respectively, compared to $3.2 and $5.3 million during the same periods in 2007. The increase in current taxes was due to an increase in net income combined with a decrease in capital expenditures in 2008. We expect our U.S. current income and withholding taxes to average approximately 25% of cash flow from U.S. operations based on current commodity prices, our current development capital program and assuming excess funds are repatriated to Canada. Net Income Net income for the second quarter of 2008 was $112.2 million or $0.68 per trust unit compared to $40.1 million or $0.31 per trust unit in the same period for 2007. Net income for the six months ended June 30, 2008 was $233.6 million or $1.50 per trust unit compared to $148.0 million or $1.18 per trust unit for the same period in 2007. The $85.6 million increase in net income for the six months ended was primarily due to an increase in oil and gas sales of $477.7 million which was offset by an increase in royalties of $88.1 million and an increase in commodity derivative instrument losses of $307.7 million. Cash Flow from Operating Activities Cash flow for the three and six months ended June 30, 2008 was $364.5 million ($2.22 per trust unit) and $620.7 million ($3.98 per trust unit) respectively, compared to $237.5 million ($1.85 per trust unit) and $430.7 million ($3.42 per trust unit) for the three and six months ended June 30, 2007. The increases per trust unit were primarily a result of strong commodity prices combined with an increase in production due to the Focus acquisition. Selected Financial Results Three months ended June 30, Three months ended June 30, 2008 2007 Per BOE of Operating Non-Cash Operating Non-Cash production Cash & Other Cash & Other (6:1) Flow(1) Items Total Flow(1) Items Total ------------------------------------------------------------------------- Production per day 100,188 82,478 ------------------------------------------------------------------------- Weighted average sales price(2) $ 80.56 $ - $ 80.56 $ 50.96 $ - $ 50.96 Royalties (15.14) - (15.14) (9.63) - (9.63) Commodity derivative instruments (7.03) (17.65) (24.68) (0.15) 2.54 2.39 Operating costs (9.43) - (9.43) (9.80) 0.11 (9.69) General and administrative (1.67) (0.23) (1.90) (1.94) (0.28) (2.22) Interest expense, net of other income (1.37) (0.70) (2.07) (1.25) (0.29) (1.54) Foreign exchange gain/(loss) 0.05 0.10 0.15 (0.11) 0.64 0.53 Current income tax (1.78) - (1.78) (0.43) - (0.43) Restoration and abandonment cash costs (0.52) 0.52 - (0.51) 0.51 - Depletion, depreciation, amortization and accretion - (18.93) (18.93) - (15.58) (15.58) Future income tax recovery/ (expense) - 5.53 5.53 - (9.45) (9.45) ------------------------------------------------------------------------- Total per BOE $ 43.67 $(31.36) $ 12.31 $ 27.14 $(21.80) $ 5.34 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Cash Flow from Operating Activities before changes in non-cash working capital. (2) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. Six months ended June 30, Six months ended June 30, 2008 2007 Per BOE of Operating Non-Cash Operating Non-Cash production Cash & Other Cash & Other (6:1) Flow(1) Items Total Flow(1) Items Total ------------------------------------------------------------------------- Production per day 94,681 84,244 ------------------------------------------------------------------------- Weighted average sales price(2) $ 71.85 $ - $ 71.85 $ 50.00 $ - $ 50.00 Royalties (13.46) - (13.46) (9.43) - (9.43) Commodity derivative instruments (4.35) (13.95) (18.30) 0.45 (0.95) (0.50) Operating costs (9.21) 0.04 (9.17) (9.16) 0.06 (9.10) General and administrative (1.75) (0.21) (1.96) (1.93) (0.28) (2.21) Interest expense, net of other income (1.10) (0.01) (1.11) (1.25) (0.03) (1.28) Foreign exchange (loss)/gain - (0.13) (0.13) (0.09) 0.32 0.23 Current income tax (1.49) - (1.49) (0.35) - (0.35) Restoration and abandonment cash costs (0.51) 0.51 - (0.48) 0.48 - Depletion, depreciation, amortization and accretion - (18.12) (18.12) - (15.48) (15.48) Future income tax recovery/ (expense) - 4.97 4.97 - (3.10) (3.10) Gain on sale of marketable securities(3) - 0.48 0.48 - 0.92 0.92 ------------------------------------------------------------------------- Total per BOE $ 39.98 $(26.42) $ 13.56 $ 27.76 $(18.06) $ 9.70 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Cash Flow from Operating Activities before changes in non-cash working capital. (2) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. (3) Gain on sale of marketable securities was a cash item however it is included in cash flow from investing activities not cash flow from operating activities. Selected Canadian and U.S. Results The following tables provide a geographical analysis of key operating and financial results for the three and six months ended June 30, 2008 and 2007. (CDN$ millions, Three months ended Three months ended except per unit June 30, 2008 June 30, 2007 amounts) Canada U.S. Total Canada U.S. Total ------------------------------------------------------------------------- Daily Production Volumes Natural gas (Mcf/day) 346,554 12,795 359,349 254,122 10,824 264,946 Crude oil (bbls/day) 25,652 9,834 35,486 24,563 9,615 34,178 Natural gas liquids (bbls/day) 4,810 - 4,810 4,143 - 4,143 Total Daily Sales (BOE/day) 88,221 11,967 100,188 71,059 11,419 82,478 Pricing(1) Natural gas (per Mcf) $ 9.80 $ 11.80 $ 9.87 $ 7.03 $ 7.37 $ 7.04 Crude oil (per bbl) 112.41 118.27 114.04 59.59 67.94 61.93 Natural gas liquids (per bbl) 80.55 - 80.55 53.34 - 53.34 Capital Expenditures Development capital and office $ 76.5 $ 13.5 $ 90.0 $ 49.1 $ 32.9 $ 82.0 Acquisitions of oil and gas properties 2.0 (0.2) 1.8 204.5 (0.5) 204.0 Dispositions of oil and gas properties (0.1) - (0.1) (5.5) - (5.5) Revenues Oil and gas sales(1) $ 614.8 $ 119.6 $ 734.4 $ 315.8 $ 66.7 $ 382.5 Royalties(2) (112.4) (25.6) (138.0) (58.9) (13.3) (72.2) Financial contracts (225.0) - (225.0) 18.0 - 18.0 Expenses Operating $ 80.8 $ 5.2 $ 86.0 $ 70.6 $ 2.2 $ 72.8 General and admini- strative 16.0 1.3 17.3 14.9 1.8 16.7 Depletion, depreciation, amortization and accretion 149.6 22.9 172.5 89.5 27.4 116.9 Current income taxes (recovery)/ expense (5.3) 21.5 16.2 - 3.2 3.2 ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. (2) U.S. royalties include state production tax. (CDN$ millions, Six months ended Six months ended except per June 30, 2008 June 30, 2007 unit amounts) Canada U.S. Total Canada U.S. Total ------------------------------------------------------------------------- Daily Production Volumes Natural gas (Mcf/day) 321,177 12,382 333,559 260,051 10,249 270,300 Crude oil (bbls/day) 24,687 9,689 34,376 24,946 9,923 34,869 Natural gas liquids (bbls/day) 4,712 - 4,712 4,325 - 4,325 Total Daily Sales (BOE/day) 82,929 11,752 94,681 72,613 11,631 84,244 Pricing(1) Natural gas (per Mcf) $ 8.72 $ 10.42 $ 8.79 $ 7.12 $ 7.33 $ 7.13 Crude oil (per bbl) 98.89 104.50 100.47 57.24 65.41 59.56 Natural gas liquids (per bbl) 75.29 - 75.29 48.55 - 48.55 Capital Expenditures Development capital and office $ 184.8 $ 33.1 $ 217.9 $ 122.6 $ 70.8 $ 193.4 Acquisitions of oil and gas properties 9.4 (0.1) 9.3 206.6 60.8 267.4 Dispositions of oil and gas properties (2.2) - (2.2) (5.5) - (5.5) Revenues Oil and gas sales(1) $1,030.3 $ 207.8 $1,238.1 $ 631.4 $ 131.1 $ 762.5 Royalties(2) (187.4) (44.5) (231.9) (117.7) (26.1) (143.8) Financial contracts (315.4) - (315.4) (7.6) - (7.6) Expenses Operating $ 149.4 $ 8.6 $ 158.0 $ 134.5 $ 4.3 $ 138.8 General and admini- strative 31.1 2.7 33.8 29.7 4.1 33.8 Depletion, depreciation, amortization and accretion 268.0 44.3 312.3 181.0 55.0 236.0 Current income taxes (recovery)/ expense (7.9) 33.7 25.8 - 5.3 5.3 ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. (2) U.S. royalties include state production tax. Quarterly Financial Information Oil and gas sales were relatively flat for the first three quarters of 2006 but began to decrease in the fourth quarter 2006 through 2007 due to softening natural gas prices. During the first half of 2008 production and commodity prices were increasing resulting in additional oil and gas sales. Net income has been affected by additional production from the Focus acquisition, fluctuating commodity prices (both current and future), risk management costs, the strengthening Canadian dollar, higher operating costs, changes in future tax provisions as well as changes to accounting policies adopted during 2007. Net Income Quarterly Financial Information Oil per trust unit ($ millions, except per trust and Gas Net ------------------ unit amounts) Sales(1) Income Basic Diluted ------------------------------------------------------------------------- 2008 Second Quarter $ 734.4 $ 112.2 $ 0.68 $ 0.68 First quarter 503.7 121.4 0.82 0.82 ----------------------------------------------------- Total $1,238.1 $ 233.6 $ 1.50 $ 1.50 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2007 Fourth Quarter $ 389.8 $ 98.7 $ 0.76 $ 0.76 Third Quarter 364.8 93.0 0.72 0.72 Second Quarter 382.5 40.1 0.31 0.31 First quarter 380.0 107.9 0.88 0.87 ----------------------------------------------------- Total $1,517.1 $ 339.7 $ 2.66 $ 2.66 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2006 Fourth Quarter $ 369.5 $ 110.2 $ 0.90 $ 0.89 Third Quarter 398.0 161.3 1.31 1.31 Second Quarter 403.5 146.0 1.19 1.19 First Quarter 401.7 127.3 1.08 1.07 ----------------------------------------------------- Total $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. 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 harbour growth capacity within the context of the Government's "normal growth" guidelines for SIFT's. 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 anticipated 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, funding requirements for our development capital program and our access to equity markets. 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 the second quarter of 2008 cash distributions of $202.3 million were funded entirely through cash flow of $364.5 million. For the six months ended June 30, 2008 our cash distributions were $394.7 million and were funded entirely through cash flow of $620.7 million. Our payout ratio, which is calculated as cash distributions divided by cash flow, was 56% and 64% for the three and six months ended June 30, 2008 respectively, compared to 68% and 74% for the same periods in 2007. See "Non-GAAP Measures" in this MD&A. In aggregate, our 2008 second quarter cash distributions of $202.3 million combined with our development capital and office expenditures of $90.0 million totaled $292.3 million, or approximately 80% of our cash flow of $364.5 million. For the six month ended June 30, 2008 our cash distributions of $394.7 million combined with our development capital and office expenditures of $217.9 million totaled $612.6 million, or approximately 99% of our cash flow of $620.7 million. We expect to support our distributions and capital expenditures with our cash flow, however we will continue to fund acquisitions and growth through additional debt and equity when required. There will also be years when we are investing capital in opportunities that do not immediately generate cash flow (such as our Kirby oil sands project) where we may also use debt and equity to support the investment. For the three months ended June 30, 2008, our cash distributions exceeded our net income by $90.1 million (2007 - $122.5 million), however net income includes $290.6 million of non-cash items (2007 - $167.4 million). For the six months ended June 30, 2008 our cash distributions exceeded our net income by $161.1 million (2007 - $172.3 million) which included $472.3 million of non-cash items (2007 - $296.5 million). Non-cash items such as changes in the fair value of our derivative instruments and future income taxes do not reduce or increase our cash flow from operations. Future income taxes can fluctuate from period to period as a result of changes in tax rates as well as changes in interest, royalties and dividends from our operating subsidiaries paid to the Fund. In addition, other non-cash charges such as DDA&A are not a good proxy for the cost of maintaining our productive capacity as they are based on the historical costs of our PP&E and not the fair market value of replacing those assets within the context of the current environment. It is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities in the oil and gas sector due to the nature of reserve reporting, natural reservoir declines and the risks involved with capital investment. Therefore we do not distinguish maintenance capital separately from development capital spending. The level of investment in a given period may not be sufficient to replace productive capacity given the natural declines associated with oil and natural gas assets. In these instances a portion of the cash distributions paid to unitholders may represent a return of the unitholders' capital. The following table compares cash distributions to cash flow and net income: Three months Six months Year ended Year ended ($ millions, except ended June ended June December December per unit amounts) 30, 2008 30, 2008 31, 2007 31, 2006 ------------------------------------------------------------------------- Cash flow from operating activities $ 364.5 $ 620.7 $ 868.5 $ 863.7 Cash distributions 202.3 394.7 646.8 614.3 ------------------------------------------------------------------------- Excess of cash flow over cash distributions $ 162.2 $ 226.0 $ 221.7 $ 249.4 Net income $ 112.2 $ 233.6 $ 339.7 $ 544.8 Shortfall of net income over cash distributions (90.1) (161.1) (307.1) (69.5) Cash distributions per weighted average trust unit $ 1.23 $ 2.53 $ 5.07 $ 5.05 Payout ratio(1) 56% 64% 74% 71% ------------------------------------------------------------------------- (1) Based on cash distributions divided by cash flow from operating activities. See "Non-GAAP Measures" in this MD&A. Long-Term Debt Long-term debt at June 30, 2008 was $1,028.3 million which is comprised of $792.2 million of bank indebtedness and $236.1 million of senior unsecured notes. The increase in long-term debt compared to December 31, 2007 of $301.6 million is mainly due to the $330.9 million of debt that was assumed on the Focus acquisition. We reduced long term debt by $68.7 million during the second quarter of 2008 with excess cash flow. Our working capital deficiency, excluding cash, at June 30, 2008 increased $106.9 million to $310.3 million from $203.4 million at December 31, 2007. Excluding current deferred financial assets and credits and the related current future income taxes, our working capital deficiency decreased by $63.5 million compared to December 31, 2007. This decrease is primarily due to higher accounts receivable attributable to higher commodity prices and production levels. We continue to maintain a conservative balance sheet as demonstrated below: June December Financial Leverage and Coverage 30, 2008 31, 2007 ------------------------------------------------------------------------- Long-term debt to trailing cash flow 0.9x 0.8x Cash flow to interest expense 20.6x 25.8x Long-term debt to long-term debt plus equity 21% 22% ------------------------------------------------------------------------- Long-term debt is measured net of cash. Cash flow and interest expense are 12-months trailing. After applying the proceeds of approximately $500 million from the sale of our Joslyn interest to our debt, we anticipate our debt to cash flow ratio will be 0.4 times. At June 30, 2008 Enerplus had a $1.4 billion 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 June 30, 2008 we were in compliance with our debt covenants, the most restrictive of which limits our long-term debt to three times trailing cash flow including acquisition cash flows. Refer to "Debt of Enerplus" in our Annual Information Form for the year ended December 31, 2007 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 5. We 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, if needed. Trust Unit Information We had 164,709,000 trust units outstanding at June 30, 2008. This includes the 30,150,000 units issued on February 13, 2008 to acquire Focus and 7,885,000 exchangeable limited partnership units of Enerplus Exchangeable Limited Partnership outstanding from the original 9,087,000 exchangeable limited partnership units which were assumed with the Focus acquisition. The remaining 7,885,000 exchangeable limited partnership units are convertible at the option of the holder into 0.425 of an Enerplus trust unit (3,351,000 trust units). This compares to 129,205,000 trust units at June 30, 2007 and 129,813,000 trust units outstanding at December 31, 2007. Including the exchangeable limited partnership units the weighted average basic number of trust units outstanding for the six months ended June 30, 2008 was 155,984,000 (2007 - 125,849,000). At July 31, 2008 we had 164,807,000 trust units outstanding including the equivalent limited partnership units. During the three months ended June 30, 2008, 683,000 trust units (2007 - 416,000) 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 $28.8 million (2007 - $18.6 million) of additional equity to the Fund. For the six months ended June 30, 2008 $40.7 million of additional equity (2007 - $31.7 million) and 1,000,000 trust units (2007 - 699,000) were issued pursuant to the DRIP and the trust unit options and rights plans. For further details see Note 8. Canadian and U.S. Taxpayers Enerplus currently estimates that approximately 95% of cash distributions paid to Canadian and U.S unitholders will be taxable and the remaining 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. 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. Draft U.S. Tax Bill 1672, which proposes to make dividends from Canadian income trusts such as Enerplus ineligible for treatment as a "Qualified Dividend", has not progressed in the U.S. approval process. Therefore, we still cannot determine when or even if Bill 1672 will be enacted as presented. In July 2008, Enerplus estimated its non-resident ownership to be approximately 64%. Greenhouse Gas and Carbon Emissions Enerplus continues to monitor and evaluate the developments associated with carbon emissions regulations associated with environmental policy and legislation in all jurisdictions where we operate. In particular, we are currently reviewing the Government of Canada's "Turning the Corner" plan. Given Enerplus' interest in various oil sands development areas we will be closely monitoring the development of these proposed federal regulations. We will be working with government at all levels where we have operations to assist in the development of regulatory design in an effort to strike a productive balance between environmental responsibility and continued positive economic impact. At this stage, without further clarity and specific details from the government of Canada, it is very difficult to forecast the increased costs associated with the proposed greenhouse gas and carbon capture regulations. 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. INTERNAL CONTROLS AND PROCEDURES There were no changes in our internal control over financial reporting during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. CONSOLIDATED BALANCE SHEETS June 30, December 31, (CDN$ thousands) (Unaudited) 2008 2007 ------------------------------------------------------------------------- Assets Current assets Cash $ 723 $ 1,702 Accounts receivable 242,999 145,602 Deferred financial assets (Note 9) 1,122 10,157 Future income taxes 86,140 10,807 Other current 7,336 6,373 ------------------------------------------------------------------------- 338,320 174,641 Property, plant and equipment (Note 2) 5,570,402 3,872,818 Goodwill (Note 4) 603,255 195,112 Other assets (Note 9) 50,216 60,559 ------------------------------------------------------------------------- $ 6,562,193 $ 4,303,130 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities Current liabilities Accounts payable $ 289,576 $ 269,375 Distributions payable to unitholders 69,180 54,522 Deferred financial credits (Note 9) 289,100 52,488 ------------------------------------------------------------------------- 647,856 376,385 ------------------------------------------------------------------------- Long-term debt (Note 5) 1,028,301 726,677 Deferred financial credits (Note 9) 85,621 90,090 Future income taxes 697,065 304,259 Asset retirement obligations (Note 3) 203,411 165,719 ------------------------------------------------------------------------- 2,014,398 1,286,745 ------------------------------------------------------------------------- Equity Unitholders' capital (Note 8) 5,438,100 4,032,680 Accumulated deficit (1,445,033) (1,283,953) Accumulated other comprehensive income (93,128) (108,727) ------------------------------------------------------------------------- (1,538,161) (1,392,680) 3,899,939 2,640,000 ------------------------------------------------------------------------- $ 6,562,193 $ 4,303,130 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT Three months ended Six months ended (CDN$ thousands) June 30, June 30, (Unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Accumulated income, beginning of period $ 2,408,321 $ 2,055,109 $ 2,286,927 $ 1,952,960 Adjustment for adoption of financial instruments standards - - - (5,724) ------------------------------------------------------------------------- Revised accumulated income, beginning of period 2,408,321 2,055,109 2,286,927 1,947,236 Net income 112,230 40,084 233,624 147,957 ------------------------------------------------------------------------- Accumulated income, end of period $ 2,520,551 $ 2,095,193 $ 2,520,551 $ 2,095,193 Accumulated cash distributions, beginning of period $(3,763,238) $(3,081,716) $(3,570,880) $(2,924,045) Cash distributions (202,346) (162,607) (394,704) (320,278) ------------------------------------------------------------------------- Accumulated cash distributions, end of period $(3,965,584) $(3,244,323) $(3,965,584) $(3,244,323) ------------------------------------------------------------------------- Accumulated deficit, end of period $(1,445,033) $(1,149,130) $(1,445,033) $(1,149,130) ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (CDN$ thousands) Three months ended June 30, Six months ended June 30, (Unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Balance, beginning of period $ (87,505) $ (15,525) $ (108,727) $ (8,979) Transition adjustments on adoption: Cash flow hedges - - - 660 Available for sale marketable securities - - - 14,252 Other comprehensive (loss)/income (5,623) (49,853) 15,599 (71,311) ------------------------------------------------------------------------- Balance, end of period $ (93,128) $ (65,378) $ (93,128) $ (65,378) ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME (CDN$ thousands except Three months ended Six months ended per trust unit amounts) June 30, June 30, (Unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues Oil and gas sales $ 741,470 $ 387,926 $ 1,251,539 $ 773,797 Royalties (138,040) (72,214) (231,876) (143,762) Commodity derivative instruments (Note 9) (225,015) 17,954 (315,394) (7,652) Other income 411 272 15,527 14,432 ------------------------------------------------------------------------- 378,826 333,938 719,796 636,815 ------------------------------------------------------------------------- Expenses Operating 85,974 72,756 157,990 138,786 General and administrative 17,327 16,660 33,764 33,770 Transportation 7,127 5,453 13,444 11,317 Interest (Note 6) 19,313 11,847 26,301 19,962 Foreign exchange (Note 7) (1,408) (3,956) 2,276 (3,474) Depletion, depreciation, amortization and accretion 172,496 116,909 312,290 236,000 ------------------------------------------------------------------------- 300,829 219,669 546,065 436,361 ------------------------------------------------------------------------- Income before taxes 77,997 114,269 173,731 200,454 Current taxes 16,211 3,227 25,752 5,291 Future income tax (recovery)/expense (50,444) 70,958 (85,645) 47,206 ------------------------------------------------------------------------- Net Income $ 112,230 $ 40,084 $ 233,624 $ 147,957 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per trust unit Basic $ 0.68 $ 0.31 $ 1.50 $ 1.18 Diluted $ 0.68 $ 0.31 $ 1.50 $ 1.18 ------------------------------------------------------------------------- Weighted average number of trust units outstanding (thousands)(1) Basic 164,483 128,361 155,984 125,849 Diluted 164,633 128,419 156,102 125,904 ------------------------------------------------------------------------- (1) Includes the exchangeable limited partnership units. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (CDN$ thousands) Three months ended June 30, Six months ended June 30, (Unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Net income $ 112,230 $ 40,084 $ 223,624 $ 147,957 ------------------------------------------------------------------------- Other comprehensive income/(loss), net of tax: Unrealized gain/(loss) on marketable securities - 2,502 2,578 (654) Realized gains on marketable securities included in net income - - (6,158) (11,654) Gains and losses on derivatives designated as hedges in prior periods included in net income - (176) 74 (380) Change in cumulative translation adjustment (5,623) (52,179) 19,105 (58,623) ------------------------------------------------------------------------- Other comprehensive income/(loss) (5,623) (49,853) 15,599 (71,311) ------------------------------------------------------------------------- Comprehensive income $ 106,607 $ (9,769) $ 239,223 $ 76,646 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOWS Three months ended Six months ended (CDN$ thousands) June 30, June 30, (Unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Operating Activities Net income $ 112,230 $ 40,084 $ 233,624 $ 147,957 Non-cash items add/ (deduct): Depletion, depreciation, amortization and accretion 172,496 116,909 312,290 236,000 Change in fair value of derivative instruments (Note 9) 168,787 (1,394) 235,259 33,453 Unit based compensation (Note 8) 2,094 2,107 3,580 4,218 Foreign exchange on translation of senior notes (Note 7) (2,158) (20,808) 7,075 (23,690) Future income tax (50,444) 70,958 (85,645) 47,206 Amortization of senior notes premium (157) (159) (310) (328) Reclassification adjustments from AOCI to net income - (176) 92 (380) Gain on sale of marketable securities - - (8,263) (14,055) Asset retirement obligations settled (Note 3) (4,747) (3,803) (8,767) (7,117) ------------------------------------------------------------------------- 398,101 203,718 688,935 423,264 (Increase)/Decrease in non-cash operating working capital (33,644) 33,764 (68,262) 7,399 ------------------------------------------------------------------------- Cash flow from operating activities 364,457 237,482 620,673 430,663 ------------------------------------------------------------------------- Financing Activities Issue of trust units, net of issue costs (Note 8) 28,811 218,204 40,696 231,224 Cash distributions to unitholders (202,346) (162,607) (394,704) (320,278) (Decrease)/Increase in bank credit facilities (68,656) (35,992) (36,054) 64,350 Decrease in non-cash financing working capital 241 180 14,658 2,549 ------------------------------------------------------------------------- Cash flow from financing activities (241,950) 19,785 (375,404) (22,155) ------------------------------------------------------------------------- Investing Activities Capital expenditures (89,961) (82,000) (217,884) (193,354) Property acquisitions (1,740) (149,266) (9,289) (212,644) Property dispositions 86 (1,107) 2,208 (1,152) Proceeds on sale of marketable securities - - 18,320 16,467 Increase in non-cash investing working capital (30,218) (20,627) (40,636) (14,497) ------------------------------------------------------------------------- Cash flow from investing activities (121,833) (253,000) (247,281) (405,180) ------------------------------------------------------------------------- Effect of exchange rate changes on cash (1,404) (2,311) 1,033 (1,402) ------------------------------------------------------------------------- Change in cash (730) 1,956 (979) 1,926 Cash, beginning of period 1,453 94 1,702 124 ------------------------------------------------------------------------- Cash, end of period $ 723 $ 2,050 $ 723 $ 2,050 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplementary Cash Flow Information Cash income taxes paid $ 24,756 $ 4,005 $ 33,758 $ 7,246 Cash interest paid $ 17,980 $ 14,644 $ 26,298 $ 20,730 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The interim consolidated financial statements of Enerplus Resources Fund ("Enerplus" or the "Fund") have been prepared by management following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2007. The note disclosure requirements for annual statements provide additional disclosure to that required for these interim statements. Accordingly, these interim statements should be read in conjunction with the Fund's consolidated financial statements for the year ended December 31, 2007. With the exception of additional disclosures included in Note 9 regarding financial instruments and capital management, the disclosures provided below are incremental to those included in the 2007 annual consolidated financial statements of the Fund. 2. PROPERTY, PLANT AND EQUIPMENT (PP&E) June 30, December 31, ($ thousands) 2008 2007 ------------------------------------------------------------------------- Property, plant and equipment $ 8,440,623 $ 6,429,241 Accumulated depletion, depreciation and accretion (2,870,221) (2,556,423) ------------------------------------------------------------------------- Net property, plant and equipment $ 5,570,402 $ 3,872,818 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capitalized development general and administrative ("G&A") expense of $10,812,000 (2007 - $8,158,000) is included in PP&E for the six months ended June 30, 2008. Excluded from PP&E for the depletion and depreciation calculation is $351,124,000 (2007 - $302,459,000) related to the Joslyn development project and the Kirby Oil Sands project, both of which have not yet commenced commercial production. 3. ASSET RETIREMENT OBLIGATIONS Following is a reconciliation of the asset retirement obligations: Six months Year ended ended June 30, December ($ thousands) 2008 31, 2007 ------------------------------------------------------------------------- Asset retirement obligations, beginning of period $ 165,719 $ 123,619 Corporate acquisition 36,784 - Changes in estimates 1,475 46,000 Property acquisition and development activity 2,667 6,441 Dispositions (110) (756) Asset retirement obligations settled (8,767) (16,280) Accretion expense 5,643 6,695 ------------------------------------------------------------------------- Asset retirement obligations, end of period $ 203,411 $ 165,719 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 4. ACQUISITIONS Focus Energy Trust On February 13, 2008 Enerplus closed the acquisition of Focus Energy Trust ("Focus"). Under the plan of arrangement, Focus unitholders received 0.425 of an Enerplus trust unit for each Focus trust unit and Focus Exchangeable Limited Partnership Units became exchangeable into Enerplus trust units at the option of the holder on the basis of 0.425 of an Enerplus trust unit for each Focus Exchangeable Limited Partnership Unit. Total consideration was approximately $1,366,494,000 consisting of 30,149,752 trust units issued, 9,086,666 exchangeable limited partnership units assumed (convertible into 3,861,833 trust units) and estimated transaction costs of $5,350,000. The Fund also assumed bank debt plus an estimated working capital deficit including certain transaction costs paid by Focus of $357,305,000. The acquisition has been accounted for using the purchase method of accounting and results from the operations of Focus from February 13, 2008 onward have been included in the Fund's consolidated financial statements. The allocation of the consideration paid to the fair value of the assets acquired and liabilities assumed plus future income tax cost are summarized below: Net Assets Acquired ($ thousands) ------------------------------------------------------------------------- Property, plant and equipment $ 1,757,520 Other assets 4,566 Goodwill 403,588 Working capital deficit (26,393) Deferred financial credits (5,919) Long-term debt (330,912) Asset retirement obligations (36,784) Future income taxes (399,172) ------------------------------------------------------------------------- Total net assets acquired $ 1,366,494 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Consideration paid ($ thousands) ------------------------------------------------------------------------- Trust units issued(1) $ 1,206,593 Exchangeable limited partnership units assumed(1) 154,551 Transaction costs 5,350 ------------------------------------------------------------------------- Total consideration paid $ 1,366,494 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Recorded based on a fair value of $40.02 per trust unit 5. LONG-TERM DEBT June 30, December 31, ($ thousands) 2008 2007 ------------------------------------------------------------------------- Bank credit facilities (a) $ 792,205 $ 497,347 Senior notes (b) US$175 million (issued June 19, 2002) 181,092 175,973 US$54 million (issued October 1, 2003) 55,004 53,357 ------------------------------------------------------------------------- Total long-term debt $ 1,028,301 $ 726,677 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (a) Unsecured Bank Credit Facility Enerplus currently has a $1.4 billion unsecured covenant based three-year term facility. The facility is extendible each year with a bullet payment required at the end of the three year term. Various borrowing options are available under the facility including prime rate based advances and bankers' acceptance loans. This facility carries floating interest rates that are expected 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. The effective interest rate on the facility for the six months ended June 30, 2008 was 4.0% (June 30, 2007 - 4.9 %). (b) Senior Unsecured Notes On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes that mature June 19, 2014. The notes have a coupon rate of 6.62% priced at par, with interest paid semi-annually on June 19 and December 19 of each year. Principal payments are required in five equal installments beginning June 19, 2010 and ending June 19, 2014. Concurrent with the issuance of the notes on June 19, 2002, the Fund entered into a cross currency and interest rate swap ("CCIRS") with a syndicate of financial institutions. Under the terms of the swap, the amount of the notes was fixed for purposes of interest and principal repayments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian bankers' acceptances, plus 1.18%. On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes that mature October 1, 2015. The notes have a coupon rate of 5.46% priced at par with interest paid semi-annually on April 1 and October 1 of each year. Principal payments are required in five equal installments beginning October 1, 2011 and ending October 1, 2015. The notes are translated into Canadian dollars using the period end foreign exchange rate. In September 2007 Enerplus entered into foreign exchange swaps that effectively fix the five principal payments on the US$54,000,000 senior unsecured notes at a CDN/US exchange rate of 1.02 or CDN$55,080,000. On January 1, 2007 in conjunction with the adoption of CICA Sections 3855 and 3865, Enerplus elected to stop designating the CCIRS as a fair value hedge on the US$175,000,000 senior notes. As a result, the Fund recorded the senior notes at their fair value of US$178,681,000. The premium amount of US$3,681,000, representing the difference between the January 1, 2007 fair value and the face amount of the senior notes, will be amortized to net income over the remaining term of the notes using the effective interest method. The effective interest rate over the remaining term of the senior notes is 6.16%. The senior notes are carried at amortized cost and are translated into Canadian dollars using the period end foreign exchange rate. At June 30, 2008 the amortized cost of the US$175,000,000 senior notes was US$177,785,000. 6. INTEREST EXPENSE Three months ended June 30, Six months ended June 30, ($ thousands) 2008 2007 2008 2007 ------------------------------------------------------------------------- Realized Interest on long-term debt $ 12,918 $ 9,731 $ 26,263 $ 19,481 Unrealized Loss/(gain) on cross currency interest rate swap 7,219 4,193 (1,125) 2,909 (Gain)/loss on interest rate swaps (667) (1,918) 1,473 (2,100) Amortization of the premium on senior unsecured notes (157) (159) (310) (328) ------------------------------------------------------------------------- Interest expense $ 19,313 $ 11,847 $ 26,301 $ 19,962 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. FOREIGN EXCHANGE Three months ended June 30, Six months ended June 30, ($ thousands) 2008 2007 2008 2007 ------------------------------------------------------------------------- Realized Foreign exchange (gain)/loss $ (550) $ 854 $ 18 $ 1,442 Unrealized Foreign exchange (gain)/loss on translation of U.S. dollar denominated senior notes (2,158) (20,808) 7,075 (23,690) Foreign exchange (gain)/loss on cross currency interest rate swap (320) 15,998 (4,491) 18,774 Foreign exchange loss/(gain) on foreign exchange swaps 1,620 - (326) - ------------------------------------------------------------------------- Foreign exchange (gain)/loss $ (1,408) $ (3,956) $ 2,276 $ (3,474) ------------------------------------------------------------------------- ------------------------------------------------------------------------- The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed to foreign currency fluctuations and are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included in the determination of net income for the period. 8. UNITHOLDERS' CAPITAL Unitholders' capital as presented on the Consolidated Balance Sheets consists of trust unit capital, exchangeable partnership unit capital and contributed surplus. Six months Year ended Unitholders' capital ended June December ($ thousands) 30, 2008 31, 2007 ------------------------------------------------------------------------- Trust units $ 5,286,045 $ 4,020,228 Exchangeable limited partnership units 134,106 - Contributed surplus 17,949 12,452 ------------------------------------------------------------------------- Balance, end of period $ 5,438,100 $ 4,032,680 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (a) Trust Units Authorized: Unlimited number of trust units Six months ended Year ended (thousands) June 30, 2008 December 31, 2007 Issued: Units Amount Units Amount ------------------------------------------------------------------------- Balance, beginning of period 129,813 $ 4,020,228 123,151 $ 3,706,821 Issued for cash: Pursuant to public offerings - - 4,250 199,558 Pursuant to rights incentive plan 174 5,755 205 6,758 Cancelled trust units (116) (3,794) - - Exchangeable limited partnership units exchanged 511 20,445 - - Trust unit rights incentive plan (non- cash) - exercised - 1,877 - 2,288 DRIP(*), net of redemptions 826 34,941 1,102 50,053 Issued for acquisition of corporate and property interests (non-cash) 30,150 1,206,593 1,105 54,750 ------------------------------------------------------------------------- 161,358 $ 5,286,045 129,813 $ 4,020,228 Equivalent exchangeable partnership units 3,351 134,106 - - ------------------------------------------------------------------------- Balance, end of period 164,709 $ 5,420,151 129,813 $ 4,020,228 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Distribution Reinvestment and Unit Purchase Plan On February 13, 2008 the Fund issued 30,149,752 trust units pursuant to the Focus acquisition valued at $40.02 per trust unit, being the weighted average trading price of the Fund's units on the Toronto Stock Exchange during the five day trading period surrounding the announcement date of December 3, 2007, for a recorded value of $1,206,593,000. (b) Exchangeable Limited Partnership Units In conjunction with the Focus acquisition 9,086,666 Exchangeable Limited Partnership Units issued by Focus Limited Partnership (since renamed Enerplus Exchangeable Limited Partnership) became exchangeable into Enerplus trust units at a ratio of 0.425 of an Enerplus trust unit for each Limited Partnership unit (3,861,833 trust units). The exchangeable limited partnership units are convertible at any time into trust units at the option of the holder and receive cash distributions and have voting rights in accordance with the 0.425 exchange ratio. The Board of Directors may redeem the exchangeable limited partnership units after January 8, 2017, unless certain conditions are met to permit an earlier redemption date. The exchangeable limited partnership units are not listed on any stock exchange and are not transferable. The exchangeable limited partnership units were recorded at fair value, based on the Enerplus' five day weighted average trust unit trading price surrounding the December 3, 2007 announcement date of $40.02 multiplied by the 0.425 exchange ratio. During the second quarter of 2008, 1,202,000 exchangeable limited partnership units were converted into 511,000 trust units. As at June 30, 2008, the 7,885,000 outstanding exchangeable limited partnership units represent the equivalent of 3,351,000 trust units. Six months ended Year ended (thousands) June 30, 2008 December 31, 2007 Issued: Units Amount Units Amount ------------------------------------------------------------------------- Assumed on February 13, 2008 9,087 $ 154,551 - $ - Exchanged for trust units (1,202) (20,445) - - ------------------------------------------------------------------------- Balance, end of period 7,885 $ 134,106 - $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (c) Contributed Surplus Six months Year ended ended June 30, December Contributed surplus ($ thousands) 2008 31, 2007 ------------------------------------------------------------------------- Balance, beginning of period $ 12,452 $ 6,305 Trust unit rights incentive plan (non-cash) - exercised (1,877) (2,288) Trust unit rights incentive plan (non-cash) - expensed 3,580 8,435 Cancelled trust units 3,794 - ------------------------------------------------------------------------- Balance, end of period $ 17,949 $ 12,452 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (d) Trust Unit Rights Incentive Plan As at June 30, 2008 a total of 4,324,000 rights were issued pursuant to the Trust Unit Rights Incentive Plan ("Rights Incentive Plan") with an average exercise price of $45.73 and were outstanding. This represents 2.6% of the total trust units outstanding of which 1,795,000 rights, with an average exercise price of $45.70, were exercisable. Under the Rights Incentive Plan, distributions per trust unit to Enerplus unitholders in a calendar quarter which represent a return of more than 2.5% of the net PP&E of Enerplus at the end of such calendar quarter may result in a reduction in the exercise price of the rights. Results for the first and second quarter of 2008 reduced the exercise price of the outstanding rights by $0.43 per trust unit effective July 2008 and $0.41 per trust unit effective October 2008. Activity for the rights issued pursuant to the Rights Plan is as follows: Six months ended Year ended June 30, 2008 December 31, 2007 ------------------------------------------------------------------------- Weighted Weighted Number of Average Number of Average Rights Exercise Rights Exercise (000's) Price(1) (000's) Price(1) ------------------------------------------------------------------------- Trust unit rights outstanding Beginning of period 3,404 $ 47.59 3,079 $ 48.53 Granted 1,348 42.34 816 48.71 Exercised (174) 33.01 (205) 32.90 Cancelled (254) 47.04 (286) 50.74 ------------------------------------------------------------------------- End of period 4,324 $ 45.73 3,404 $ 47.59 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Rights exercisable at end of period 1,795 $ 45.70 1,635 $ 44.84 ------------------------------------------------------------------------- (1) Exercise price reflects grant prices less reduction in strike price discussed above. The Fund uses a binomial lattice option-pricing model to calculate the estimated fair value of rights granted under the plan. Non-cash compensation costs charged to general and administrative related to rights issued for the three and six months ended June 30, 2008 were $2,094,000 ($0.01 per unit) and $3,580,000 ($0.02 per unit) respectively. Non-cash compensation costs for the three and six months ended June 30, 2007 were $2,107,000 ($0.02 per unit) and $4,218,000 ($0.03 per unit) respectively. (e) Basic and Diluted per Trust Unit Calculations Basic per-unit calculations are calculated using the weighted average number of trust units and exchangeable partnership units (converted at the 0.425 exchange ratio) outstanding during the period. Diluted per-unit calculations include additional trust units for the dilutive impact of rights outstanding pursuant to the Rights Plan. Net income per trust unit has been determined based on the following: Six months ended June 30, (thousands) 2008 2007 ------------------------------------------------------------------------- Weighted average trust units 153,138 125,849 Weighted average exchangeable partnership units(1) 2,846 - ------------------------------------------------------------------------- Basic weighted average units outstanding 155,984 125,849 Dilutive impact of rights 118 55 ------------------------------------------------------------------------- Diluted weighted average units outstanding 156,102 125,904 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on the exchange ratio of 0.425 (f) Performance Trust Unit Plan The Fund has a Performance Trust Unit ("PTU") plan for executives and employees. Under the plan employees and participants receive cash compensation in relation to the value of a specified number of underlying notional trust units. The number of notional trust units awarded is variable to individuals and they vest at the end of three years. Upon vesting, the plan participant receives a cash payment based on the fair value of the underlying trust units plus notional accrued distributions. The value determined upon vesting of the PTU plans is dependent upon the performance of the Fund compared to its peers over the three year period. The level of performance within the peer group then determines a performance multiplier. For the three months and six months ended June 30, 2008 the Fund recorded cash compensation costs of $1,217,000 (2007 - $570,000) and $2,300,000 (2007 - $915,000), respectively, under the plan which are included in general and administrative expenses. At June 30, 2008 there were 435,000 performance trust units outstanding. 9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (a) Fair Value of Financial Instruments The fair value of a financial instrument is the amount of consideration that would be agreed upon in an arm's-length transaction between knowledgeable, willing parties who are under no compulsion to act. Fair values are determined by reference to quoted bid or ask prices, as appropriate, in the most advantageous active market for that instrument to which we have immediate access. Where bid and ask prices are unavailable, we would use the closing price of the most recent transaction for that instrument. In the absence of an active market, we determine fair values based on prevailing market rates for instruments with similar characteristics. Fair values may also be determined based on internal and external valuation models, such as option pricing models and discounted cash flow analysis, that use observable market based inputs and assumptions. (b) Carrying Value and Fair Value of Non-derivative Financial Instruments i. Cash Cash is classified as held-for-trading and is reported at fair value. ii. Accounts Receivable Accounts receivable are classified as loans and receivables and are reported at amortized cost. At June 30, 2008 the carrying value of accounts receivable approximated their fair value. iii. Marketable Securities Marketable securities with a quoted market price in an active market are classified as available-for-sale and are reported at fair value, with changes in fair value recorded in other comprehensive income. During the first quarter of 2008 the Fund disposed of certain publicly traded marketable securities which resulted in a gain of $8,263,000 ($6,158,000 net of tax) being reclassified from accumulated other comprehensive income to other income on the Consolidated Statement of Income. As at June 30, 2008 the Fund did not hold any investments in publicly traded marketable securities. As at December 31, 2007 the Fund reported investments in publicly traded marketable securities at a fair value of $14,676,000. Marketable securities without a quoted market price in an active market are reported at cost. As at June 30, 2008 the Fund reported investments in marketable securities of private companies at cost of $49,966,000 (December 31, 2007 - $45,400,000) in Other Assets on the Consolidated Balance Sheet. iv. Accounts Payable & Distributions Payable to Unitholders Accounts payable and distributions payable to unitholders are classified as other liabilities and are reported at amortized cost. At June 30, 2008 the carrying value of these accounts approximated their fair value. v. Long-term debt Bank Credit Facilities The bank credit facilities are classified as other liabilities and are reported at amortized cost. At June 30, 2008 the carrying value of the bank credit facilities approximated their fair value. US$175 million senior notes The US$175,000,000 senior notes, which are classified as other liabilities, are reported at amortized cost of US$177,785,000 and are translated to Canadian dollars at the period end exchange rate. At June 30, 2008 the Canadian dollar amortized cost of the senior notes was approximately $181,092,000 and the fair value of these notes was $189,082,000. US$54 million senior notes The US$54,000,000 are classified as other liabilities and reported at their amortized cost of US$54,000,000 and are translated into Canadian dollars at the period end exchange rate. At June 30, 2008 the Canadian dollar amortized cost of the senior notes was approximately $55,004,000 and the fair value of these notes was approximately $54,830,000. (c) Fair Value of Derivative Financial Instruments The Fund's derivative financial instruments are classified as held for trading and are reported at fair value with changes in fair value recorded through earnings. The deferred financial assets and credits on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value. At June 30, 2008 a current deferred financial asset of $1,122,000, a current deferred financial credit of $289,100,000 and a long-term deferred financial credit of $85,621,000 are recorded on the consolidated balance sheet. The deferred financial credit relating to crude oil instruments of $199,211,000 at June 30, 2008 consists of the fair value of the financial instruments, representing a loss position of $186,054,000 plus the related deferred premiums of $13,157,000. The deferred financial credit relating to natural gas instruments of $89,889,000 at June 30, 2008 consists of the fair value of the financial instruments of $84,619,000 plus the related deferred premiums of $5,270,000. The following table summarizes the fair value as at June 30, 2008 and change in fair value for the period ended June 30, 2008 of the Fund's derivative financial instruments. The fair values indicated below are determined using observable market data including price quotations in active markets. Cross Currency Interest Interest Foreign Rate Rate Exchange Electricity ($ thousands) Swaps Swaps Swaps Swaps ------------------------------------------------------------------------- Deferred financial assets/(credits), at December 31, 2007 $ (226) $ (89,439) $ (425) $ 450 Change in fair value asset/(credits) (1,473)(3) 5,616(4) 326(5) 672(6) ------------------------------------------------------------------------- Deferred financial assets/(credits), end of period $ (1,699) $ (83,823) $ (99) $ 1,122 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Balance sheet classification: Current asset/ (liability) $ - $ - $ - $ 1,122 Non-current asset/ (liability) $ (1,699) $ (83,823) $ (99) $ - ------------------------------------------------------------------------- Commodity Derivative Instruments ------------------------- ($ thousands) Oil Gas Total ------------------------------------------------------------ Deferred financial assets/(credits), at December 31, 2007 $(56,783)(1) $ 8,083(2) $ (138,340) Change in fair value asset/(credits) (142,428)(7) (97,972)(7) (235,259) ------------------------------------------------------------ Deferred financial assets/(credits), end of period $ (199,211) $ (89,889) $ (373,599) ------------------------------------------------------------ ------------------------------------------------------------ Balance sheet classification: Current asset/ (liability) $ (199,211) $ (89,889) $ (287,978) Non-current asset/ (liability) $ - $ - $ (85,621) ------------------------------------------------------------ (1) Includes the Focus opening credit balance at February 13, 2008 of $4,295. (2) Includes the Focus opening credit balance at February 13, 2008 of $1,624. (3) Recorded in interest expense. (4) Recorded in foreign exchange expense (gain of $4,491) and interest expense (gain of $1,125). (5) Recorded in foreign exchange expense. (6) Recorded in operating expense. (7) Recorded in commodity derivative instruments (see below). The following table summarizes the income statement effects of commodity derivative instruments: Three months ended June 30, Six months ended June 30, ($ thousands) 2008 2007 2008 2007 ------------------------------------------------------------------------- Loss/(gain) due to change in fair value $ 160,955 $ (19,052) $ 240,400 $ 14,430 Net realized cash losses/(gain) 64,060 1,098 74,994 (6,778) ------------------------------------------------------------------------- Commodity derivative instruments loss/(gain) $ 225,015 $ (17,954) $ 315,394 $ 7,652 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (d) Risk Management The Fund is exposed to a number of financial risks including market, counterparty credit and liquidity risk. Risk management policies have been established by the Fund's Board of Directors to assist in managing a portion of these risks, with the goal of protecting earnings, cash flow and unitholder value. i. Market Risk Market risk is comprised of commodity price risk, currency risk and interest rate risk. Commodity Price Risk -------------------- The Fund is exposed to commodity price fluctuations as part of its normal business operations, particularly in relation to its crude oil and natural gas sales. The Fund manages a portion of these risks through a combination of financial derivative and physical delivery sales contracts. The Fund's policy is to enter into commodity contracts considered appropriate to a maximum of 80% of forecasted production volumes net of royalties. The Fund's outstanding commodity derivative contracts as at July 25, 2008 are summarized below: Crude Oil: WTI US$/bbl ---------------------------------------- Fixed Daily Price Volumes Sold Purchased Sold and bbls/day Call Put Put Swaps ------------------------------------------------------------------------- Term July 1, 2008 - December 31, 2008 Collar 750 $ 77.00 $ 67.00 - - 3-Way option 1,000 $ 84.00 $ 66.00 $ 50.00 - 3-Way option 1,000 $ 84.00 $ 66.00 $ 52.00 - 3-Way option 1,000 $ 86.00 $ 68.00 $ 52.00 - 3-Way option 1,000 $ 87.50 $ 70.00 $ 52.00 - 3-Way option 1,500 $ 90.00 $ 70.00 $ 60.00 - Put Spread 1,500 - $ 76.50 $ 58.00 - Put Spread 1,500 - $ 78.00 $ 58.00 - Put 700 - $ 86.10 - - Swap 750 - - - $ 72.94 Swap 750 - - - $ 74.00 Swap 750 - - - $ 73.80 Swap 750 - - - $ 73.35 Swap(3) 400 - - - $ 78.53 Swap 1,500 - - - $ 92.00 Swap(3) 400 - - - $ 84.60 January 1, 2009 - December 31, 2009 Collar 850 $100.00 $ 85.00 - - 3-Way option 1,000 $ 85.00 $ 70.00 $ 57.50 - 3-Way option 1,000 $ 95.00 $ 79.00 $ 62.00 - Put Spread 500 - $ 92.00 $ 79.00 - Put Spread(1) 500 - $ 92.00 $ 79.00 - Swap 500 - - - $100.05 Put(1) 1400 - $122.00 - - Put(2) 500 - $120.00 - - ------------------------------------------------------------------------- (1) Financial contracts entered into during the second quarter of 2008. (2) Financial contracts entered into subsequent to June 30, 2008. (3) Acquired through the acquisition of Focus. Natural Gas: AECO CDN$/Mcf ------------------------------------------------- Fixed Daily Price Volumes Sold Purchased Sold and MMcf/day Call Put Put Swaps ------------------------------------------------------------------------- Term July 1, 2008 - October 31, 2008 Collar 6.6 $ 8.44 $ 7.17 - - Collar 6.6 $ 7.49 $ 6.44 - - Collar 5.7 $ 7.39 $ 6.65 - - Collar 11.4 $ 8.65 $ 7.60 - - Collar 2.8 $ 8.65 $ 7.49 - - Collar 2.8 $ 8.86 $ 7.91 - - Collar 2.8 $ 8.97 $ 7.91 - - 3-Way option 5.7 $ 9.50 $ 7.54 $ 5.28 - 3-Way option 11.8 $ 7.91 $ 6.75 $ 5.49 - 3-Way option 11.8 $ 7.91 $ 6.75 $ 5.38 - 3-Way option 4.7 $ 8.23 $ 7.18 $ 5.28 - Swap 4.7 - - - $ 8.18 Swap 7.6 - - - $ 6.79 Swap(3) 14.2 - - - $ 6.70 Swap(3) 14.2 - - - $ 7.17 Swap 2.8 - - - $ 7.91 Swap 2.8 - - - $ 7.87 Swap 2.8 - - - $ 8.44 Swap 2.8 - - - $ 8.49 Swap 5.7 - - - $ 8.76 November 1, 2008 - March 31, 2009 Collar 5.7 $ 9.50 $ 8.44 - - 3-Way option 5.7 $ 10.71 $ 7.91 $ 5.80 - 3-Way option 1.9 $ 10.55 $ 8.44 $ 6.33 - 3-Way option 5.7 $ 10.71 $ 8.44 $ 6.33 - 3-Way option 9.5 $ 12.45 $ 8.97 $ 7.39 - 3-Way option(1) 4.7 $ 12.45 $ 8.97 $ 7.39 - Put Spread 4.7 - $ 8.97 $ 7.39 - Put Spread(1) 4.7 - $ 8.97 $ 7.39 - Swap 2.8 - - - $ 9.42 Swap 2.8 - - - $ 9.28 Swap 2.8 - - - $ 9.34 Put(1) 4.7 - $ 11.34 - - Put(2) 4.7 - $ 11.61 - - Put(2) 4.7 - $ 9.50 - - April 1, 2009 - October 31, 2009 Swap 3.8 - - - $ 7.86 Put Spread(1) 2.8 - $ 9.23 $ 7.65 - Put Spread(1) 2.8 - $ 9.50 $ 7.91 - Put Spread(1) 5.6 - $ 9.60 $ 7.91 - 2008 - 2010 Physical (escalated pricing) 2.0 - - - $ 2.59 ------------------------------------------------------------------------- (1) Financial contracts entered into during the second quarter of 2008. (2) Financial contracts entered into subsequent to June 30, 2008. (3) Acquired through the acquisition of Focus. The following sensitivities show the impact to after-tax net income for the three months ended June 30, 2008 of the respective changes in forward crude oil and natural gas prices as at June 30, 2008 on the Fund's commodity derivative contracts, with all other variables held constant: Increase/(decrease) to after-tax net income --------------------------- 20% decrease 20% increase in forward in forward ($ thousands) prices prices ------------------------------------------------------------------------- Crude oil derivative contracts $ 70,934 $ (67,469) Natural gas derivative contracts $ 39,235 $ (42,823) Electricity: The Fund is subject to electricity price fluctuations and it manages this risk by entering into forward fixed rate electricity derivative contracts on a portion of its electricity requirements. The Fund's outstanding electricity derivative contracts as at July 25, 2008 are summarized below: Volumes Price Term MWh CDN$/MWh ------------------------------------------------------------------------- July 1, 2008 - September 30, 2008 4.0 $ 63.00 July 1, 2008 - December 31, 2009 4.0 $ 74.50 ------------------------------------------------------------------------- The Fund did not enter into any new electricity contracts in the second quarter of 2008. Currency Risk ------------- The Fund is exposed to currency risk in relation to its U.S. dollar cash balances and U.S. dollar denominated senior unsecured notes. The Fund generally maintains a minimal amount of U.S. dollar cash and manages the currency risk relating to the senior unsecured notes through the currency derivative instruments that are detailed below. Cross Currency Interest Rate Swap ("CCIRS") Concurrent with the issuance of the US$175,000,000 senior notes on June 19, 2002, the Fund entered into a CCIRS with a syndicate of financial institutions. Under the terms of the swap, the amount of the notes was fixed for purposes of interest and principal payments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian bankers' acceptances, plus 1.18%. Foreign Exchange Swaps In September 2007 the Fund entered into foreign exchange swaps on US$54,000,000 of notional debt at an average CAD/US foreign exchange rate of 1.02. These foreign exchange swaps mature between October 2011 and October 2015 in conjunction with the principal repayments on the US$54,000,000 senior notes. The following sensitivities show the impact to after-tax net income for the three months ended June 30, 2008 of the respective changes in the period end and applicable forward foreign exchange rates as at June 30, 2008, with all other variables held constant: Increase/(decrease) to after-tax net income -------------------------- 10% decrease 10% increase in $CDN in $CDN relative relative ($ thousands) to $US to $US ------------------------------------------------------------------------- Translation of senior unsecured notes $ (7,029) $ 7,029 Increase/(decrease) to after-tax net income -------------------------- 10% decrease 10% increase in $CDN in $CDN relative relative ($ thousands) to $US to $US ------------------------------------------------------------------------- Foreign exchange swaps $ 7 $ (7) Cross currency interest rate swap(1) $ 6,732 $ (6,732) (1) Represents change due to foreign exchange rates only Interest Rate Risk ------------------ The Fund's cash flows are impacted by fluctuations in interest rates as its outstanding bank debt carries floating interest rates and payments made under the CCIRS are based on floating interest rates. To manage a portion of interest rate risk relating to the bank debt, the Fund has entered into interest rate swaps on $100,000,000 of notional debt at rates varying from 3.70% to 4.61% before banking fees that are expected to range between 0.55% and 1.10%. These interest rate swaps mature between June 2011 and April 2013. If interest rates change by 1%, either lower or higher, on our variable rate debt outstanding at June 30, 2008 with all other variables held constant, the Fund's after-tax net income for a quarter would change by $1,063,000. The following sensitivities show the impact to after-tax net income for the three months ended June 30, 2008 of the respective changes in the applicable forward interest rates as at June 30, 2008, with all other variables held constant: Increase/(decrease) to after-tax net income ------------------------------- 20% decrease 20% increase in forward in forward interest interest ($ thousands) rates rates ------------------------------------------------------------------------- Interest rate swaps $ (239) $ 239 Cross currency interest rate swap(1) $ 1,687 $ (1,687) (1) Represents change due to interest rates only ii. Credit Risk Credit risk represents the financial loss the Fund would experience due to the potential non-performance of counterparties to our financial instruments. The fund is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables. The Fund mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor a counterparty's credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. The Fund monitors and manages its concentration of counterparty credit risk on an ongoing basis. The Fund's maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets as well as the fair value of its derivative financial assets. At June 30, 2008 approximately 80% of our marketing receivables were with companies considered investment grade or just below investment grade. This level of credit concentration is typical of oil and gas companies of our size producing in similar regions. At June 30, 2008 approximately $7,700,000 or 3% of our total accounts receivable are aged over 120 days and considered past due. The majority of these accounts are due from various joint venture partners. The Fund actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production or net paying when the accounts are with joint venture partners. Should the Fund determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If the Fund subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. The Fund's allowance for doubtful accounts balance at June 30, 2008 is $3,800,000, which includes a $1,000,000 provision made during the quarter relating to receivables from a Canadian subsidiary of SemGroup LP. There were no accounts written off during the quarter. iii. Liquidity Risk & Capital Management Liquidity risk represents the risk that the Fund will be unable to meet its financial obligations as they become due. The Fund mitigates liquidity risk through actively managing its capital, which it defines as long-term debt (net of cash) and unitholders' capital. Enerplus' objective is to provide adequate short and longer term liquidity while maintaining a flexible capital structure to sustain the future development of the business. The Fund strives to balance the portion of debt and equity in its capital structure given its current oil and gas assets and planned investment opportunities. Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, distributions to unitholders, access to capital markets, as well as acquisition and divestment activity. Debt Levels ----------- The Fund commonly measures its debt levels relative to its "debt-to-cash flow ratio" which is defined as long-term debt (net of cash) divided by the trailing twelve month cash flow from operating activities. The debt- to-cash flow ratio represents the time period, expressed in years, it would take to pay off the debt if no further capital investments were made or distributions paid and if cash flow from operating activities remained constant. At June 30, 2008 the debt to cash flow ratio was 0.9x including the 12 months of trailing cash flow from Focus (June 30, 2007 - 0.7x). Enerplus' bank credit facilities and senior debenture covenants carry a maximum debt-to-cash flow ratio of 3.0x including cash flow from acquisitions on a proforma basis. Traditionally Enerplus has managed its debt levels such that the debt-to-cash flow ratio has been below 1.5x, which has provided flexibility in pursuing acquisitions and capital projects. After applying the proceeds from the sale of our Joslyn interest our debt to trailing cash flow ratio will be 0.4x. Enerplus' five-year history of debt to cash flow is illustrated below: Q2/ Q1/ 2008 2008 2007 2006 2005 2004 2003 ------------------------------------------------ Debt-to-Cash Flow Ratio 0.9x 1.0x 0.8x 0.8x 0.8x 1.1x 0.6x At June 30, 2008 Enerplus had additional borrowing capacity of $607,795,000 under its $1.4 billion bank credit facility. The Fund also has the ability to increase the bank credit facility and borrowing capacity beyond this level, however increasing the credit facility at this time would result in increased fees. Enerplus does not have any subordinated or convertible debt outstanding at this time. Capital Spending Plans ---------------------- In 2008 Enerplus expects to spend approximately $580 million developing existing assets. A portion of this capital spending is considered discretionary. There are limitations to changing the capital spending plans during a year. Long project lead times, economies of scale, logistical considerations, and partner commitments reduce the ability to adjust or down-size the capital program. Alternatively, the ability to rapidly increase spending may be limited by staff capacity, availability of services and equipment, access to sites, and regulatory approvals. Distributions to Unitholders ---------------------------- Enerplus distributes a significant portion of its cash flow to its unitholders every month. These distributions are not guaranteed and the board of directors can change the amount at any time. In the past, in periods of sustained commodity price declines, distributions have been reduced. Similarly, in periods of sustained higher commodity prices, distributions have increased. To the extent that cash flow exceeds distributions the additional funds are available to reduce debt, spend on capital development or finance acquisitions. The less cash required to finance these activities typically means more cash available for distributions and vice versa. Enerplus does not forecast distribution levels as it is difficult to predict the direction of commodity prices. To the extent possible, distributions are set at a level that can be maintained for a sustained period. Historical performance has demonstrated that Enerplus investors do not reward short-term sporadic increases, nor do they appreciate a series of decreases. Enerplus has maintained the current distribution level of $0.42/unit for 34 consecutive months. A stable or growing distribution pattern typically helps support the market price of the trust units. This unit price is important as equity is often issued in association with large acquisitions and the higher the unit price the less dilutive the equity issuance. By paying distributions, we effectively earn a tax deduction against the corporate taxes in our underlying subsidiaries and pass along Canadian tax liability to our unitholders. If distributions are lowered and too much cash flow is retained within the structure there is a risk that tax obligations in the operating entities may be created thereby eroding the flow-through advantage of the trust structure. Access to Capital Markets ------------------------- Enerplus relies on both the debt and equity markets to manage its cost of capital and fund future opportunities. There are times when the cost and access to these markets will vary. For example, the ability to issue new equity at a reasonable cost is strongly influenced by the equity market's perceptions of energy prices, macroeconomic factors, and Enerplus' future prospects. Similarly, the ability to increase bank credit or issue debentures is dependent on the overall state of the credit markets, as well as creditors' perceptions of the energy sector and Enerplus' credit quality. In times of uncertainty cash flow is preserved as a defense against capital market downturns rather than invested in capital programs or increasing distributions. Enerplus currently has an NAIC2 rating on the senior unsecured debentures in the U.S. private debt markets. In addition, the equity capital markets have indicated their continued support. Nonetheless, the capital markets can change rapidly with very little notice. Acquisition & Divestment Activity --------------------------------- In periods of market uncertainty and volatility, it is important to have a conservative balance sheet and access to capital markets to take advantage of acquisition opportunities as they arise. The Fund attempts to manage its capital in a manner that reflects the likelihood and magnitude of potential acquisitions and/or opportunities to dispose of non-core assets. Enerplus was successful in disposing of its Joslyn interest subsequent to the quarter, the proceeds of which will be used to repay debt, reinforcing Enerplus' borrowing capacity and enhancing the ability to fund future capital spending and acquisition activity. Liability Maturity Analysis --------------------------- The following tables detail the principal maturity analysis for the Fund's non-derivative financial liabilities at June 30, 2008: Payments Due by Period -------------------------------------- ($ thousands) Total 2008 2009 2010 ------------------------------------------------------------------------- Accounts Payable $ 289,576(1) $ 289,576 $ - $ - Distributions payable to unitholders 69,180(2) 69,180 - - Bank credit facility 792,205 - - 792,205 Senior unsecured notes 323,408(3) - - 53,666 ------------------------------------------------------------------------- Total commitments $ 1,474,369 $ 358,756 $ - $ 845,871 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Payments Due by Period Total ------------------------- Committed ($ thousands) 2011 2012 after 2013 ------------------------------------------------------------ Accounts Payable $ - $ - $ - Distributions payable to unitholders - - - Bank credit facility - - - Senior unsecured notes 64,682 64,682 140,378 ------------------------------------------------------------ Total commitments $ 64,682 $ 64,682 $ 140,378 ------------------------------------------------------------ ------------------------------------------------------------ (1) Accounts payable are generally settled between 30 and 90 days from the balance sheet date. (2) Distributions payable to unitholders are paid on the 20th day of the month following the balance sheet date. (3) Includes the economic impact of derivative instruments directly related to the senior unsecured notes (CCIRS and foreign exchange swap). It is Enerplus' intention to renew the bank credit facilities before or as they come due. Historically, the bank credit facilities have been renewed annually, refreshing the associated three year term period. Similarly, it is expected that the senior unsecured notes will be replaced with replacement notes or bank debt as they become due. Over the long-term, Enerplus expects to balance short-term credit requirements with bank credit and to look to the term debt markets for longer-term credit support. 10. SUBSEQUENT EVENT On July 31, 2008, subsequent to the quarter, Enerplus disposed of its Joslyn interest for net proceeds of approximately $500 million. 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.gov and at www.enerplus.com. Gordon J. Kerr President & Chief Executive Officer Enerplus Resources Fund INFORMATION REGARDING CONTINGENT RESOURCE DISCLOSURE IN THIS NEWS RELEASE This news release contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage." There is no certainty that Enerplus will produce any portion of the volumes currently classified as "contingent resources". The primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Kirby oil sands project as reserves consist of current uncertainties around the specific scope and timing of the project development, proposed reliance on technologies that have not yet been demonstrated to be commercially applicable in oil sands applications, the uncertainty regarding marketing plans for production from the subject areas and improved estimation of project costs. Based on current information and market conditions, Enerplus believes that development of the Kirby project will proceed as described in this news release. However, there are a number of inherent risks and contingencies associated with the development of the Kirby project, including commodity price fluctuations, project costs, receipt of regulatory approvals and those other risks and contingencies described above and under "Risk Factors and Risk Management" in the Management's Discussion an Analysis section of this news release and under "Risk Factors" in the Fund's Annual Information Form (and corresponding Form 40-F) dated March 12, 2007, as well as the risk factors to be contained in the Fund's Annual Information Form (and corresponding Form 40-F) filed in March 2008. FORWARD-LOOKING INFORMATION AND STATEMENTS This news release 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", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volumes and estimated value of the Fund's oil and gas reserves; the life of the Fund's reserves; 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 and operating metrics; future costs, expenses and royalty rates; future interest costs; future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures, including with respect to both our conventional and oil sands activities and in particular the development of the Kirby and Joslyn leases; future acquisitions and dispositions; the reinstatement of production from the Giltedge property and the availability of business interruption insurance to mitigate the costs of the Giltedge fire; the making and timing of future regulatory filings and applications; the value of the Fund's equity investments; future tax treatment of income trusts and future taxes payable by the Fund; the Fund's tax pools; the impact of the Focus acquisition on the Fund; the amount, timing and tax treatment of cash distributions to unitholders; and future payout ratios. The forward-looking information and statements contained in this news release 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, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of the Fund's reserve and resource volumes; certain commodity price and other cost assumptions; the continued availability of adequate debt and equity financing and cash flow to fund its plans expenditures; and accurate assessment of the value of Focus' assets and the extent of its liabilities. 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 news release 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; changes in the demand for or supply of the Fund's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans the Fund or by third party operators of the Fund's properties, including the operator of the Joslyn oil sands project; increased debt levels or debt service requirements; inaccurate estimation of the Fund's and Focus' oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; declines in the value of the Fund's equity investments; 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 news release and in the Fund's Annual Information Form). The forward-looking information and statements contained in this news release speak only as of the date of this news release, 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.
Enerplus’ core values include a commitment to develop its resources responsibly and profitably, while making a positive contribution to society