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The following discussion and analysis of financial results is dated February 18, 2006 and is to be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2005 and 2004. All amounts are stated in Canadian dollars unless otherwise specified. All note references relate to the notes included with the consolidated financial statements. 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. Non-GAAP Measures Throughout the MD&A, we use the terms funds flow from operations ("funds flow") and cash available for distribution. These terms as presented do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles ("GAAP"), and therefore they may not be comparable with the calculation of similar measures for other entities. Funds flow as presented is not intended to represent operating cash flows or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Funds flow is used by management to analyze operating performance, leverage and liquidity. All references to funds flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital. Cash available for distribution is calculated using funds flow less discretionary amounts of cash withheld for acquisitions, capital expenditures and debt repayment. Refer to the Cash Available for Distribution section of the MD&A for a quantitative reconciliation of "funds flow" to cash flow from operating activities. 2005 Overview 2005 was an extremely active year with the acquisitions of TriLoch Resources Inc. ("TriLoch") and Lyco Energy Corporation ("Lyco") occurring throughout our third quarter. The acquisition of Lyco was a strategic move into the United States and has provided further opportunities evidenced by the acquisition of Sleeping Giant LLC ("Sleeping Giant") which closed in the fourth quarter. These acquisitions, collectively, added approximately 10,000 BOE/day of production and 42.8 MMBOE of total proved plus probable reserves, replacing approximately 147% of 2005 total production. Overall we achieved our corporate guidance targets for annual production, operating costs per BOE and general and administrative ("G&A") costs per BOE. Development capital expenditures were $13.7 million higher than our guidance due to additional opportunities and increased costs. Our annual production increased 6% year over year due to our capital program and acquisitions. Exit production was approximately 85,000 BOE/day based on December's monthly average, which is below our guidance of 86,000 BOE/day due to delays and facility restrictions. We estimate 3,800 BOE/day associated with 2005 capital spending was delayed and is expected to come on production early in 2006. Compared to 2004, funds flow from operations increased 47%, net income per trust unit increased 52% and distributions to unitholders increased 20%. Additional production combined with a 28% rise in commodity prices were the main contributors to the year-over-year increases which were partially offset by a 4% increase in operating costs. Highlights
Production Daily production increased 6% during 2005 averaging 79,727 BOE/day, up from 75,130 BOE/day in 2004. This increase was primarily due to our development capital program and acquisitions. The most significant acquisitions completed during the year included TriLoch, Lyco and Sleeping Giant. Average production during 2005 was weighted 57% natural gas and 43% liquids on a BOE basis. Our operations have now expanded into the United States further diversifying our production base which already included Alberta, Saskatchewan, British Columbia and Manitoba. With operations widely distributed across more than 300 producing areas we minimize the risk that operational problems on a given property will materially impact our production or funds flow. Average production volumes for the years ended December 31, 2005 and 2004 are outlined below:
We exited the year with production of approximately 85,000 BOE/day based on December's monthly average production, slightly below our target of 86,000 BOE/day. Our development capital program experienced delays due to pipeline curtailment at Bashaw and facility restrictions at Bantry North. As a result we expect approximately 3,800 BOE/day of production related to 2005 activity to come on stream early in 2006. We expect 2006 production to average 84,000 BOE/day, weighted 53% natural gas and 47% liquids. In addition, we expect to exit 2006 with production of approximately 89,000 BOE/day which is 5% above our 2005 exit rate. This reflects our planned development capital program, however does not contemplate potential acquisitions or dispositions. Pricing Our earnings, funds flow and financial condition are dependent on the prices received for our natural gas and Crude Oil production. The following table compares our average selling prices for 2005 with those of 2004. It also compares the benchmark price indices for the same periods.
Natural Gas During the first half of the year, the monthly AECO benchmark natural gas price averaged just over $7.00/Mcf. Late in the summer, prices, climbed to over $12.00/Mcf in response to hurricane activity and strength in Crude Oil prices. Despite disruption in the Gulf Coast area, production during the summer injection season was sufficient to fill North American storage. Cold weather was slow to arrive in the fall of 2005 and as a result demand for natural gas combined with adequate storage levels caused prices to retreat at year-end to $10.78/Mcf. Overall, the average price for the AECO monthly index price for 2005 was $8.48/Mcf, up 25% compared to $6.79/Mcf in 2004. Within our sales portfolio of aggregator, downstream and spot gas, we sold approximately 40% of our natural gas based on AECO month index, 40% based on AECO day index and 20% at NYMEX monthly NX3 index prices. With the volatility around the weather and supply issues, there can be significant price differences between the month and day indices. During 2005 we realized an average price of $8.41/Mcf (net of transportation) on our natural gas, an increase of 28% from $6.56/Mcf in 2004. In comparison, the AECO monthly index price for natural gas increased 25% and the AECO daily index increased 33%. As indicated by the current market for future prices (the "forward market"), AECO natural gas prices are expected to average $8.08/Mcf for 2006. Weather continues to be a significant factor in the near term volatility of natural gas prices. Crude Oil The Crude Oil benchmark West Texas Intermediate ("WTI") price experienced volatility throughout 2005. Early in the year, fears concerning the supply demand balance and the refining infrastructure caused the prices to rise above US$50.00/bbl. Mid year unrest in Nigeria combined with the onset of the hurricane season pushed prices to peak at approximately US$70.00/bbl. Warmer weather and a reassessment of inventory levels post hurricane season, caused prices to settle into the US$60.00/bbl range near the end of the year. Overall, WTI prices denominated in U.S. dollars were 37% higher in 2005 compared to 2004. Our average Crude Oil selling price increased 28% from CDN$43.80 to CDN$55.93 which was comparable to the increase in the Canadian dollar equivalent WTI at 27%. Furthermore, our additional light sweet production in the United States offset the effect of increasing Canadian heavy oil differentials on our existing production. Continued geopolitical instability throughout the world combined with expected steady growth in a number of key economies have the current forward Crude Oil price at approximately US$64.70/bbl converted to CDN$74.39 using an exchange rate of US$0.87 for 2006. Throughout 2005 the Canadian dollar strengthened 8% against the U.S. dollar, reducing prices received for our Crude Oil and a portion of our natural gas. Most of Canada's Crude Oil and natural gas is exported to the U.S. and is priced with reference to U.S. dollar denominated benchmarks. The CDN$/US$ exchange rate entered 2005 at $0.83 and increased throughout the year to $0.86 in December. Price Risk Management Our commodity price risk management program incurred cash costs of $142.6 million during 2005 compared to $96.2 million during 2004. The increase in cash costs was primarily due to record high commodity prices exceeding our calls. The majority of these derivative instruments were contracted in 2003 and 2004, some of which expired on December 31, 2005 with the remaining expiring by the end of 2006.
We continue to review our risk management strategies in response to the increasing price environment, the economics of our acquisitions and development projects along with our overall financial position. Recently we have not been actively hedging commodity prices, however, this strategy may change in the future as management is constantly comparing the value of hedging with our overall requirement for price protection. The following table summarizes the effect that our financial contracts have had on income for the years ended December 31, 2005 and 2004.
The unrealized gain on our financial contracts of $35.8 million for the year ended December 31, 2005 represents the change in the fair value of financial contracts not qualifying for hedge accounting and results in a non-cash increase to earnings. Effective December 31, 2005, we elected to stop designating our commodity financial contracts as hedges. As a result we recorded a deferred credit representing the fair value of these contracts on that day, with an offset recorded as a deferred financial asset that is amortized to income over the life of the underlying contracts. All of these contracts mature during 2006, therefore the deferred financial asset will be fully amortized by December 31, 2006. In the future, non-cash gains or losses on any new commodity contracts will be reflected in our income statement. Funds flow remains sensitive to changes as demonstrated by the following table:
These sensitivities reflect all commodity contracts as described in Note 12 and are based on current forward markets for 2006. To the extent the market price of Crude Oil and natural gas change significantly from current levels, the above sensitivities will no longer be relevant. Revenues Crude Oil and natural gas revenues for the year ended December 31, 2005 were $1,523.7 million ($1,550.6 million, net of $26.9 million transportation) compared to $1,124.6 million ($1,149.7 million, net of $25.1 million transportation) during 2004. Higher Crude Oil and natural gas prices, combined with increased production from our development capital program and recent acquisitions resulted in a 35% increase of $399.1 million.
Royalties Royalties are paid to various government entities and other land and mineral rights owners. Royalties in 2005 and 2004 were approximately 19% and 20% of oil and gas sales , net of transportation, respectively. Overall royalties were $297.0 million compared to $231.0 million during 2004 which is consistent with our increase in revenue. We expect royalties to remain at approximately 19% for 2006. Operating Expenses Operating expenses for the year ended December 31, 2005 were on target with our guidance at $7.45/BOE or $216.8 million. This represented a 4% increase from $7.14/BOE or $196.5 million in 2004. As expected, we experienced increased cost pressures due to industry activity levels and higher utility rates. We also incurred additional well servicing costs as we focused on production enhancement initiatives. We expect cost pressures to continue in 2006 and estimate annual operating costs will be approximately $7.95/BOE, representing an increase of 7% per BOE compared to 2005. General and Administrative Expenses G&A expenses were $1.39/BOE or $40.4 million for the year ended December 31, 2005 compared to $1.23/BOE or $33.9 million for 2004. Cash G&A costs of $1.28/BOE or $37.4 million were in line with our guidance of $1.27/BOE and higher than costs of $1.06/BOE or $29.2 million experienced during 2004. The increase from the prior year can be attributed to recruiting and retaining skilled professional and technical staff along with increased infrastructure and information technology to support and enhance our expanded operations. Non-cash charges for our trust unit rights incentive plan for the year ended December 31, 2005 were $3.0 million or $0.11/BOE compared to $4.7 million or $0.17/BOE for 2004. Based on revised guidance on accounting for stock based compensation and related interpretations by the securities commissions, we have retroactively adopted the fair value method of accounting for our trust unit rights incentive plan to January 1, 2003. The impact of the adoption on our 2003 and 2004 reported earnings is not material and therefore prior period financial statements have not been restated. Our fourth quarter compensation expense in 2005 includes a non-cash recovery of $10.6 million. This recovery represents the difference between the unit based compensation expense related to 2005 originally calculated under the intrinsic method compared to the expense calculated using the fair value method. This change had no impact on funds flow from operations. See Notes 2 and 10. The following table summarizes the cash and non-cash expenses recorded in G&A:
For 2006 we expect total G&A costs to be approximately $1.70/BOE, including non-cash G&A costs of approximately $0.15/BOE. The forecasted increase reflects rising costs within a very competitive market place and our expanded operations in the United States. Interest Expense Annual interest expense was $25.8 million compared to $20.7 million in 2004. This increase is due to higher debt levels and rising interest rates during 2005. At December 31, 2005, 21% of our debt was based on fixed interest rates while 79% was floating. These instruments are more fully described in Note 12. Foreign exchange We experienced a foreign exchange loss of $1.7 million during the year ended December 31, 2005 compared to a gain of $5.0 million in 2004. A loss on foreign exchange contracts that were used to secure purchase price economics on the acquisition of Lyco was partially offset by gains on our US$54 million debentures. See Note 9 for further information. Capital Expenditures During the year ended December 31, 2005 we spent $1,010.5 million on capital expenditures and acquisitions net of dispositions compared to $813.6 million in 2004. As discussed in Notes 6 and 7, our most significant acquisitions during 2005 were TriLoch, Lyco, and Sleeping Giant. Our capital expenditures were financed through bank borrowing, the issuance of trust units and funds flow.
The following is a summary by major property of our largest development capital expenditures during 2005 and 2004.
Total development capital expenditures in 2006 are expected to be approximately $485 million . We plan to spend approximately $74 million on shallow natural gas development, $78 million on waterflood development, $89 million on Bakken oil development at our U.S. properties, $31 million on oil sands development and $49 million with respect to coalbed methane. Other conventional development costs are expected to be approximately $164 million during 2006. In 2005, we sold $66.5 million worth of non-core properties and we expect to continue the process of acquiring new properties and rationalizing marginal properties in 2006. At this time we have no significant divestment program planned for 2006. ASSET RETIREMENT OBLIGATIONS We have estimated total future asset retirement obligations based on our 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. Our asset retirement obligation was $110.6 million at December 31, 2005 compared to $106.0 million at December 31, 2004. The increase of $4.6 million was due to our acquisition and development activity during the year combined with changes in estimated future liabilities, offset by our dispositions of non-core properties. The remainder of the change was due to retirement costs incurred offset by accretion expense for the year. See Note 4. Depletion, depreciation, amortization and Accretion ("DDA&A") DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the year ended December 31, 2005, DDA&A increased to $13.27/BOE compared to $11.87/BOE during the year ended December 31, 2004. The increase is due to rising FD&A costs experienced over the last couple of years. No impairment existed at December 31, 2005 using year-end reserves and management's estimates of future prices. Our future price estimates are more fully discussed in Note 5. Taxes Future Income Taxes Future income taxes arise from differences between the accounting and tax bases of the operating companies' assets and liabilities. The future income tax liability associated with Canadian assets recorded on the balance sheet is recovered through earnings over time. For the year ended December 31, 2005, a future income tax expense of $15.3 million was recorded in income compared to a future income tax recovery of $76.8 million in 2004. The change from 2004 to 2005 was due to the combination of a future tax expense with respect to U.S. operations, amended tax pool balances, and a reduced payout ratio. Our expected future income tax rate incorporating these changes is approximately 34% which is the same as 2004. Current Income Taxes In our current structure, payments are made between the Canadian operating entities and the Fund, ultimately transferring both income and future income tax liability to our unitholders. Therefore, no cash income taxes have been paid by our Canadian operating entities. Our U.S. operations incurred taxes (income and withholding) in the amount of $2.8 million. The amount of tax was lower than originally projected due to increased development capital spending combined with additional tax pools. In 2006, we expect current and withholding taxes to be approximately 20% of U.S. funds flow from operations. Capital Taxes Capital taxes of $6.5 million decreased slightly in 2005 compared to 2004. The decrease is due to a reduction in the tax rate for Federal Large Corporations Tax. Capital taxes are expected to be $6.5 million in 2006. Selected Financial Results
Selected Canadian and U.S. Financial Results The following table provides a geographical analysis of key financial results for 2005. Prior period information has not been presented as we only had operations in Canada prior to 2005.
Net Income and Funds Flow from Operations Increased production volumes and commodity prices resulted in increased oil and gas sales, net income and funds flow from operations during the three years. The following table provides a summary of net income, funds flow from operations and other key measures.
Funds flow from operations for the year ended December 31, 2005 was $794.4 million or $7.28 per trust unit compared to $540.0 million or $5.44 per trust unit for 2004. Net income for the year ended December 31, 2005 was $432.0 million or $3.96 per trust unit compared to $258.3 million or $2.60 per trust unit for 2004. The increase in both funds flow from operations and net income was a result of higher commodity prices and production during 2005 compared to 2004. These increases were offset partially by cash losses on our commodity price risk management program and increased operating expenses. Quarterly Financial Information Overall oil and gas sales have increased due to higher commodity prices and production as well as through development capital activity and acquisitions throughout the last two years. Net income has been affected by rising oil and gas sales, increased risk management costs, the strengthening Canadian dollar, higher operating costs, changes in future tax recovery and changes to accounting policies adopted during 2005.
Summary Fourth Quarter Information In comparing the fourth quarter of 2005 with the same period in 2004:
(2) The entire non-cash recovery related to the adoption of the fair value method of accounting for our trust unit rights incentive plan has been recorded in the fourth quarter of 2005. Cash Available for distribution Our payout ratio for the year ended December 31, 2005 was 64%, compared to a payout ratio of 79% for the year ended December 31, 2004. During 2005, we funded over $1 billion in acquisitions and development capital spending through a combination of equity issuance, cash retained by the business, increased bank debt, and proceeds from divestments. We continually monitor our distribution payout with respect to forecasted funds flows, debt levels and spending plans. The level of cash retained typically varies between 10% and 40% of annual funds flow. This range has increased over the last two years. Recently we have been funding a greater portion of our development capital and acquisition programs with cash generated by the business, rather than through new equity issuance or increased debt. We are prepared to adjust the payout levels in an effort to balance the investor's desire for distributions with the Fund's requirement to maintain a prudent capital structure. The actual amount of funds flow withheld is dependant upon our current levels of production, the prevailing commodity price environment and is at the discretion of our Board of Directors. The following table reconciles Enerplus' funds flow from operations with the cash available for distribution to unitholders.
(1) Cash withheld for acquisitions, capital expenditures and debt repayment is a discretionary amount and represents the difference between cash flow from operations less distributions. (2) Cash available for distribution will differ from Cash Distributions to Unitholders on the Consolidated Statements of Cash Flows due to the timing of distribution announcements and the number of trust units outstanding on the record dates. Liquidity and Capital Resources Long-term debt, net of cash, at December 31, 2005 was $649.8 million , an increase of $64.8 million from December 31, 2004. Long-term debt at December 31, 2005 is comprise d of $328.6 m illion of bank indebtedness and $331.3 million of s enior unsecured notes . Our working capital at December 31, 2005 decreased compared to December 31, 2004. Current liabilities increased due to significant development capital spending late in the year, which more than offset increased current assets, including receivables for oil and gas sales. We continue to maintain a conservative balance sheet as demonstrated below:
Long-term debt is measured net of cash. Funds flow and interest expense are 12-months trailing (calculated based on the last 12 months after adjusting for acquisitions). Enerplus has an $850 million bank credit facility (the "Bank Credit Facility") through its wholly-owned subsidiary EnerMark Inc. The Bank Credit Facility is an unsecured, covenant-based, three-year committed credit agreement with nine North American banks. We have the ability to extend the facility each year or repay the entire balance at the end of the three-year term. At December 31, 2005, we had $ 521.4 million of available borrowing capacity under this facility, which currently extends to November, 2008. This bank debt carries floating interest rates that are expected to range between 60.0 and 115.0 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 funds 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 operating companies to make payments to the Fund and consequently the Fund's ability to make distributions to the unitholders may be restricted. Principal payments on Enerplus' senior unsecured notes are required commencing in 2010 and 2011 and are more fully discussed in Note 8. We anticipate that we will continue to have adequate liquidity to fund planned development capital spending during 2006 through a combination of funds flow from operations and debt. Most of our $485 million capital budget for 2006 is discretionary and can be revised downward in the event of a commodity price downturn or similar economic event. Commitments We have contracted to transport natural gas with various pipelines totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends until 2015. We also have a contract to transport a minimum of 2,480 bbls/day of Crude Oil until 2010. These transportation contracts will cost approximately $6.0 million in 2006. Our office lease commitments expire between November 2009 and January 2011. Annual costs of these lease commitments, which include rent and operating fees, amount to approximately $5.7 million. The Fund's commitments, contingencies, and guarantees are more fully described in Note 13. We must continue to pay crown and surface royalties, lease rentals, mineral taxes along with abandonment and reclamation costs with respect to our ongoing ownership of hydrocarbon production rights. The amounts paid with respect to these burdens will depend on the future ownership, production, prices and legislative environment at the time. Approximately 28% of our current gas production is dedicated to certain aggregator sales arrangements. Under these arrangements, we receive a price based on the average netback price of the pool, net of transportation costs incurred by the aggregator for the life of the reserves. Enerplus has the following minimum annual commitments including long-term debt:
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