Oil & Gas Job Listings
CALGARY, May 5 /CNW/ - Enerplus Resources Fund is pleased to announce the results from operations for the first quarter of 2006. Our financial and operating highlights are as follows:
- Enerplus had another strong lead-off quarter in 2006 with both record
production volumes and drilling activity. Our combined oil and natural
gas production for the quarter averaged 85,392 BOE/day, setting a new
high for Enerplus as a result of the ongoing strength of our
operations in the United States and Canada.
- Our development program also achieved record levels in the quarter as
we participated in the drilling of 289 wells (124.3 net) with a 100%
success rate. We are well on track to meet our full year 2006 capital
expenditures guidance of $485 million, having spent $129 million in
the first quarter. The capital program concentrated on Bakken oil in
Montana, coalbed methane in Alberta, tight shallow gas in southern
Alberta and Saskatchewan, and the Athabasca oil sands in northern
Alberta as we remain focused on the development of our resource plays.
- Cash distributions paid in the quarter to our Canadian unitholders
totaled $1.26 per unit and US$1.11 per unit to our U.S. unitholders.
This represents a 20% increase in distributions for Canadian
unitholders and a 31% increase for U.S. unitholders over the same
period last year and is a result of our increased production volumes
associated with our acquisition and development activities and
increased commodity prices. We were able to retain over $61 million
to fund our capital development program resulting in a payout ratio
of 71% for the quarter.
- Our oil sands operating partner, Deer Creek Energy Ltd., a
wholly-owned subsidiary of Total E&P Canada ("Total") filed an
application for the North Mine and we commissioned an interim
reserves/resources report from our independent reserve engineers. This
report quantified the recoverable resource associated with the mining
potential for the lease and when combined with our existing booked
reserves for SAGD, results in a best estimate of total recoverable
resource for the lease in the order of 2 billion barrels (300 million
barrels net to Enerplus). The best estimate of surface mineable gross
bitumen recoverable resources of 1.7 billion barrels recognizes the
North Mine as well as other mining areas.
- On March 20, we issued 4.37 million trust units through an equity
issue that raised gross proceeds of $253.5 million at $58.00 per unit.
The net proceeds of the offering were initially used to repay
outstanding indebtedness and will help fund our capital expenditures
program.
- Enerplus opened a new office in Denver, Colorado which is responsible
for the day-to-day operation of our Sleeping Giant project in
Montana. The office is also managing the development of our land base
in the Williston Basin and assisting our Calgary office in the pursuit
of future growth and acquisition opportunities in the United States.
- Our debt-to-cash flow at March 31, 2006 was 0.6 times.
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SELECTED FINANCIAL RESULTS
For the three months ended March 31, 2006 2005
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Financial (000's)
Net Income(1) $127,292 $65,178
Funds Flow from Operations(2) 213,315 153,741
Cash Available for Distribution(3) 152,197 109,843
Cash Withheld for Acquisitions and Capital
Expenditures 61,118 43,898
Debt Outstanding (net of cash) 525,864 562,369
Development Capital Spending 128,748 69,303
Acquisitions 30,027 1,820
Divestments 19,717 61,689
Financial per Unit
Net Income(1) $1.08 $0.63
Funds Flow from Operations(2) 1.80 1.47
Cash Distributed(3) 1.26 1.05
Cash Withheld for Acquisitions and Capital
Expenditures 0.51 0.42
Payout Ratio 71% 71%
Selected Financial Results per BOE(4)
Oil & Gas Revenues(5) $52.27 $42.55
Royalties (10.40) (8.78)
Financial Contracts (2.98) (2.86)
Operating Costs (7.57) (6.98)
General and Administrative (1.58) (1.09)
Interest and Foreign Exchange (0.90) (0.71)
Taxes (0.68) (0.17)
Restoration and Abandonment (0.40) (0.29)
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Funds Flow from Operations(2) $27.76 $21.67
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Weighted Average Number of Trust Units
Outstanding (thousands) 118,221 104,269
Debt/Trailing 12 Month Funds Flow Ratio(2) 0.6x 1.0x
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(1) See trust unit rights incentive plan discussion in Note 1
(2) See the definition of funds flow in Management's Discussion and
Analysis
(3) Calculated based on distributions paid or payable each month relating
to the period
(4) Non-cash amounts have been excluded
SELECTED OPERATING RESULTS
Enerplus uses the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
For the three months ended March 31, 2006 2005 ------------------------------------------------------------------------- Average Daily Production Natural gas (Mcf/day) 270,765 280,463 Crude oil (bbls/day) 35,853 27,448 NGLs (bbls/day) 4,411 4,621 ------------------------------------------------------------------------- Total (BOE/day) (6:1) 85,392 78,813 % Natural gas 53% 59% Average Selling Price(5) Natural gas (per Mcf) $8.33 $6.58 Crude oil (per bbl) 55.20 47.61 NGLs (per bbl) 50.57 43.80 US$ exchange rate 0.87 0.82 Net Wells Drilled 124 95 Success Rate 100% 100% ------------------------------------------------------------------------- (5) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. TRUST UNIT TRADING SUMMARY TSX - ERF.un NYSE - ERF for the three months ended March 31, 2006 (CDN$) (US$) ------------------------------------------------------------------------- High 64.36 56.05 Low 52.12 45.10 Close 58.57 50.44 2006 CASH DISTRIBUTIONS PER TRUST UNIT CDN$ US$ ------------------------------------------------------------------------- Production Month Payment Month January March $0.42 $0.36 February April 0.42 0.37 March May 0.42 0.38(x) ------------------------------------------------------------------------- First Quarter Total $1.26 $1.11 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (x) Calculated using an exchange rate of 1.11 OPERATIONS OVERVIEW
Year-to-date, our 2006 production and development programs are meeting our expectations. First quarter production averaged 85,392 BOE/day, slightly higher than our 2005 fourth quarter production volumes. Production additions from our first quarter development capital program along with carry-forward production from the fourth quarter offset natural declines in our asset base. We continue to target average annual production of 84,000 BOE/day with an exit rate of 89,000 BOE/day.
We achieved record first quarter levels of development capital activity with expenditures of $128.7 million and the drilling of 124.3 net wells with a 100% success rate. Most of our drilling activity was focused on shallow gas and CBM development, while significant investments were also made in our Montana Bakken oil property and our Canadian conventional oil and gas properties. We also spent $8.2 million on land and seismic which is expected to generate additional opportunities in the years ahead. As a result of our organization and pre-planning efforts, we are well positioned to execute on our planned capital investment opportunities throughout the remainder of the year.
Operating costs were in line with expectations at $7.57/BOE for the quarter, up from the first quarter 2005 due to inflationary pressures. We expect to see operating costs per BOE increase during the second quarter as a result of planned plant maintenance activities that will interrupt production. The industry continues to experience cost escalations due to high levels of activity. To help mitigate these increases, we are focusing additional effort on leveraging our size to procure goods and service contracts that can provide greater cost efficiencies. Our full year projection for operating costs remains at $7.95/BOE.
Enerplus enjoys a healthy inventory of oil and gas development prospects in excess of our 2006 target investment level of $485 million. Although all scheduled programs are economically attractive at current commodity prices, we are reviewing our 2006 program in the context of recent escalating oil prices and softening gas prices. We currently have approximately $90 million targeted for long-term opportunities and we may redirect a portion of this capital towards crude oil projects to maximize our return given the current strength of crude oil prices. This could lead to the acceleration of some oil projects in 2006 and the deferral of some gas projects to 2007.
Q1 Capital Q1 2006 Development Activity Spending Wells Drilled by Play Type ($ millions) Gross Net ------------------------------------------------------------------------- Shallow Natural Gas $12.1 116 59.6 Crude Oil Waterfloods 14.1 14 11.2 Bakken Oil 27.0 8 5.6 Oil Sands 11.1 11 1.7 Coalbed Methane 16.8 41 25.6 Other Conventional Oil & Gas 47.6 99 20.6 ------------------------------------------------------------------------- Total $128.7 289 124.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- SHALLOW GAS DEVELOPMENT
We continue to pursue an active development program on our shallow natural gas properties in southern Alberta and Saskatchewan, targeting the Milk River, Medicine Hat and Second White Specs formations. During the first quarter we invested $12.1 million and participated in the drilling of 116 gross shallow gas wells (59.6 net). At Verger we participated in 24 gross wells (8.8 net), with production expected to come on stream in May. At Bantry we initiated a high density well program (16 wells/section) with the drilling of 17 gross wells (15.6 net). We expect that production from this program will be on stream in August. We also drilled 17 wells (100% WI) at Medicine Hat North and participated in drilling 18 wells (8.8 net) at Shackleton. Significant additional drilling activity is planned at Shackleton, Hanna and Medicine Hat during the year.
WATERFLOOD DEVELOPMENT
In the first quarter, we invested approximately $14.1 million on waterflood drilling, re-completions, stimulations and optimization activities. We drilled 14 gross wells (11.2 net) including 11 wells (100% WI) at Joarcam in the Viking formation. The Joarcam wells are part of a larger 22 oil well program expected to add 500 BOE/day in 2006. During the course of the year, we plan to drill 7 wells (100% WI) at Pembina and execute on other significant development activities at Medicine Hat and Virden.
BAKKEN OIL DEVELOPMENT
We became a significant Bakken crude oil player in 2005 with the acquisition of interests in the Sleeping Giant project in northeast Montana. In February, we opened our Denver office and are currently building a team of technical professionals to support our strategic growth plans for the United States. First quarter production and development activities occurred as planned with capital investment of $27 million to drill 8 horizontal oil wells (5.6 net) resulting in average production volumes of over 10,000 BOE/day. We ship our crude oil production from this area via a combination of pipeline and trucking. Currently, both pipeline and trucking systems are effectively fully utilized and we could experience temporary curtailments of approximately 250 - 500 bbls/day at any given time. We are working closely with the shippers and industry partners to ensure that the effects of these restrictions are mitigated. Also the pipeline company has plans to expand capacity out of the area to handle the additional production volumes anticipated with the on-going development spending in the area.
OIL SANDS DEVELOPMENT
Our oil sands project continues to be a significant part of our planning activity and future growth opportunity as we progress on both the SAGD and mine development. Enerplus and the operator, Deer Creek Energy Ltd., a wholly-owned subsidiary of Total E&P Canada ("Total"), are currently reviewing options on the optimal lease development plan given the flexibility which exists for both SAGD and mining recovery of the bitumen resource. Given the overburden depth relative to bitumen resource on the western portion of the lease, the option to expand the current mining area exists and could impact the area originally identified for SAGD recovery.
Phase II (SAGD)
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Phase II is the first phase of commercial SAGD development on the lease. In the first quarter we completed the initial SAGD drilling and began steam injection as expected. We currently have 17 new well pairs in Phase II plus the initial pilot well pair which will be included in the first commercial project. We expect production from the new wells to begin in May of this year with peak production to occur in the fourth quarter of 2007.
The SAGD development project is slightly behind schedule but is expected to come in essentially on budget at just over $200 million gross ($30 million net to Enerplus). The Joslyn sales pipeline, however, was over budget due to weather, right of way and operational issues. As a result of the project delays, the 2006 exit rate production is projected to be approximately 5,000 bbls/day (gross) and reach peak production expectations in the order of 10,000 bbls/day (1,500 bbls/day net to Enerplus) in the fourth quarter of 2007. We do not expect to report any production until such time as commercial operations have been established and as such, have not included any of these volumes in our overall 2006 corporate guidance.
Phase IIIA/IIIB (SAGD)
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Phase IIIA is a 26 well pair SAGD project expected to start up in 2008 and reach an estimated 15,000 bbls/day gross peak production rate in 2010. Phase IIIB is an additional 15,000 bbls/day gross peak production rate project which may startup in 2010. The operator has completed the preliminary engineering design for Phase IIIA and we anticipate receiving regulatory approval early in the third quarter. Currently Phase IIIA is booked as probable reserves and no reserves are carried for the Phase IIIB project.
We are currently reviewing options for lease development including the potential to mine areas of the lease which could impact the scope of Phase IIIA and IIIB. Given that we currently have a portion of the Phase IIIA SAGD reserves booked as probables and no reserves associated with Phase IIIB, a decision to mine some currently identified SAGD areas could result in changes to reserves and projected production on this portion of the lease. Mining typically provides about twice the recovery of the original bitumen in place versus SAGD projects.
Mining Resource Potential
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The Joslyn lease has the potential for resource recovery from both the SAGD process as well as mining. An independent third party analysis commissioned by Enerplus considered the mining opportunities contained within the lease and prepared a low, best and high estimate of gross lease recoverable, surface mineable, bitumen resources of approximately 1.1, 1.7 and 2.3 billion barrels, respectively. Enerplus has a 15 percent working interest in the lease.
The resource estimates recognize select mine areas beyond the North Mine, however, they do not consider potential mining opportunities within the SAGD potential area. The range reflects the current uncertainty associated with the geological model, pit development and design issues, and extraction recovery. The low resource estimate considers a total volume of material to bitumen in place (TV:BIP) limit of approximately 12:1, consistent with the North Mine application, while the high resource estimate considers a TV:BIP limit of approximately 15:1, subject to site layout constraints relating to the North Mine development plan. As the TV:BIP pit limit increases, the mine operation accesses higher cost to revenue ratio ore. If the mining areas were expanded to impact the SAGD area, this would likely result in incremental total resources and ultimately reserves for the lease.
Additional work including detailed economic comparisons of expanded mining operations versus SAGD, confirmation of project timing, pilot testing on new technologies included in the North Mine application, development of the marketing plans for the lease, and additional core hole drilling will further define the opportunities for both SAGD and mining development on this lease. Given the uncertainties around the specific project scope, timing, use of new technologies, and the marketing plans for the lease, none of the resources associated with the mining area were classified as reserves at this time. As these uncertainties are further resolved, we would expect to begin booking probable reserves for the mining area.
North Mine
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The North Mine represents a 100,000 bbl/day (gross) project and 890 million barrels of recoverable resource per the application submitted by the operator (134 million barrels net to Enerplus). The North Mine application was filed in February and is currently being reviewed by the government regulators. The operator currently anticipates project approval late in 2007 with project startup in 2010/2011 and full production by 2014. Current industry pressures from a significant number of competing projects could impact project timing.
The interim reserves/resources report includes a best estimate of resources for the North Mine of 950 million barrels (142 million net) which is comparable to the recoverable resource estimated in the mining application discussed above. The report also includes a low and high estimate for the North Mine of 790 and 1,170 million barrels (gross), respectively.
COALBED METHANE DEVELOPMENT
Coalbed methane ("CBM") continues to represent a significant piece of Enerplus' capital development portfolio. During the first quarter of 2006, we invested approximately $16.8 million on development activities, including participation in 41 gross wells (25.6 net) targeting the Horseshoe Canyon formation in central Alberta. The Horseshoe Canyon coals are typically dry and do not have the water handling issues often associated with CBM production found in other areas in North America. At Bashaw, we drilled 7 gross wells (5.6 net). We also participated in 12 gross wells (6 net) at Joffre and drilled 8 gross wells (6.8 net) at Trochu. We expect that all of these new wells at Bashaw, Joffre and Trochu will be tied in by the end of the second quarter. We are currently reviewing our 2006 CBM drilling plans at Bashaw due to area transportation issues. This review could result in a reallocation of a portion of our 2006 CBM capital program to other play types with the balance of CBM drilling deferred to 2007.
OTHER CONVENTIONAL DEVELOPMENT
During the first quarter of 2006, we invested $47.6 million in other conventional development properties, drilling 99 gross wells (20.6 net) throughout western Canada. We invested $9 million of this total participating in the drilling of 21 gross wells (1.2 net) in the deep gas formations of the Foothills and Deep Basin areas of western Alberta and northeast British Columbia. We expect to continue to participate in joint venture deep gas drilling opportunities during the remainder of the year.
At Bantry North, a non-operated sour gas facility was completed allowing for additional production capability of 1,400 BOE/day from our 2005 development activities to come on stream. We have experienced some production interruptions as the plant undergoes expansion and we expect that our full production capability will be achieved during the course of the year. Additional 2006 development plans include drilling 5 (100% WI) oil wells in the Sunburst formation in the third quarter.
ACQUISITIONS AND DIVESTMENTS
Although no significant acquisitions were completed in the first quarter, we did execute on a number of focused acquisitions, increasing working interests in existing strategic portfolio areas. This included the addition of interests to our Gleneath light oil unit and the Sleeping Giant project in Montana. In total, we acquired approximately 2.9 million BOE of proved plus probable reserves and 442 BOE/day of production for $30 million resulting in attractive acquisition metrics of $10.23 per BOE of proved plus probable reserves excluding future development capital and $67,990/BOE of current daily production.
We also divested 3.3 million BOE of proved plus probable reserves, with no associated production for $19.7 million. The bulk of our disposition activity was the strategic sale of a 1% working interest in our Joslyn oil sands project in return for an equity ownership position in Laricina Energy Ltd. Laricina is a private oil sands focused company run by the former CEO of Deer Creek Energy Limited. In addition to the equity interest, we are participating with Laricina in an area of mutual interest to jointly pursue additional in-situ oil sands ventures.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated
May 4, 2006 and is to be read in conjunction with:
- the MD&A and audited consolidated financial statements as at and for
the years ended December 31, 2005 and 2004; and
- the unaudited interim consolidated financial statements as at and for
the three months ended March 31, 2006 and 2005.
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. 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.
Cash available for distribution is calculated using funds flow less discretionary amounts of cash withheld for acquisitions, capital expenditures and debt repayment. In the past, we have used the term "distributable income" and "cash available for distribution" interchangeably in our public disclosure documents. In the future, we intend to only use the term "cash available for distribution" in all such documents.
OVERVIEW
Increased production from prior year acquisitions and our ongoing development capital program combined with continued high commodity prices delivered strong funds flow in the first quarter. Development capital spending totaled $128.7 million, resulting in the addition of 124 net wells with a 100% success rate. Overall operating metrics were in-line with our guidance. We continue to expect annual production for 2006 to average approximately 84,000 BOE/day with an average exit rate of 89,000 BOE/day. We closed an equity offering at $58.00 per unit on March 20, 2006 that resulted in gross proceeds of $253.5 million ($240.3 net of issuance costs). The net proceeds were used to repay bank indebtedness and will subsequently be used to fund development capital and other general corporate expenditures.
RESULTS OF OPERATIONS Production
We achieved average production of 85,392 BOE/day for the first quarter of 2006, an 8% increase over our average production volumes of 78,813 BOE/day for the first quarter of 2005. This increase is a result of our acquisitions completed during the second half of 2005 as well as our ongoing development capital program.
Our average production during the three months ended March 31, 2006 was weighted 53% natural gas and 47% crude oil and natural gas liquids on a BOE basis, compared to the first quarter of 2005 when our production was weighted 59% natural gas and 41% liquids on a BOE basis. Our U.S. acquisitions of light sweet crude oil contributed to this change in production mix. Average production volumes for the three months ended March 31, 2006 and 2005 are outlined below:
Three months ended March 31, Daily Production Volumes 2006 2005 % change ------------------------------------------------------------------------- Natural gas (Mcf/day) 270,765 280,463 (3%) Crude oil (bbls/day) 35,853 27,448 31% Natural gas liquids (bbls/day) 4,411 4,621 (5%) Total daily sales (BOE/day) 85,392 78,813 8% -------------------------------------------------------------------------
We are maintaining our annual production estimate of 84,000 BOE/day, however during the second quarter we expect a temporary decrease in production as a result of scheduled plant maintenance.
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 the three months ended March 31, 2006 and 2005. It also compares the benchmark price indices for the same periods.
Three months ended March 31, Average Selling Price(1) 2006 2005 % change ------------------------------------------------------------------------- Natural gas (per Mcf) $8.33 $6.58 27% Crude oil (per bbl) 55.20 47.61 16% Natural gas liquids (per bbl) 50.57 43.80 15% Per BOE $52.27 $42.55 23% ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments Three months ended March 31, Average Benchmark Pricing 2006 2005 % change ------------------------------------------------------------------------- AECO natural gas - monthly index (CDN$/Mcf) $9.27 $6.69 39% AECO natural gas - daily index (CDN$/Mcf) 7.56 6.87 10% NYMEX natural gas - monthly NX3 index (US$/Mcf) 9.07 6.32 44% NYMEX natural gas - monthly NX3 index CDN$ equivalent (CDN$/Mcf) 10.43 7.71 35% WTI crude oil (US$/bbl) 63.48 49.84 27% WTI crude oil: CDN$ equivalent (CDN$/bbl) 72.99 60.78 20% CDN$/US$ exchange rate $0.87 $0.82 6% -------------------------------------------------------------------------
We realized an average price on our natural gas of $8.33/Mcf (net of transportation) during the three months ended March 31, 2006 an increase of 27% from $6.58/Mcf for the same period in 2005. In general, natural gas prices in February and March 2006 retracted approximately 35% from January levels in response to the unusually warm winter and the lower than normal storage withdrawal. In comparison to the first quarter of 2005, the AECO monthly index price for natural gas increased 39% and the AECO daily index price increased 10%. We sell our natural gas under both month and day AECO index contracts. As a result, our realized natural gas price during the first quarter increased 27%, comparable to the 24% blended increase of the combined indices.
The average price we received for our crude oil during the three months ended March 31, 2006 increased 16% to $55.20/bbl (net of transportation) from $47.61/bbl during the same period of 2005. In comparison, the West Texas Intermediate ("WTI") crude oil benchmark price, after adjusting for the change in the US$ exchange rate, increased 20% for the corresponding period in 2005. Our average crude oil price did not increase to the extent of the underlying WTI despite the fact that we added additional light sweet production in 2006. Across North America the differential between physically delivered crude oil and the WTI contract traded in New York at the Mercantile Exchange (NYMEX) has widened impacting realized prices within our industry. The differentials widened due to a number of factors including North American supply and demand, inventory levels, reduced refinery utilization and quality differences.
The Canadian dollar strengthened 6% against the U.S. dollar during the first quarter of 2006 compared to the same period in 2005. As most of our crude oil and a portion of our 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 continue to review our risk management strategies in response to the volatile price environment and the economics of our acquisitions and development projects together with our overall financial position. We have not entered into any financial contracts since the third quarter of 2005 and as a result the number of outstanding derivative financial instruments continues to decrease as existing contracts expire. All current outstanding financial contracts will expire during 2006.
Our commodity price risk management program incurred cash costs of $12.9 million on crude oil contracts and cash costs of $10.0 million on natural gas contracts during the first quarter of 2006, compared to cash costs of $18.8 million and $1.4 million respectively during the first quarter of 2005. Fewer outstanding crude oil contracts, partially offset by increased crude oil prices, caused the decrease in cash costs on crude oil contracts. Although there were fewer natural gas contracts outstanding, significantly higher natural gas prices in January of 2006 caused the increase in cash costs on natural gas contracts.
The unrealized gain on our financial contracts of $40.3 million for the three months ended March 31, 2006 represents the change in the fair value of financial contracts since December 31, 2005 and results in a non-cash increase to earnings. At March 31, 2006 the fair value of our financial contracts of $17.1 million is recorded on the balance sheet as a deferred credit. See Note 2 for details.
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. For the period ended March 31, 2006 we recorded $18.3 million of amortization related to these contracts. The remaining deferred financial asset of $31.6 million at March 31, 2006 will be amortized during the remainder of the year as the underlying contracts mature. See Note 2 for details.
Risk Management Costs Three months ended Three months ended ($ millions, except per March 31, March 31, unit amounts) 2006 2005 ------------------------------------------------------------------------- Cash costs: Crude oil $12.9 $4.00/bbl $18.8 $7.61/bbl Natural Gas 10.0 $0.41/Mcf 1.4 $0.06/Mcf -------- -------- Total Cash costs $22.9 $2.98/BOE $20.2 $2.86/BOE Non-cash costs: Change in fair value - financial contracts $(40.3) $(5.24)/BOE $31.3 $4.41/BOE Amortization of deferred financial assets 18.3 2.38/BOE 1.0 0.14/BOE -------- -------- Total Non-cash costs $(22.0) $(2.86)/BOE $32.3 $4.55/BOE -------- -------- Total costs $0.9 $0.12/BOE $52.5 $7.41/BOE ------------------------------------------------------------------------- ------------------------------------------------------------------------- REVENUES
Crude oil and natural gas revenues for the three months ended March 31, 2006 were $401.7 million ($407.8 million, net of $6.1 million of transportation costs) compared to $301.8 million ($309.0 million, net of $7.2 million of transportation costs) for the same period in 2005. The increase of $99.9 million, or 33%, is primarily due to higher commodity prices as well as increased crude oil production resulting from our 2005 acquisitions.
Analysis of Sales Revenue(1) Natural ($ millions) Crude oil NGLs Gas Total ------------------------------------------------------------------------- Quarter ended March 31, 2005 $117.6 $18.2 $166.0 $301.8 Price variance(1) 24.5 2.7 43.1 70.3 Volume variance 36.0 (0.8) (5.6) 29.6 ------------------------------------------------------------------------- 2006 Sales Revenue $178.1 $20.1 $203.5 $401.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. ROYALTIES
Royalties are paid to various government entities and other land and mineral rights owners. For the three months ended March 31, 2006 royalties increased to $80.0 million compared to $62.3 million during 2005, both approximately 20% of oil and gas sales, net of transportation. The increase is consistent with our revenue analysis of higher production and commodity prices during the first quarter. We continue to expect royalties to be between 19% and 20% for the remainder of the year.
OPERATING EXPENSES
Operating expenses for the three months ended March 31, 2006 were $58.2 million or $7.57/BOE compared to $49.5 million or $6.98/BOE for the same period in 2005. Total operating costs have increased over the prior period due to cost pressures related to the high level of industry activity and more specifically those costs associated with repairs and maintenance, well servicing and utilities. These increases were in line with our expectations for the first quarter.
Scheduled plant maintenance that will temporarily impact production is expected to increase operating costs both in total and per BOE during the second quarter. We are maintaining our operating cost guidance of approximately $7.95/BOE for the year ended 2006.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses were $13.3 million or $1.73/BOE for the three months ended March 31, 2006 compared to $8.3 million or $1.18/BOE for the first quarter of 2005. Cash G&A expenses of $1.58/BOE in the first quarter of 2006 were slightly higher than our guidance of $1.55/BOE and significantly higher compared to $1.09/BOE in the first quarter of 2005. The cost pressures to retain, recruit and expand a highly skilled professional and technical team have resulted in increased compensation and benefits being paid during 2006 compared to previous years.
On October 1, 2005 we retroactively adopted the fair value method of accounting for our trust unit rights incentive plan to January 1, 2003. For comparative purposes the 2005 quarters have been restated to reflect the adoption of the fair value method of accounting for the trust unit rights incentive plan. See Notes 1 and 4 for further details. For the three months ended March 31, 2006 these non-cash charges were $1.2 million or $0.15/BOE compared to $0.6 million or $0.09/BOE for the first quarter of 2005.
We are maintaining our annual guidance of $1.70/BOE for G&A.
The following table summarizes the cash and non-cash expenses recorded in G&A:
General and Administrative Costs Three months ended March 31, ($ millions) 2006 2005 ------------------------------------------------------------------------- Cash $12.1 $7.7 Non-cash trust unit rights incentive plan(1) 1.2 0.6 ------------------------------------------------------------------------- Total G&A $13.3 $8.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (Per BOE) 2006 2005 ------------------------------------------------------------------------- Cash $1.58 $1.09 Non-cash trust unit rights incentive plan(1) 0.15 0.09 ------------------------------------------------------------------------- Total G&A $1.73 $1.18 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) See trust unit rights incentive plan discussion in Note 1 INTEREST EXPENSE
Interest expense increased to $8.2 million for the first quarter of 2006 from $5.9 million during the same period of 2005. The increase is due to higher average indebtedness and higher interest rates during the first quarter of 2006. At March 31, 2006, approximately 26% of our debt was based on fixed interest rates while 74% was floating.
CAPITAL EXPENDITURES
During the three months ended March 31, 2006 we spent $128.7 million on development drilling and facilities compared to $69.3 million during the same period in 2005. We achieved a 100% success rate in drilling 124 net wells during the quarter focusing primarily on shallow gas and CBM development. We also made significant development investments in our U.S. Bakken oil property and Canadian conventional oil and gas properties.
Property acquisitions for the quarter included additional interests in the Gleneath area for $11.8 million and the Sleeping Giant project in Montana for $14.6 million. We also sold a 1% interest in the Joslyn project for $19.7 million in exchange for an equity interest of approximately 19% in Laricina Energy Ltd. ("Laricina") valued at $19.5 million and cash of $0.2 million. This reduced our interest in the Joslyn project to 15%.
Our capital expenditures were financed by withholding a portion of our cash available for distribution, additional debt and an equity issuance completed during the first quarter. Total net capital expenditures of $139.8 million for the first quarter of 2006 compared to $9.9 million for the first quarter of 2005 are outlined below.
Three months ended March 31, Capital Expenditures ($ millions) 2006 2005 ------------------------------------------------------------------------- Development expenditures $97.7 $54.3 Plant and facilities 31.0 15.0 ------------------------------------------------------------------------- Development Capital 128.7 69.3 Office 0.8 0.5 ------------------------------------------------------------------------- Sub-total 129.5 69.8 Acquisitions of oil and gas properties 30.0 1.8 Dispositions of oil and gas properties (19.7) (61.7) ------------------------------------------------------------------------- Total Net Capital Expenditures $139.8 $9.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total Capital Expenditures financed with funds flow $61.1 $9.9 Total Capital Expenditures financed with debt and equity 98.2 - Total non-cash consideration for 1% sale of Joslyn project (19.5) - ------------------------------------------------------------------------- Total Net Capital Expenditures $139.8 $9.9 ------------------------------------------------------------------------- -------------------------------------------------------------------------
We are maintaining our 2006 annual guidance of $485 million for development capital spending.
DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION ("DDA&A")
DDA&A of property, plant and equipment is recognized using the unit-of- production method based on proved reserves.
For the three months ended March 31, 2006, DDA&A increased to $111.6 million or $14.52/BOE compared to $87.0 million or $12.26/BOE during the corresponding period in 2005. The increase in DDA&A per BOE is due to increased plant, property and equipment from acquisitions completed during the second half of 2005.
No impairment of the Fund's assets existed at March 31, 2006 using year-end reserves updated for acquisitions, divestitures and management's estimates of future prices.
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 that is recorded on the balance sheet is recovered through earnings over time.
For the three months ended March 31, 2006, a future income tax recovery of $1.7 million was recorded in income compared to a future income tax recovery of $29.6 million during the same period in 2005. This change is due to the combination of a future tax expense with respect to our U.S. operations and a change in estimate of royalty payments between the operating subsidiaries and the Fund.
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.
For the three months ended March 31, 2006, our U.S. operations incurred taxes (income and withholding) in the amount of $3.9 million. We did not have U.S. operations during the first quarter of 2005 therefore no amount was recorded. The amount of current taxes recorded throughout the year is dependant upon the timing of both capital expenditures and repatriation of funds to Canada. Although U.S. taxes as a percentage of funds flow were lower in the first quarter, we continue to expect current and income withholding taxes will be approximately 20% of funds flow from U.S. operations on an annual basis.
SELECTED FINANCIAL RESULTS Three months ended March 31, Per BOE of production (6:1) 2006 2005 ------------------------------------------------------------------------- Production per day 85,392 78,813 ------------------------------------------------------------------------- Weighted average sales price(1) $ 52.27 $ 42.55 Royalties (10.40) (8.78) Financial contracts (0.12) (7.41) Add back / (deduct): Non-cash financial contracts (2.86) 4.55 Operating costs (7.57) (6.98) General and administrative(2) (1.73) (1.18) Add back: Non-cash G&A expense (trust unit rights)(2) 0.15 0.09 Interest expense, net of interest and other income (0.89) (0.72) Foreign exchange (loss) gain (0.02) (0.04) Deduct: Non-cash foreign exchange loss 0.01 0.05 Capital taxes (0.18) (0.17) Current income tax (0.50) - Restoration and abandonment cash costs (0.40) (0.29) ------------------------------------------------------------------------- Funds flow from operations 27.76 21.67 Restoration and abandonment cash costs 0.40 0.29 Non-cash items: Depletion, depreciation, amortization and accretion (14.52) (12.26) Financial contracts 2.86 (4.55) G&A expense (trust unit rights)(2) (0.15) (0.09) Foreign exchange (0.01) (0.05) Future income tax recovery 0.22 4.18 ------------------------------------------------------------------------- Total net income per BOE $ 16.56 $ 9.19 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments (2) See trust unit rights incentive plan discussion in Note 1 SELECTED CANADIAN AND U.S. FINANCIAL RESULTS
The following table provides a geographical analysis of key financial results for the three months ended March 31, 2006. Prior period information has not been presented as we commenced operations in the U.S. on August 30, 2005.
(CDN$ millions, except per unit Three months ended March 31, 2006 amounts) Canada U.S. Total ------------------------------------------------------------------------- Daily Production Volumes Natural gas (Mcf/day) 265,354 5,411 270,765 Crude oil (bbls/day) 26,339 9,514 35,853 Natural gas liquids (bbls/day) 4,411 - 4,411 Total Daily Sales (BOE/day) 74,976 10,416 85,392 Pricing(1) Natural gas (per Mcf) $ 8.32 $ 8.61 $ 8.33 Crude oil (per bbl) $51.69 $64.93 $55.20 Natural gas liquids (per bbl) $50.57 - $50.57 Capital Expenditures Development capital and office $102.0 $ 27.5 $129.5 Acquisitions of oil and gas properties $ 15.4 $ 14.6 $ 30.0 Dispositions of oil and gas properties $(19.7) - $(19.7) Revenues Oil and gas sales(1) $348.0 $ 59.8 $407.8 Royalties(2) $(68.6) $(11.4) $(80.0) Financial contracts $ (0.9) - $ (0.9) Expenses Operating $ 56.5 $ 1.7 $ 58.2 General and administrative $ 12.5 $ 0.8 $ 13.3 Depletion, depreciation, amortization and accretion $ 85.7 $ 25.9 $111.6 Current income taxes - $ 3.9 $ 3.9 ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. (2) Royalties include U.S. state production tax. FUNDS FLOW FROM OPERATIONS AND NET INCOME
Funds flow from operations for the three months ended March 31, 2006 was $213.3 million or $1.80 per trust unit compared to $153.7 million or $1.47 per trust unit for the three months ended March 31, 2005. The increase in funds flow from operations was primarily a result of higher production and commodity prices, offset by higher operating and G&A costs during the first quarter of 2006 compared to 2005.
Net income for the first quarter of 2006 was $127.3 million or $1.08 per trust unit compared to $65.2 million or $0.63 per trust unit for the first quarter of 2005. The increase in net income was largely due to more favourable commodity prices, higher production and a non-cash gain (versus a non-cash cost in 2005) on the fair market value of our financial contracts. This was partially offset by increased royalties, depletion and operating costs as well as a lower future income tax recovery.
QUARTERLY FINANCIAL INFORMATION
Generally, oil and gas revenues have increased due to higher commodity prices and production, offset by an increased Canadian/U.S. dollar exchange rate. Production increases can be attributed to our acquisitions and development capital program during the last two years. Oil and gas revenues decreased from the fourth quarter of 2005 to the first quarter of 2006 largely due to lower natural gas prices. Net income has been affected by fluctuations in oil and gas sales, changes in cash and non-cash risk management costs, the strengthening Canadian dollar and inflationary increases associated with the high level of industry activity.
Quarterly Financial Net income Information per trust unit ($ millions, except Oil and Gas Net ---------------------- per trust unit amounts) Revenue(1) Income Basic Diluted ------------------------------------------------------------------------- 2006 First quarter $401.7 $127.3 $1.08 $1.07 ------------------------------------------------------------------------- 2005(2) Fourth quarter $503.2 $150.9 $1.29 $1.28 Third quarter 398.7 107.1 0.97 0.97 Second quarter 320.0 108.8 1.04 1.04 First quarter 301.8 65.2 0.63 0.62 ------------------------------------------------- Total $1,523.7 $432.0 $3.96 $3.95 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2004 Fourth quarter $317.5 $114.5 $1.10 $1.10 Third quarter 302.2 50.6 0.49 0.49 Second quarter 265.6 48.0 0.51 0.51 First quarter 239.3 45.2 0.48 0.48 ------------------------------------------------- Total $1,124.6 $258.3 $2.60 $2.60 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments (2) See trust unit rights incentive plan discussion in Note 1 CASH AVAILABLE FOR DISTRIBUTION
Our payout ratio for the three months ended March 31, 2006 was 71%, the same as the corresponding period in 2005. During the first quarter of 2006, we funded $159.5 million in acquisitions and capital spending by withholding a portion of our cash available for distribution, additional debt and an equity issuance.
We continually monitor our distribution payout ratio with respect to forecasted funds flows, debt levels and spending plans. The level of cash withheld typically varies between 10% and 40% of annual funds flow. We are prepared to adjust the payout levels in an effort to balance the investor's desire for distributions with the Fund's requirement to maintain a prudent capital structure. The actual amount of cash withheld is dependant upon our current levels of production, the prevailing commodity price environment and the Board of Directors' discretion.
The following table reconciles Enerplus' funds flow from operations with the cash available for distribution to unitholders.
Reconciliation of Cash Available Three months ended for Distribution March 31, ($ millions, except per unit amounts) 2006 2005 ------------------------------------------------------------------------- Cash flow from operating activities $189.3 $130.3 Change in non cash working capital 24.0 23.4 ------------------------------------------------------------------------- Funds flow from operations 213.3 153.7 Cash withheld for acquisitions, capital expenditures and debt repayment(1) (61.1) (43.9) ------------------------------------------------------------------------- Cash available for distribution(2) $152.2 $109.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash available for distribution per trust unit $1.26 $1.05 Payout ratio 71% 71% ------------------------------------------------------------------------- (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
At March 31, 2006 our balance sheet remains strong with conservative debt levels of 0.6 times debt to trailing funds flow. This is a result of the current high commodity price environment, increased production, and our net proceeds of $240.3 million from our March 2006 equity issue, offset by our first quarter capital spending.
During the first quarter long-term debt, net of cash, decreased $123.9 million to $525.9 million, which is comprised of $194.5 million of bank indebtedness and $331.4 million of senior unsecured notes.
The following table provides certain key financial ratios for the Fund:
March 31, December 31, Financial Leverage and Coverage 2006 2005 ------------------------------------------------------------------------- Long-term debt to trailing funds flow 0.6x 0.8x Funds flow to interest expense 30.5x 30.8x Long-term debt to long-term debt plus equity 16% 21% ------------------------------------------------------------------------- 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).
There has been no change to our $850 million bank credit facility or our senior unsecured notes during the quarter. 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.
We anticipate that we will continue to have adequate liquidity to fund future working capital and planned capital expenditures during 2006 primarily through funds flow from operations and the proceeds of the March 2006 equity issue. Enerplus' capital budget for 2006 can be revised downward in the event of a significant commodity price downturn or a similar economic event.
TRUST UNIT INFORMATION
We had 122,232,000 trust units outstanding at March 31, 2006 compared to 104,586,000 trust units at March 31, 2005 and 117,539,000 at December 31, 2005. The weighted average basic number of trust units outstanding during the first quarter of 2006 was 118,221,000 (2005 - 104,269,000).
During the three months ended March 31, 2006, 323,000 trust units (2005 -
462,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights incentive plan. This resulted in $13.4 million (2005 - $14.6 million) of additional equity to the Fund. For further details see Note 4.
On March 20, 2006 we closed an equity offering for a total of 4,370,000 units at a price of $58.00 per unit for gross proceeds of $253.5 million ($240.3 million net of issuance costs). The proceeds of the offering were initially used to repay indebtedness under our credit facilities and will subsequently be used to fund development capital as well as other general corporate expenditures.
CANADIAN AND U.S. TAXPAYERS
Enerplus estimates that approximately 95% of cash distributions paid to Canadian and U.S. unitholders will be taxable and the remaining 5% will be treated as a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions that are dependent upon production, commodity prices and funds flow experienced throughout the year.
For U.S. taxpayers the taxable portion of the cash distribution is considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers this should be a "Qualified Dividend" eligible for the reduced tax rate.
In May 2006, Enerplus estimated its non-resident ownership to be approximately 71%.
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
(CDN$ thousands) (Unaudited) 2006 2005
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 1,265 $ 10,093
Accounts receivable 134,943 170,623
Deferred financial assets (Note 2) 31,578 49,874
Other current 22,454 26,751
-------------------------------------------------------------------------
190,240 257,341
Property, plant and equipment (Note 3) 3,689,539 3,650,327
Goodwill 221,847 221,234
Other assets 21,200 1,721
-------------------------------------------------------------------------
$ 4,122,826 $ 4,130,623
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 241,400 $ 316,875
Distributions payable to unitholders 51,367 49,367
Deferred credits (Note 2) 17,087 57,368
-------------------------------------------------------------------------
309,854 423,610
-------------------------------------------------------------------------
Long-term debt 527,129 659,918
Future income taxes 441,887 442,970
Asset retirement obligations 115,464 110,606
-------------------------------------------------------------------------
1,084,480 1,213,494
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 4) 3,665,481 3,410,614
Accumulated income 1,535,470 1,408,178
Accumulated cash distributions (2,459,950) (2,309,705)
Cumulative translation adjustment (12,509) (15,568)
-------------------------------------------------------------------------
2,728,492 2,493,519
-------------------------------------------------------------------------
$ 4,122,826 $ 4,130,623
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
Three months ended
(CDN$ thousands except per trust unit amounts) March 31,
(Unaudited) 2006 2005
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 407,838 $ 308,960
Royalties (79,971) (62,268)
Derivative instruments (Notes 2 and 5)
Financial contracts - qualified hedges - (2,892)
Other financial contracts (895) (49,649)
Interest and other income 1,335 808
-------------------------------------------------------------------------
328,307 194,959
-------------------------------------------------------------------------
Expenses
Operating 58,165 49,477
General and administrative 13,305 8,343
Transportation 6,112 7,159
Interest on long-term debt 8,163 5,921
Foreign exchange loss 154 313
Depletion, depreciation, amortization and
accretion 111,551 86,963
-------------------------------------------------------------------------
197,450 158,176
-------------------------------------------------------------------------
Income before taxes 130,857 36,783
Capital taxes 1,435 1,241
Current taxes 3,862 -
Future income tax recovery (1,732) (29,636)
-------------------------------------------------------------------------
Net Income $ 127,292 $ 65,178
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 1.08 $ 0.63
Diluted $ 1.07 $ 0.62
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)
Basic 118,221 104,269
Diluted 118,725 104,777
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED INCOME
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2006 2005
-------------------------------------------------------------------------
Accumulated income, beginning of period $ 1,408,178 $ 976,137
Net income 127,292 65,178
-------------------------------------------------------------------------
Accumulated income, end of period $ 1,535,470 $ 1,041,315
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2006 2005
-------------------------------------------------------------------------
Operating Activities
Net income $ 127,292 $ 65,178
Non-cash items add/(deduct):
Depletion, depreciation, amortization
and accretion 111,551 86,963
Financial contracts (Note 2) (21,985) 32,296
Foreign exchange loss 65 324
Trust unit rights incentive plan (Note 4) 1,187 662
Future income tax recovery (1,732) (29,636)
Asset retirement costs incurred (3,063) (2,046)
-------------------------------------------------------------------------
213,315 153,741
Increase in non-cash working capital (24,034) (23,382)
-------------------------------------------------------------------------
189,281 130,359
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue costs (Note 4) 253,680 14,587
Cash distributions to unitholders (150,245) (109,686)
Decrease in bank credit facilities (132,854) (22,946)
Decrease in non-cash financing working capital 2,000 164
-------------------------------------------------------------------------
(27,419) (117,881)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (129,560) (69,747)
Property acquisitions (30,027) (1,820)
Property dispositions 189 61,689
Increase in non-cash investing working capital (11,433) (2,600)
-------------------------------------------------------------------------
(170,831) (12,478)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash 141 -
-------------------------------------------------------------------------
Change in cash (8,828) -
Cash, beginning of period 10,093 -
-------------------------------------------------------------------------
Cash, end of period $ 1,265 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ 254 $ -
Cash interest paid $ 4,523 $ 2,385
CONSOLIDATED STATEMENTS OF ACCUMULATED CASH DISTRIBUTIONS
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2006 2005
-------------------------------------------------------------------------
Accumulated cash distributions,
beginning of period $ 2,309,705 $ 1,811,500
Cash distributions 150,245 109,686
-------------------------------------------------------------------------
Accumulated cash distributions, end of period $ 2,459,950 $ 1,921,186
-------------------------------------------------------------------------
-------------------------------------------------------------------------
ENERPLUS RESOURCES FUND
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars and thousands of units
except per unit amounts) (Unaudited)
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, 2005. 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, 2005.
The disclosures provided below are incremental to those included in the
2005 annual consolidated financial statements.
On October 1, 2005 the Fund retroactively adopted the fair value method
of accounting for the trust unit rights incentive plan to January 1,
2003. Under this method, the fair value of the rights is calculated on
the date in which fair value can reasonably be determined, generally
being the grant date. The impact of the adoption on our 2003 and 2004
reported earnings was not material and therefore those prior year
financial statements have not been restated. The 2005 impact was recorded
upon adoption. For comparison purposes the 2005 quarters have been
restated to reflect the fair value methodology. The impact on the first
quarter of 2005 was a decrease to general and administrative expenses
("G&A") of $2,986,000 and a decrease to contributed surplus of
$5,276,000.
2. DEFERRED FINANCIAL ASSETS AND DEFERRED CREDITS
Current Deferred Financial Assets ($ thousands)
-------------------------------------------------------------------------
Deferred financial assets as at December 31, 2005 $ 49,874
Amortization of deferred financial assets(1) (18,296)
-------------------------------------------------------------------------
Deferred financial assets as at March 31, 2006 $ 31,578
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the amortization of the fair value of financial contracts
on December 31, 2005 for which hedge accounting is no longer applied.
These deferred financial assets will be amortized over the remaining
lives of the associated financial contracts.
Current Deferred Credits ($ thousands)
-------------------------------------------------------------------------
Deferred credits as at December 31, 2005 $ 57,368
Change in fair value - other financial contracts(1) (40,281)
-------------------------------------------------------------------------
Deferred credits as at March 31, 2006 $ 17,087
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Changes in the fair value of financial contracts that do not qualify
for hedge accounting are taken into income during the period as other
financial contracts and reflected as an increase or decrease in the
deferred financial liability.
The following table summarizes the income statement effects of other
financial contracts:
Three months ended
March 31,
Other Financial Contracts ($ thousands) 2006 2005
-------------------------------------------------------------------------
Change in fair value $ (40,281) $ 31,290
Amortization of deferred financial assets 18,296 1,006
Realized cash costs, net 22,880 17,353
-------------------------------------------------------------------------
Other financial contracts $ 895 $ 49,649
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the three months ended March 31, 2006 the Fund realized cash costs
of $nil, net of gains and losses from financial contracts that qualified
as hedges compared to cash costs of $2,892,000 during the same period of
2005.
3. PROPERTY, PLANT AND EQUIPMENT
March 31, December 31,
($ thousands) 2006 2005
-------------------------------------------------------------------------
Property, plant and equipment $ 5,454,952 $ 5,306,137
Accumulated depletion, depreciation
and accretion (1,765,413) (1,655,810)
-------------------------------------------------------------------------
Net property, plant and equipment $ 3,689,539 $ 3,650,327
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development G&A of $3,208,000 (2005 - $2,508,000) is included
in property, plant and equipment ("PP&E") for the three months ended
March 31, 2006. Excluded from PP&E for the purpose of the depletion and
depreciation calculation is $49,328,000 (2005 - $36,134,000) related to
the Joslyn development project that has not yet commenced commercial
production.
4. FUND CAPITAL
(a) Unitholders' Capital
Trust Units
Authorized: Unlimited number of trust units
Three months ended Year ended
March 31, 2006 December 31, 2005
(thousands)
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance before Contributed
Surplus, beginning of
period 117,539 $ 3,407,567 104,124 $ 2,826,641
Issued for cash:
Pursuant to public
offerings 4,370 240,287 10,638 466,885
Pursuant to rights
plans 210 7,166 805 24,737
Trust unit rights
incentive plan
(non-cash) - exercised - 519 - 4,629
DRIP(x), net of
redemptions 113 6,227 339 15,613
Issued for acquisition
of corporate and
property interests
(non-cash) - - 1,633 69,062
-------------------------------------------------------------------------
122,232 3,661,766 117,539 3,407,567
Contributed Surplus
(Trust unit rights
incentive plan) - 3,715 - 3,047
-------------------------------------------------------------------------
Balance, end of period 122,232 $ 3,665,481 117,539 $ 3,410,614
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Distribution Reinvestment and Unit Purchase Plan
Three months Year ended
ended March 31, December 31,
Contributed surplus ($ thousands) 2006 2005
-------------------------------------------------------------------------
Balance, beginning of period $ 3,047 $ 4,636
Trust unit rights incentive plan
(non-cash) - exercised (519) (4,629)
Trust unit rights incentive plan
(non-cash) - expensed 1,187 3,040
-------------------------------------------------------------------------
Balance, end of period $ 3,715 $ 3,047
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On March 20, 2006 the Fund closed an equity offering of 4,370,000 units
at a price of $58.00 per unit for gross proceeds of $253,460,000
($240,287,000 net of issuance costs).
(b) Trust Unit Rights Incentive Plan
As at March 31, 2006, a total of 2,576,000 rights pursuant to the Trust
Unit Rights Incentive Plan ("Rights Plan") at an average exercise price
of $44.35 were outstanding. This represents 2.1% of the total trust units
outstanding of which 526,000 rights with an average exercise price of
$32.89 were exercisable. Under the Rights 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 three months ended March 31, 2006 reduced the
exercise price of the outstanding rights by $0.50 per trust unit
effective July 2006.
Activity for the rights issued pursuant to the Rights Plan is as follows:
Three months ended Year ended
March 31, 2006 December 31, 2005
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 2,621 $ 42.80 2,401 $ 34.33
Granted 198 56.55 1,125 53.07
Exercised (210) 34.07 (805) 30.72
Cancelled (33) 48.67 (100) 37.15
-------------------------------------------------------------------------
End of period 2,576 44.35 2,621 42.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable at
the end of the period 526 $ 32.89 643 $ 32.46
-------------------------------------------------------------------------
(1) Exercise price reflects grant prices less reduction in strike price
discussed above.
The Fund uses a binomial option-pricing model to calculate the estimated
fair value of rights under the plan. Non-cash compensation costs of
$1,187,000 ($0.01 per unit) related to the rights issued since January 1,
2003 have been charged to general and administrative expense during the
three months ended March 31, 2006 (2005 - $662,000, $0.01 per unit).
(c) Basic and Diluted per Trust Unit Calculations
Net income per trust unit has been determined based on the following:
Three months ended
March 31,
(thousands) 2006 2005
-------------------------------------------------------------------------
Weighted average units 118,221 104,269
Dilutive impact of rights 504 508
-------------------------------------------------------------------------
Diluted trust units 118,725 104,777
-------------------------------------------------------------------------
-------------------------------------------------------------------------
5. FINANCIAL INSTRUMENTS
The Fund's financial instruments presented on the balance sheet consist
of accounts receivable, other current assets, current liabilities and
long-term debt.
The carrying value of accounts receivable, current liabilities and
outstanding bank credit facility balances approximate their fair value.
Other current assets are comprised of prepaid expenses and marketable
securities. The marketable securities are carried on the balance sheet at
the lower of cost and fair value. The fair value of the marketable
securities at March 31, 2006 exceeded the cost of these securities by
$13,890,000. The Fund has US$54,000,000 of senior unsecured notes with
fixed rate debt and a fair value of $61,486,000 at March 31, 2006. In
addition, the Fund has US$175,000,000 of senior unsecured notes with
fixed rate debt that was converted to CDN$268,328,000 floating rate debt
through a cross-currency swap with a syndicate of financial institutions.
At March 31, 2006 the fair value of the senior unsecured note was
$210,379,000.
The estimated fair values have been determined based on available market
information and appropriate valuation methods. The actual amounts
realized may differ from these estimates.
(a) Derivative Financial Instruments
The Fund uses certain derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures. The fair
values of these instruments are based on an approximation of the amounts
that would have been paid to or received from counterparties to settle
the instruments outstanding as at March 31, 2006 with reference to
forward prices and market valuations provided by independent sources.
The fair values of derivative financial instruments are as follows:
Interest Rate and Cross Currency Swaps
The Fund has entered into interest rate swaps on $75,000,000 of notional
debt at rates varying from 3.97% to 4.12% before banking fees that are
expected to range between 0.60% and 1.15%. These interest rate swaps
mature between June 2006 and January 2007. The fair value of the
$75,000,000 interest rate swaps as at March 31, 2006 represents an
unrealized cost of $87,000. These swaps have been designated as hedges
for accounting purposes.
The fair value of the cross currency swap related to the US$175,000,000
senior unsecured notes as at March 31, 2006 represents an unrealized cost
of $66,128,000 whereas the fair value of the underlying debt instrument
as at March 31, 2006 represents an unrealized gain of $57,949,000. The
cross currency swap has been designated as a hedge for accounting
purposes.
Subsequent to March 31, 2006 the Fund entered into an interest rate swap
on $50,000,000 of notional debt at a rate of 4.607%. This swap is
effective June 2006 and matures June 2011. It has been designated as a
hedge for accounting purposes.
Crude Oil Instruments
The Fund has financial contracts in place on its crude oil production as
described below. Effective December 31, 2005, the Fund elected to stop
designating commodity contracts as qualified hedges.
The following table summarizes the Fund's crude oil risk management
positions at April 26, 2006:
WTI US$/bbl
--------------------------------------------
Daily
Volumes
bbls/day Sold Call Purchased Put Sold Put
-------------------------------------------------------------------------
Term
April 1, 2006 -
June 30, 2006
3-way option 1,500 $45.80 $31.50 $27.50
Put(x) 1,500 - $41.50 -
Put 1,500 - - $35.00
April 1, 2006 -
June 30, 2006
Costless Collar(x) 1,500 $35.35 $30.00 -
Costless Collar(x) 1,500 $37.00 $30.00 -
April 1, 2006 -
December 31, 2006
Put(x) 1,500 - $50.00 -
Put 1,500 - - $41.00
April 1, 2006 -
December 31, 2006
Put(x) 1,500 - $53.00 -
Put 1,500 - - $43.00
April 1, 2006 -
December 31, 2006
Put(x) 1,500 - $53.00 -
Put 1,500 - - $43.00
-------------------------------------------------------------------------
(x) Financial contracts that were treated as hedges during 2005, however
the Fund elected to stop designating these contracts as hedges as of
December 31, 2005.
The Fund did not enter into any new contracts in the first quarter of
2006.
Natural Gas Instruments
The Fund has physical and financial contracts in place on its natural gas
production as described below. Effective December 31, 2005, the Fund
elected to stop designating commodity contracts as qualified hedges.
The following table summarizes the Fund's natural gas risk management
positions at April 26, 2006:
AECO CDN$/Mcf
--------------------------------------------
Daily Fixed
Volumes Purchased Price
MMcf/day Sold Call Put Sold Put and Swaps
-------------------------------------------------------------------------
Term
April 1, 2006 -
October 31, 2006
Swap(x) 9.5 - - - $5.47
Swap(x) 4.8 - - - $5.25
Swap(x) 4.8 - - - $5.24
Swap(x) 4.8 - - - $5.28
April 1, 2006 -
October 31, 2006
Put(x) 9.5 - $7.38 - -
Put(x) 9.5 - $7.38 - -
Put(x) 9.5 - $7.38 - -
2006 - 2010
Physical (escalated
pricing) 2.0 - - - $2.52
-------------------------------------------------------------------------
(x) Financial contracts that were treated as hedges during 2005, however
the Fund elected to stop designating these contracts as hedges as of
December 31, 2005.
The Fund did not enter into any new contracts in the first quarter of
2006.
Electricity Instrument
The Fund has entered into an electricity swap contract that has fixed the
price of electricity on 5MWh of Alberta Power Pool electricity
consumption at $49.99/MWh from April 1, 2006 to December 31, 2006. This
has been designated as a cash flow hedge and the fair value of this
instrument as at March 31, 2006 is an unrealized gain of $382,000.
Proceeds or costs realized from the electricity hedge are recognized as
operating costs.
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund, including the Fund's Annual Information Form, is available under the Fund's profile on the SEDAR website at www.sedar.com and at www.enerplus.com.
This news release contains certain forward-looking statements, which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. Some of the forward-looking statements may be identified by words such as "expects", "anticipates", "believes", "projects", "plans" and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties. Such forward- looking statements necessarily involve known and unknown risks and uncertainties, which may cause Enerplus' actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things, changes in general economic, market and business conditions; changes or fluctuations in production levels, commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation, investment eligibility or investment criteria; Enerplus' ability to comply with current and future environmental or other laws; Enerplus' success at acquisition, exploitation and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Many of these risks and uncertainties are described in Enerplus' Annual Information Form and Enerplus' Management's Discussion and Analysis. Readers are also referred to risk factors described in other documents Enerplus files with the Canadian and U.S. securities authorities. Copies of these documents are available without charge from Enerplus. Enerplus disclaims any responsibility to update these forward- looking statements.
Eric P. Tremblay Senior Vice-President, Capital Markets >>
For further information
and a complete copy of the 2006 First Quarter Interim report, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com
To request a free copy of this organization's annual report, please go to http://www.newswire.ca and click on Tools for Investors.