TSX: ERF.un
NYSE: ERF
CALGARY, May 9 /CNW/ - Enerplus Resources Fund is pleased to announce that operating and financial results for the first quarter of 2008 are in line with expectations. Highlights for the quarter are as follows:
- On February 13, 2008, Enerplus closed the single largest acquisition
in our history - the $1.7 billion acquisition of Focus Energy Trust.
Enerplus now has a production weighting of just over 60% natural gas
and 40% crude oil and NGLs in its portfolio.
- Daily production volumes averaged 89,150 BOE/day reflecting the
additional volumes from Focus since February 13, 2008. Our
production volumes in March were approximately 100,000 BOE/day,
being the first full month including Focus production and an all-
time high for Enerplus. We continue to expect full year production
volumes to average 98,000 BOE/day with an exit rate of 100,000
BOE/day.
- Cash flow from operating activities was $256.2 million up 33%
over the same period last year on the strength of increased
commodity prices and production volumes.
- Cash distributions to unitholders were maintained at $0.42 per unit
per month ($1.26 per unit for the quarter) with a payout ratio of
75% versus 82% for the first quarter of 2007 after adjustments for
working capital. Based on existing commodity prices and current
distribution levels, we would expect our payout ratio will decrease
throughout the year.
- Our development capital program was one of the most active in our
history with total spending of approximately $126 million and
256 gross wells drilled. Over 50% of our development capital was
invested in oil properties however the majority of the wells drilled
were in our shallow natural gas resource play which offers a
significant number of low risk infill drilling locations.
- Our cash operating costs averaged $8.88/BOE during the quarter, up
from $8.53/BOE during the same period last year however we continue
to maintain our annual guidance of approximately $8.65/BOE.
- Cash general and administrative expenses decreased to $1.85/BOE
compared to $1.94/BOE during the first quarter of 2007.
- Our price risk management program generated cash gains of
$4.3 million on our natural gas contracts and cash losses of
$15.2 million on our crude oil contracts for a total cost of
$10.9 million for the quarter versus a gain of $7.9 million for the
same period in 2007.
- We continue to maintain a conservative use of debt as reflected by
our debt to trailing cash flow ratio of 1.0x.
SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS
The financial information presented for the first quarter 2008 includes the results of Focus Energy Trust from the date of closing February 13, 2008.
All amounts are stated in Canadian dollars unless otherwise specified. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading. Certain prior year amounts have been restated to reflect current year presentation. Readers are also urged to review the Management's Discussion & Analysis (MD&A) and Audited Financial Statements for more fulsome disclosure on our operations. These reports can be found on our website at www.enerplus.com, our SEDAR profile at www.sedar.com and as part of our SEC filings available on www.sec.gov.
SELECTED FINANCIAL RESULTS
For the three months ended March 31, 2008 2007
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Financial (000's)
Cash Flow from Operating Activities $ 256,216 $ 193,181
Cash Distributions to Unitholders(1) 192,358 157,671
Cash Withheld for Acquisitions and Capital
Expenditures 63,858 35,510
Net Income 121,394 107,873
Debt Outstanding (net of cash) 1,097,821 716,860
Development Capital Spending 126,262 109,952
Acquisitions 1,765,069 63,423
Divestments 2,122 -
Actual Cash Distributions paid to Unitholders $ 1.26 $ 1.26
Financial per Weighted Average Trust Units(2)
Cash Flow from Operating Activities $ 1.74 $ 1.57
Cash Distributions per Unit(1) 1.30 1.28
Cash Withheld for Acquisitions and Capital
Expenditures 0.44 0.29
Net Income 0.82 0.88
Payout Ratio(3) 75% 82%
Selected Financial Results per BOE(4)
Oil & Gas Sales(5) $ 62.10 $ 49.08
Royalties (11.57) (9.24)
Commodity Derivative Instruments (1.35) 1.01
Operating Costs (8.96) (8.55)
General and Administrative (1.85) (1.94)
Interest and Other Income and Foreign
Exchange (0.84) (1.32)
Taxes (1.18) (0.26)
Restoration and Abandonment (0.50) (0.42)
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Cash Flow from Operating Activities before
changes in non-cash working capital $ 35.85 $ 28.36
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Weighted Average Number of Trust Units
Outstanding Including Equivalent Exchangeable
Partnership Units (thousands) 147,482 123,282
Debt/Trailing 12 Month Cash Flow Ratio(6) 1.0x 0.8x
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SELECTED OPERATING RESULTS
For the three months ended March 31, 2008 2007
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Average Daily Production
Natural gas (Mcf/day) 307,746 275,714
Crude oil (bbls/day) 33,256 35,567
NGLs (bbls/day) 4,603 4,509
Total (BOE/day) 89,150 86,028
% Natural gas 58% 53%
Average Selling Price(5)
Natural gas (per Mcf) $ 7.52 $ 7.21
Crude oil (per bbl) 86.02 57.26
NGLs (per bbl) 69.75 44.09
US$ exchange rate 1.00 0.85
Net Wells drilled 125 40
Success Rate 100% 98%
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(1) Calculated based on distributions paid or payable. Cash distributions
per unit may not correspond to the actual cash distributions to
unitholders of $1.26 as a result of using the weighted average trust
units outstanding for the period.
(2) Based on weighted average trust units outstanding for the period,
including the exchangeable partnership units assumed through the
Focus Energy Trust acquisition.
(3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
from Operating Activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(6) Including the trailing 12 month cash flow of Focus Energy Trust.
TRUST UNIT TRADING SUMMARY TSX - ERF.un NYSE - ERF
for the three months ended March 31, 2008 (CDN$) (US$)
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High $ 44.75 $ 44.31
Low $ 34.02 $ 32.59
Close $ 44.65 $ 43.40
2008 CASH DISTRIBUTIONS PER TRUST UNIT CDN$ US$
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Production Month Payment Month
January March $ 0.42 $ 0.41
February April 0.42 0.42
March May 0.42 0.41*
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First Quarter Total $ 1.26 $ 1.24
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* Calculated using an Canadian/US$ exchange rate of 1.02
2008 PRODUCTION AND DEVELOPMENT ACTIVITY
As at March 31, 2008 Production Capital Wells Drilled*
Volumes Spending --------------------
Play Type (BOE/day) ($millions) Gross Net
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Shallow Gas & CBM 20,627 $ 22.4 149 92.0
Crude Oil Waterfloods 14,784 17.2 22 10.5
Deep Tight Gas 11,937 22.9 28 4.0
Bakken Oil 10,878 19.6 4 3.1
Other Conventional
Oil & Gas 30,924 22.7 53 15.2
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Total Conventional 89,150 $104.8 256 124.8
Oil Sands
Kirby - 20.6 - -
Joslyn - .7 - -
Laricina - .2 - -
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Total Oil Sands - $ 21.5 - -
Total 89,150 $126.3 256 124.8
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* Drilling totals to do not include the delineation wells drilled
during the quarter at Kirby
Success Rate To Date: 100%
OPERATIONS UPDATE
Our Canadian drilling program employed as many as 17 drilling rigs and 20 service rigs in our operations including those dedicated to our Kirby delineation program throughout the quarter. Our U.S. operations also had 2 drilling rigs and 6 - 7 service rigs in use through the quarter. While modest savings were realized on day rates for drilling rigs, labour, steel and service costs have not abated.
With the recent strengthening in natural gas prices and the additional working interests in the Shackleton property acquired from Focus, we have increased our activities in our shallow gas resource play. During the quarter, Enerplus drilled almost 150 shallow gas wells, the majority of which were in the Countess and Verger area taking the well density to 16 wells per section. At Shackleton, a total of 41 Milk River natural gas wells were drilled during the quarter (including Enerplus and Focus activity) and booster compression was installed in the Miry Bay area. In addition, a total of 24 existing wells were recompleted to add reserves and production from the Milk River interval as well.
At Tommy Lakes, the winter drilling program was completed with a total of 17 wells successfully drilled, completed and tied-in before spring break up with results in line with expectations. This was slightly more than originally planned by Focus.
Our crude oil development activities continue to benefit from the current strength in oil prices. Although the number of wells drilled is significantly less than in the shallow natural gas arena, the cost and productivity per well is considerably higher. Our conventional oil activities were focused at Routledge and Shorncliffe in Southeast Saskatchewan and our waterfloods at Pembina, Alberta and Virden, Manitoba.
Development activity in our Bakken resource play kept two drilling rigs active for most of the quarter drilling four additional third wells per section. We temporarily slowed our refrac program to concentrate on higher return optimization activities and expect to resume the refrac program in June. Through our current activities in the U.S., we expect to maintain production volumes in the range of 11,000 BOE/day throughout 2008 with targeted spending of $55 to $65 million. We continue to advance our development plans beyond 2008 and have identified opportunities which will help to maintain production in the coming years. We also continue to pursue growth opportunities in the U.S. which are outside of our existing areas.
UPDATE ON KIRBY OIL SANDS PROJECT
Development plans at our Kirby oil sands project continued throughout the first quarter with the execution of our winter delineation program. We drilled 55 core holes and 3 water source/disposal wells on the lease. Our preliminary review of the core hole samples is encouraging. We expect to use this new information in support of the initial development on this lease, a 10,000 bbl/day steam assisted gravity drainage ("SAGD") project, and will provide updated resources estimates for the lease once we have fully evaluated the results of this program. We continue to expect to file our regulatory application for the 10,000 bbl/day project in late fall of this year and will provide new capital estimates associated with the project as part of the application.
We are pleased to report that we have been successful in attracting experienced and talented personnel to our oil sands resource team over the past quarter and now have over 20 people dedicated exclusively to the Kirby oil sands project. Combined, we have over 130 years of oil sands experience and over 350 years of industry experience within the team including direct experience from most of the active SAGD projects in western Canada.
Strategic Review of Joslyn Lease
On March 25, 2008, we announced that we were commencing a review of strategic options regarding our 15% working interest in the Joslyn oil sands lease ("Joslyn"). Joslyn is located in the Athabasca oil sands fairway in northeastern Alberta and consists of both mining and SAGD development projects. Our oil sands portfolio is comprised of three principal investments: a 100% working interest in the operated Kirby SAGD project a 15% non-operated working interest in the Joslyn mining and SAGD project; and a 12% equity investment and minor joint venture participation with Laricina Energy Ltd., ("Laricina") a private oil sands company pursuing SAGD projects in Alberta.
A strategic review of our portfolio of oil sands and conventional projects has resulted in the decision to consider options to rebalance our portfolio. Enerplus' low risk, distribution-oriented business model necessitates a portfolio of assets that provide near-term cash flow, future growth potential and an appropriate balance of commodities. Managing the future capital requirements of the portfolio while maintaining financial flexibility is critical to the long-term success of Enerplus. While we believe that both Joslyn and Kirby provide attractive long-term potential, the operated nature of the Kirby project provides enhanced control over the timing and nature of our capital spending profile. In addition, there are more SAGD opportunities within Canada for future growth and SAGD is better suited to our technical competencies and business model.
Should the strategic review result in a decision to sell all or a portion of Joslyn, sale proceeds would initially be used to reduce our current bank debt.
GREENHOUSE GAS EMISSIONS REGULATIONS
Enerplus continues to monitor and evaluate the developments associated with carbon emissions regulations associated with environmental policy and legislation in all jurisdictions where we operate. In particular, we are currently reviewing the Government of Canada's "Turning the Corner" plan and will continue to evolve our strategies and responses to the plan. Draft regulations under the plan are expected to be published in the latter half of this year for public comment. Under the proposed plan, the oil and gas industry will be required to reduce its emissions intensity from 2006 levels by 18% by 2010 and 2% every following year. The proposed federal regulations also require oil sands upgraders and in-situ projects to meet certain carbon capture and storage targets by 2018. Given Enerplus' interest in various oil sands development areas (Kirby, Joslyn and Laricina), we will be closely monitoring the development of the proposed federal regulations.
In January, 2008, the Government of Alberta released its new climate change strategy. The Alberta strategy focuses on the three areas of carbon capture and storage, conserving and using energy more efficiently and "greening" energy production. The provincial government will be providing updates as to its specific plans for implementation of various portions of its strategy. Certain climate change regulations came in to effect in Alberta on July 1, 2007 which set an emissions level of 100,000 tonnes/year to be considered a "large final emitter" (under Alberta regulations). Enerplus does not have any operated facilities that meet this level; however, we do participate in a small number of partner-operated facilities that fall into this category. We also anticipate that our proposed Kirby project would fit this classification once operational. We will be evaluating carbon capture and storage alternatives for our Kirby development as a normal course of business.
We will be working with government at all levels where we have operations to assist in the development of regulatory design in an effort to strike a productive balance between environment responsibility and continued positive economic impact.
APPOINTMENT OF NEW U.S. PRESIDENT OF OPERATIONS
I am also pleased to announce that Mr. Dana Johnson has joined the Enerplus executive group as the President, U.S. Operations. Mr. Johnson brings over 25 years of oil and gas industry experience, the majority of which has been spent in the United States with Quicksilver Resources Inc. and Shell Exploration and Production Company. His background in both conventional and unconventional plays throughout Canada and the U.S. will be a tremendous asset to Enerplus in leading this operating division. Larry Hammond and Ray Daniels will continue to lead our Canadian conventional and oil sands divisions respectively.
THE FUTURE
While the oil and gas industry faces many challenges we believe there are also many opportunities in front of us. We continue to be committed to the long-term success of our business and are focused on improving our operations to the benefit of our unitholders. We believe that our unitholders have invested in Enerplus because of their desire for income. We plan to manage our business in order to provide that income today, tomorrow and beyond 2010 when the Canadian federal income trust tax is implemented. We will look to maximize our cash flow and provide an attractive yield to our investors through the effective use of our tax pools and our development capital expenditures. Our current balance sheet strength, the opportunities within our asset base and our technical expertise positions Enerplus for future success.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated May 8, 2008 and is to be read in conjunction with:
- the audited consolidated financial statements as at and for the years
ended December 31, 2007 and 2006; and
- the unaudited interim consolidated financial statements as at and for
the three months ended March 31, 2008 and 2007.
All amounts are stated in Canadian dollars unless otherwise specified. All references to GAAP refer to Canadian generally accepted accounting principles. All note references relate to the notes included with the consolidated financial statements. In accordance with Canadian practice revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. In addition to disclosing reserves under the requirements of NI 51-101, we also disclose our reserves on a company interest basis which is not a term defined under NI 51-101. This information may not be comparable to similar measures presented by other issuers. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading.
The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our disclaimer on forward-looking information and statements.
NON-GAAP MEASURES
Throughout the MD&A we use the term "payout ratio" to analyze operating performance, leverage and liquidity. We calculate payout ratio by dividing cash distributions to unitholders ("cash distributions") by cash flow from operating activities ("cash flow"), both of which appear on our consolidated statements of cash flows. The term "payout ratio" does not have a standardized meaning or definition as prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other entities.
Refer to the Liquidity and Capital Resources section of the MD&A for further information on cash flow, cash distributions and payout ratio.
OVERVIEW
On February 13, 2008 we successfully closed the largest transaction in our 22 year history, acquiring Focus Energy Trust ("Focus") for total consideration of $1.7 billion including approximately $357 million of assumed debt and working capital. The results of the quarter include the results of Focus from the date of closing. The integration of Focus is progressing well. The drilling programs at Tommy Lakes and Shackleton are on schedule. We retained approximately 88% of the Focus staff, excluding executives, and the offices have been successfully integrated.
Overall production was in-line with expectations although operating costs were slightly higher than anticipated due to optimization work in the United States and pipeline and facility issues on some non-operated Canadian properties. Our development capital spending in the first quarter of 2008 was on target as we successfully integrated and completed both the Focus and Enerplus first quarter development capital spending programs. In total we spent $126.3 million and drilled 125 net wells with a 100% success rate.
Cash flow from operating activities increased 33% to $256.2 million in the first quarter of 2008 compared to the same period in 2007. The increase was due to higher realized crude oil and natural gas prices along with increased production as a result of the Focus acquisition. The higher commodity prices increased our price risk management program costs as we incurred cash losses of $10.9 million and non-cash losses of $79.4 million due to higher forward commodity prices at quarter end.
We maintained our monthly cash distributions at $0.42 per unit during the first quarter with a payout ratio of 75% and our debt-to-cash flow remains at a conservative 1.0x (including both Enerplus' and Focus' trailing twelve month cash flow).
We continue to maintain our 2008 guidance targets of $580 million on development capital spending, operating costs of $8.65/BOE, G&A costs of $2.20/BOE, annual average production rate of 98,000 BOE/day and an exit production rate of 100,000 BOE/day.
RESULTS OF OPERATIONS
Production
Production in the first quarter of 2008 was in-line with our expectations averaging 89,150 BOE/day. March was the first full month of production from both Enerplus and Focus and the combined production averaged approximately 100,000 BOE/day.
On November 30, 2007 we experienced a fire at our Giltedge property that resulted in shut-in production of approximately 2,000 BOE/day that was not expected to be back on-line until mid-2008. We were able to bring a portion of the Giltedge production (460 BOE/day) back on-line earlier than expected in the first quarter of 2008. Successful waterflood activities at our Medicine Hat Glauconitic C property and optimization activities at our U.S. properties also resulted in higher than expected production during the quarter.
These increases were partially offset by lower production of approximately 200 BOE/day at Bantry North due to regulatory issues at two non-operated facilities during March. We worked closely with the operator and regulator and were able to resolve these issues subsequent to the quarter. We also had unplanned downtime at our non- operated Mitsue property and operated Chinchaga property resulting in shut-in production of approximately 700 BOE/day for the first quarter, however both Mitsue and Chinchaga were brought back on-line at the end of March.
Production volumes in the first quarter of 2008 were 4% higher than the first quarter of 2007 volumes of 86,028 BOE/day. Incremental production from the Focus assets beginning February 13, 2008 more than offset the production interruptions experienced at our Giltedge, Bantry, Mitsue and Chinchaga properties.
Average production volumes for the three months ended March 31, 2008 and 2007 are outlined below:
Three months ended March 31,
Daily Production Volumes 2008 2007 % Change
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Natural gas (Mcf/day) 307,746 275,714 12%
Crude oil (bbls/day) 33,256 35,567 (6%)
Natural gas liquids (bbls/day) 4,603 4,509 2%
Total daily sales (BOE/day) 89,150 86,028 4%
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Based on the results of our first quarter we continue to expect 2008 annual production volumes to average 98,000 BOE/day and our 2008 exit rate to be approximately 100,000 BOE/day.
Pricing
The prices received for our natural gas and crude oil production directly impact our earnings, cash flow and financial condition. The following table compares our average selling prices for the three months ended March 31, 2008 and 2007. It also compares the benchmark price indices for the same periods.
Three months ended March 31,
Average Selling Price(1) 2008 2007 % Change
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Natural gas (per Mcf) $ 7.52 $ 7.21 4%
Crude oil (per bbl) 86.02 57.26 50%
Natural gas liquids (per bbl) 69.75 44.09 58%
Per BOE 62.09 49.08 27%
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(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Three months ended March 31,
Average Benchmark Pricing 2008 2007 % Change
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AECO natural gas - monthly index
(CDN$/Mcf) $ 7.13 $ 7.46 (4%)
AECO natural gas - daily index
(CDN$/Mcf) 7.90 7.41 7%
NYMEX natural gas - monthly NX3 index
(US$/Mcf) 8.07 6.96 16%
NYMEX natural gas - monthly NX3 index
CDN$ equivalent (CDN$/Mcf) 8.07 8.19 (1%)
WTI crude oil (US$/bbl) 95.39 58.23 64%
WTI crude oil: CDN$ equivalent
(CDN$/bbl) 95.39 68.51 39%
US$/CDN$ exchange rate 1.00 0.85 18%
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Both natural gas and crude oil prices rose significantly during the first quarter. In the case of natural gas, the winter started off with very weak natural gas prices and a consensus for mild weather. However, actual weather was colder than normal across most of North America and imports of LNG to the U.S. fell considerably year-over-year, resulting in upward pressure on price throughout the first quarter as storage inventories fell. During the quarter prices at AECO rose 35% from a low of $6.88/Mcf to a high of $9.32/Mcf.
We realized an average price on our natural gas of $7.52/Mcf (net of transportation costs) during the three months ended March 31, 2008, an increase of 4% from $7.21/Mcf for the same period in 2007. In comparison to the first quarter of 2007, the AECO monthly index price for natural gas decreased 4% and the AECO daily index price increased 7%. We sell the majority of our natural gas under both month and day AECO index contracts. Our realized natural gas price increase of 4% during the first quarter was comparable to the average change in the combined indices.
The West Texas Intermediate ("WTI") crude oil price fell during January and early February, reaching a low of US$86.99/bbl, but then climbed to a high of US$110.33/bbl, before settling at US$101.58/bbl on March 31, 2008. Subsequent to the quarter end, the WTI price has increased a further 15% to 20%. A key driver for the price increase has been demand for commodities, including crude oil futures, as a hedge against inflation. Fundamentals were also supportive as global demand continued to grow during the quarter.
The average price we received for our crude oil during the three months ended March 31, 2008 increased 50% to $86.02/bbl (net of transportation costs) from $57.26/bbl during the same period in 2007. In comparison, the WTI crude oil benchmark price, in Canadian dollars, increased 39% from the corresponding period in 2007. The relative strength in our sales price increase can be attributed in large part to the reduced Giltedge heavy crude production. As a result, heavy crude with its wide differential to WTI comprised a smaller portion of our overall volumes.
The Canadian dollar began the year at $0.99 per U.S. dollar, stronger than par, and fluctuated between $0.97 per U.S. dollar and $1.03 per U.S. dollar during the quarter. As a result of the Canadian dollar strengthening throughout 2007, the first quarter of 2008 average exchange rate increased 18% compared to the same period in 2007. As most of our crude oil and a portion of our natural gas are priced in reference to U.S. dollar denominated benchmarks, this movement in the exchange rate reduced the Canadian dollar prices that we would have otherwise realized.
Price Risk Management
We have developed a price risk management framework to respond to the volatile commodity price environment in a prudent manner. Consideration is given to our overall financial position together with the economics of our development capital program and acquisitions. Consideration is also given to the upfront costs of our risk management program as we seek to limit our exposure to price downturns while maintaining participation should commodity prices increase. Hedge positions for any given term are transacted across a range of prices and time. With respect to our natural gas and crude oil hedges for 2008, our overall hedge position was influenced both by existing Focus hedges and by the objective to protect the downside and assure cash flow certainty during the first year of this significant acquisition.
Given the above framework and objectives, we entered into additional commodity contracts during the first quarter of 2008. Considering all financial contracts transacted as of April 28, 2008, we have protected a portion of our natural gas price risk through to October 31, 2009 and a portion of our crude oil price risk through to December 31, 2009. We also have protected our exposure to rising electricity costs for some of our consumption in the Alberta power market through to December 31, 2009. See Note 9 for a list of our current price risk management positions.
The following is a summary of the financial contracts in place at April 28, 2008, including positions entered into by Focus, expressed as a percentage of our forecasted net production volumes:
Natural Gas
(CDN$/Mcf)
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April 1, November 1, April 1,
2008 - 2008 - 2009 -
October 31, March 31, October 31,
2008 2009 2009
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Floor Prices (puts) $ 7.09 $ 8.66 -
% (net of royalties) 25% 14% -
Fixed Price (swaps) $ 7.44 $ 9.35 $7.86
% (net of royalties) 20% 3% 1%
Capped Price (calls) $ 8.25 $ 11.24 -
% (net of royalties) 25% 11% -
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Crude Oil
(US$/bbl)
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April 1, July 1, January 1,
2008 - 2008 - 2009 -
June 30, December 31, December 31,
2008 2008 2009
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Floor Prices (puts) $ 71.43 $ 72.09 $ 81.36
% (net of royalties) 38% 35% 16%
Fixed Price (swaps) $ 79.95 $ 79.97 $ 100.05
% (net of royalties) 18% 19% 2%
Capped Price (calls) $ 85.09 $ 85.48 $ 92.98
% (net of royalties) 24% 22% 12%
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Based on weighted average price (before premiums), estimated average annual production of 98,000 BOE/day, and assuming for 2008 a 19% royalty rate. For 2009 we have assumed a 24% royalty rate reflecting the increased royalties for Alberta production at the current forward commodity price levels.
Accounting for Price Risk Management
During the first quarter of 2008 our price risk management program generated cash gains of $4.3 million on our natural gas contracts and cash losses of $15.2 million on our crude oil contracts. The natural gas cash gains are due to contracts in place that provided floor protection that was above market prices. The crude oil cash losses are the result of crude oil prices rising above our swap and sold call positions. In comparison, our first quarter of 2007 commodity price risk management program resulted in cash losses of $0.5 million on our natural gas contracts and cash gains of $8.4 million on our crude oil contracts.
At March 31, 2008 the fair value of our natural gas and crude oil derivative instruments, net of premiums, represent losses of $50.2 million and $77.9 million, respectively. The loss positions at March 31, 2008, which are due to forward natural gas and crude oil prices being above our sold call and swap positions, are recorded as current deferred financial credits on our balance sheet. In comparison, at December 31, 2007 the fair value of our natural gas and crude oil derivative instruments represented a gain of $9.7 million and a loss of $52.5 million respectively. Upon the closing of the Focus acquisition the fair value loss, included with the Focus assets, on both the natural gas derivative instruments of $1.6 million and crude oil derivative instruments of $4.3 million were recorded on our balance sheet. The change in the fair value of our derivative instruments during the quarter resulted in unrealized losses of $58.3 million for natural gas and $21.1 million for crude oil. As the forward markets for natural gas and crude oil fluctuate and new contracts are executed and existing contracts are realized, changes in fair value are reflected as a non-cash charge or non-cash gain in earnings. See Note 9 for details.
The following table summarizes the effects of our financial contracts on income.
Risk Management Gains/
(Losses)
($ millions, except per Three months ended Three months ended
unit amounts) March 31, 2008 March 31, 2007
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Cash (losses)/gains:
Natural Gas $4.3 $0.15/Mcf $(0.5) $(0.02)/Mcf
Crude Oil (15.2) (5.03)/bbl 8.4 2.63/bbl
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Total Cash (losses)/
gains $(10.9) $(1.35)/BOE $7.9 $1.01/BOE
Non-cash losses on
financial contracts:
Change in fair value
- natural gas $(58.3) $(2.08)/Mcf $(20.6) $(0.83)/Mcf
Change in fair value
- crude oil (21.1) (6.98)/bbl (12.9) (4.02)/bbl
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Total non-cash losses $(79.4) $(9.79)/BOE $(33.5) $(4.32)/BOE
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Total losses $(90.3) $(11.14)/BOE $(25.6) $(3.31)/BOE
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Cash Flow Sensitivity
The sensitivities below reflect the impact on cash flow per trust unit for the remaining three quarters of 2008 and include the commodity contracts described in Note 9 as well as the impact of 2008 forward market prices as at April 21, 2008. To the extent the market price of crude oil and natural gas change significantly from the April 21, 2008 levels, the sensitivities will no longer be relevant as the effect of our commodity contracts will change.
Sensitivity Table Estimated Effect on 2008
Cash Flow per Trust Unit(1)
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Change of $0.15 per Mcf in the price
of AECO natural gas $0.06
Change of US$1.00 per barrel in
the price of WTI crude oil $0.04
Change of 1,000 BOE/day in production $0.10
Change of $0.01 in the US$/CDN$ exchange rate $0.10
Change of 1% in interest rate $0.05
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(1) Assumes constant working capital and 160,147,000 units outstanding.
The impact of a change in one factor may be compounded or offset by
changes in other factors. This table does not consider the impact of
any inter-relationship among the factors.
Revenues
Crude oil and natural gas revenues for the three months ended March 31, 2008 were $503.7 million ($510.0 million, net of $6.3 million of transportation costs), an increase of 33% or $123.7 million compared to $380.0 million ($385.9 million, net of $5.9 million of transportation costs) in the first quarter 2007. Increased gas production as a result of the Focus acquisition and substantially higher crude oil prices were the primary reasons for the higher revenues.
Analysis of Sales Crude Natural
Revenue(1) ($ millions) oil NGLs Gas Total
-------------------------------------------------------------------------
Quarter ended March 31, 2007 $183.3 $ 17.9 $178.8 $380.0
Price variance(1) 87.0 10.7 12.4 110.1
Volume variance (10.0) 0.6 23.0 13.6
-------------------------------------------------------------------------
Quarter ended March 31, 2008 $260.3 $ 29.2 $214.2 $503.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Other Income
Other income for the three months ended March 31, 2008 was $15.1 million compared to $14.2 million for the three months ended March 31, 2007. During the first quarter of 2008 we realized a gain of $8.3 million on the sale of certain marketable securities, as well as interim payments for our business interruption insurance of $6.4 million related to the Giltedge fire. During the first quarter of 2007 we realized a gain of $14.1 million on the sale of certain marketable securities.
Royalties
Royalties are paid to various government entities and other land and mineral rights owners. For the three months ended March 31, 2008 and 2007 royalties were $93.8 million and $71.6 million respectively, approximately 19% of oil and gas sales, net of transportation costs. Overall, royalties increased primarily as a result of additional revenue from higher oil prices and the additional Focus assets acquired.
In October 2007, the Alberta government announced a 'New Royalty Framework' ("NRF") which will be effective January 1, 2009. In the context of an annualized 2008 forward market outlook of $110.00/bbl crude oil and $9.00/Mcf natural gas, and relative to Enerplus' current properties and production profile in Alberta, we estimate the incremental annual impact of the NRF to be approximately $90 to $100 million.
In April 2008, the Alberta government announced some changes to the NRF to encourage the development of deep, high-cost oil and gas reserves. These programs will be implemented on January 1, 2009 along with the NRF. These new programs are not expected to have a significant effect on our 2008 capital plans. Had these new programs been in place during 2007, approximately 23 gross (5 net) of Enerplus' natural gas wells drilled in 2007 would have qualified for potential royalty credits totaling $0.8 million. Our crude oil wells would not have been affected.
We continue to expect royalties to be approximately 19% of oil and gas sales, net of transportation costs for 2008. In 2009 given current commodity prices, we estimate the average royalty rate for the Fund including all royalties will be approximately 24% of oil and gas sales, net of transportation costs.
As at the date of this MD&A the Alberta government had not yet made the necessary legislative and administration changes to implement the NRF. The NRF announcement can be found on the Alberta government's website at www.gov.ab.ca.
Operating Expenses
Operating expenses for the three months ended March 31, 2008 were $8.88/BOE or $72.0 million, compared to $8.53/BOE or $66.0 million for the same period in 2007. Excluding the non-cash gain included in operating expenses related to our electricity swaps, operating costs were $8.96/BOE compared to $8.55/BOE for the same period in 2007. We had higher operating costs at our Mitsue and Chinchaga properties due to costs associated with pipeline and facility issues along with additional optimization expenses onour U.S. properties. Partially offsetting these increases was the addition of lower operating cost properties from Focus beginning February 13, 2008.
We are maintaining our annual guidance for operating costs of approximately $8.65/BOE.
General and Administrative Expenses ("G&A")
During the first quarter of 2008 G&A expenses decreased 8% to $2.03/BOE or $16.4 million compared to $2.21/BOE or $17.1 million for the first quarter of 2007. Total cash G&A was relatively unchanged year-over-year, with higher overall salary and benefits costs offset by lower long term cash compensation charges which are impacted by our trust unit price.
During the quarter our G&A expenses included non-cash charges for our trust unit rights incentive plan of $1.5 million or $0.18/BOE compared to $2.1 million or $0.27/BOE for 2007. These amounts relate solely to our trust unit rights incentive plan and are determined using a binomial lattice option- pricing model. See Note 8 for further details.
The following table summarizes the cash and non-cash expenses recorded in G&A:
General and Administrative Costs Three months ended March 31,
($ millions) 2008 2007
-------------------------------------------------------------------------
Cash $ 14.9 $ 15.0
Trust unit rights incentive plan (non-cash) 1.5 2.1
-------------------------------------------------------------------------
Total G&A $ 16.4 $ 17.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2008 2007
-------------------------------------------------------------------------
Cash $ 1.85 $ 1.94
Trust unit rights incentive plan (non-cash) 0.18 0.27
-------------------------------------------------------------------------
Total G&A $ 2.03 $ 2.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We are maintaining our guidance for G&A expenses at $2.20/BOE, which includes non-cash G&A costs of approximately $0.20/BOE.
Interest Expense
Interest expense includes interest on long-term debt, the premium amortization on our US$175 million senior unsecured notes, unrealized gains and losses resulting from the change in fair value of our interest rate swaps as well as the interest component on our cross currency interest rate swap (see Note 6).
Interest on long-term debt for the three months ended March 31, 2008 totaled $13.3 million, a $3.6 million increase from $9.7 million during the comparable quarter of 2007. The increase was due to higher average indebtedness partially offset by a lower weighted average interest rate of 4.3% during the first three months of 2008 compared to 4.9% in the same period in 2007.
The following table summarizes the cash and non-cash interest expense recorded.
Interest Expense Three months ended March 31,
($ millions) 2008 2007
-------------------------------------------------------------------------
Interest on long-term debt $ 13.3 $ 9.7
Unrealized gain (6.3) (1.6)
-------------------------------------------------------------------------
Total Interest Expense $ 7.0 $ 8.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At March 31, 2008 approximately 12% of our debt was based on fixed interest rates while 88% had floating interest rates. In comparison, at March 31, 2007 approximately 19% of our debt was based on fixed interest rates and 81% was floating. The increased percentage of floating rate debt is due to the bank debt that was assumed with the Focus acquisition.
Capital Expenditures
During the first quarter of 2008 we spent $126.3 million on development capital and facilities, an increase of $16.3 million or 15% compared to the same period in 2007. The increase was largely due to the successful completion of Focus' original development capital program and drilling an additional two wells at Tommy Lakes. Our development capital program is expected to remain on target through the remainder of the year. To date we have achieved a 100% success rate with our drilling program on 125 net wells.
Property acquisitions during the three months ended March 31, 2008 were $7.5 million compared to $63.4 million during the three months ended March 31, 2007 which related primarily to the acquisition of gross-overriding royalty interests in the Jonah natural gas field in Wyoming. Our corporate acquisition of Focus closed during the quarter for consideration of approximately $1.7 billion. Refer to Note 4 for further details.
Total net capital expenditures of approximately $1.9 billion for the first quarter of 2008 compared to $174.8 million for the first quarter of 2007 are outlined below.
Three months ended March 31,
Capital Expenditures ($ millions) 2008 2007
-------------------------------------------------------------------------
Development expenditures $ 109.3 $ 90.8
Plant and facilities 17.0 19.2
-------------------------------------------------------------------------
Development Capital 126.3 110.0
Office 1.6 1.4
-------------------------------------------------------------------------
Sub-total 127.9 111.4
Acquisitions of oil and gas properties(1) 7.5 63.4
Corporate Acquisitions 1,757.5 -
Dispositions of oil and gas properties(1) (2.1) -
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 1,890.8 $ 174.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Capital Expenditures financed with
cash flow $ 63.9 $ 35.5
Total Capital Expenditures financed with
debt and equity 1,826.9 139.3
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 1,890.8 $ 174.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
We are maintaining our 2008 guidance of $580 million for annual development capital spending.
Oil Sands
Our Joslyn and Kirby development projects have not commenced commercial production. As a result all associated costs inclusive of acquisition expenditures, development capital spending, salaries and benefits, engineering and planning, net of revenues generated, are capitalized and excluded from our depletion calculation.
During the first quarter of 2008 we capitalized costs of $0.7 million related to Joslyn as we continued to build the steam chambers in producing wells and bring two wells back on production that had workovers completed at year end. At our Kirby project we capitalized approximately $20.6 million and were successful in completing our core hole drilling program drilling 55 core holes and 3 water source/disposal wells. At March 31, 2008 capitalized costs life-to-date for Joslyn were $117.1 million and for Kirby were $226.0 million for a combined total of $343.1 million.
On March 25, 2008 we announced that we are commencing a review of strategic options regarding our 15% working interest in Joslyn. A review of our portfolio of oil sands and conventional projects has resulted in the decision to consider options to rebalance the portfolio. Our distribution- oriented business model necessitates a portfolio of assets that provide near- term cash flow, future growth potential and an appropriate balance of commodities. While we believe that both Joslyn and Kirby provide attractive long-term potential, the operated nature of the Kirby project provides enhanced control over the timing and nature of our capital spending profile. Should the review result in a decision to sell all or a portion of Joslyn, sale proceeds would initially be used to reduce our outstanding bank debt. Given our conservative balance sheet, such sale proceeds would reinforce our borrowing capacity, enhance our ability to fund future capital spending and acquisition activity and minimize the need for future equity.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves.
For the three months ended March 31, 2008 DDA&A increased to $139.8 million or $17.23/BOE compared to $119.1 million or $15.38/BOE during the same period in 2007. The increase is primarily due to additional PP&E and production as a result of the Focus acquisition.
No impairment of the Fund's assets existed at March 31, 2008 using year- end reserves updated for acquisitions, divestitures and management's estimates of future prices.
Asset Retirement Obligations
In connection with our operations, we anticipate we will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. Total future asset retirement obligations are estimated by management based on the Fund's net ownership interest in wells and facilities, estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods.
The Fund has estimated the net present value of its total asset retirement obligations to be approximately $204.3 million at March 31, 2008 compared to $165.7 million at December 31, 2007. The increase of $38.6 million relates primarily to the acquisition of Focus. See Note 3.
The following chart compares the amortization of the asset retirement cost, accretion of the asset retirement obligation and asset retirement obligations settled during the period.
Three months ended March 31,
($ millions) 2008 2007
-------------------------------------------------------------------------
Amortization of the asset retirement cost $ 4.7 $ 3.4
Accretion of the asset retirement obligation 2.5 1.7
-------------------------------------------------------------------------
Total Amortization and Accretion $ 7.2 $ 5.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement Obligations Settled $ 4.0 $ 3.3
-------------------------------------------------------------------------
The timing of actual asset retirement costs will differ from the timing of amortization and accretion charges. Actual asset retirement costs will be incurred over the next 66 years with the majority between 2038 and 2047. For accounting purposes, the asset retirement cost is amortized using a unit-of- production method based on proved reserves before royalties while the asset retirement obligation accretes until the time the obligation is settled.
Taxes
Future Income Taxes
Future income taxes arise from differences between the accounting and tax basis of assets and liabilities. A portion of the future income tax liability that is recorded on the balance sheet will be recovered through earnings before 2011. The balance will be realized when future income tax assets and liabilities are realized or settled.
Our future income tax recovery was $35.2 million for the quarter ended March 31, 2008 compared to a recovery of $23.7 million for the same period in 2007. Approximately $10.7 million of the additional recovery is attributed to Focus and another $2.8 million relates to a British Columbia corporate income tax rate reduction which became effective during the quarter.
Current Income Taxes
In our current structure, payments are made between the operating entities and the Fund which ultimately transfers both the income and future tax liability to our unitholders. As a result, no cash income taxes have been paid by our Canadian operating entities, however an income tax liability of $24.3 million was triggered on the acquisition of Focus on February 13, 2008. This liability was included in Focus's assumed working capital and was paid in April 2008. We expect to recover these taxes over the next twelve months and as such we have recorded a cash income tax recovery of $2.7 million in first quarter of 2008.
The amount of current taxes recorded throughout the year on our U.S. operations is dependent upon income levels and the timing of both capital expenditures and the repatriation of funds to Canada. For the three months ended March 31, 2008 our U.S. operations incurred taxes (income and withholding) in the amount of $12.2 million compared to $2.0 million for the same period in 2007. The increase in current taxes was due to an increase in net income combined with a decrease in capital expenditures during the quarter.
We have increased our guidance by 5% for 2008 as we now expect our U.S. current income and withholding taxes to average approximately 25% of cash flow from U.S. operations. This guidance is based on current commodity prices, our current development capital program and assumes all funds in excess of U.S. development capital spending are repatriated to Canada.
Effective January 1, 2011 we will be subject to the Specified Investment Flow-Through ("SIFT") tax should we remain a trust. The Federal budget on February 26, 2008 proposed that for 2009 tax years and later the SIFT tax will be based on the general provincial corporate income tax rate in each province in which the SIFT has a permanent establishment. These proposals would result in a SIFT being taxed on the same basis as a corporation.
Net Income
Net income for the first quarter of 2008 was $121.4 million or $0.82 per trust unit compared to $107.9 million or $0.88 per trust unit in the same period for 2007. The $13.5 million increase in net income was primarily due to an increase in oil and gas sales of $124.2 million and an increase in future income tax recovery of $11.4 million offset by increased risk management costs of $64.8 million, increased royalties of $22.3 million and increased DDA&A of $20.7 million.
Cash Flow from Operating Activities
Cash flow for the three months ended March 31, 2008 was $256.2 million or $1.74 per trust unit compared to $193.2 million or $1.57 per trust unit for the same period in 2007. The increase in cash flow per unit is largely due to realizing a higher weighted average sales price on our crude oil and natural gas sales combined with an increase in production, offset by higher cash risk management costs, royalties and operating costs.
Selected Financial Results
Three months ended Three months ended
March 31, 2008 March 31, 2007
-----------------------------------------------------------
Non- Non-
Per BOE of Operating Cash & Operating Cash &
production Cash Other Cash Other
(6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production per day 89,150 86,028
-------------------------------------------------------------------------
Weighted
average
sales
price(2) $ 62.10 $ - $ 62.10 $ 49.08 $ - $ 49.08
Royalties (11.57) - (11.57) (9.12) - (9.12)
Commodity
derivative
instruments (1.35) (9.79) (11.14) 1.01 (4.32) (3.31)
Operating costs (8.96) 0.08 (8.88) (8.55) 0.02 (8.53)
General and
administrative (1.85) (0.18) (2.03) (1.94) (0.27) (2.21)
Interest
expense, net
of interest
and other
income (0.79) 0.77 (.02) (1.25) 0.21 (1.04)
Foreign
exchange
gain/(loss) (0.05) (0.39) (0.44) (0.07) 0.01 (0.06)
Capital taxes - - - (0.12) - (0.12)
Current income
tax (1.18) - (1.18) (0.26) - (0.26)
Restoration and
abandonment
cash costs (0.50) 0.50 - (0.42) 0.42 -
Depletion,
depreciation,
amortization
and accretion - (17.23) (17.23) - (15.38) (15.38)
Future income
tax recovery - 4.33 4.33 - 3.06 3.06
Gain on sale of
marketable
securities(3) - 1.02 1.02 - 1.82 1.82
-------------------------------------------------------------------------
Total per BOE $ 35.85 $(20.89) $ 14.96 $ 28.36 $(14.43) $ 13.93
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash Flow from Operating Activities before changes in non-cash
working capital.
(2) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(3) Gain on sale of marketable securities was a cash item however it is
included in cash flow from investing activities not cash flow from
operating activities.
Selected Canadian and U.S. Results
The following table provides a geographical analysis of key operating and
financial results for the three months ended March 31, 2008 and 2007.
(CDN$ millions, Three months ended Three months ended
except per March 31, 2008 March 31, 2007
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily
Production
Volumes
Natural gas
(Mcf/day) 295,799 11,947 307,746 266,050 9,664 275,714
Crude oil
(bbls/day) 23,734 9,522 33,256 25,330 10,237 35,567
Natural gas
liquids
(bbls/day) 4,603 - 4,603 4,509 - 4,509
Total Daily
Sales
(BOE/day) 77,637 11,513 89,150 74,180 11,848 86,028
Pricing(1)
Natural gas
(per Mcf) $ 7.47 $ 8.95 $ 7.52 $ 7.21 $ 7.29 $ 7.21
Crude oil
(per bbl) 84.31 90.30 86.02 54.94 62.99 57.26
Natural gas
liquids
(per bbl) 69.75 - 69.75 44.09 - 44.09
Capital
Expenditures
Development
capital and
office $108.3 $ 19.6 $127.9 $ 73.6 $ 37.8 $111.4
Acquisitions
of oil
and gas
properties 7.4 0.1 7.5 2.1 61.3 63.4
Dispositions
of oil
and gas
properties (2.1) - (2.1) - - -
Revenues
Oil and gas
sales(1) $415.7 $ 88.0 $503.7 $315.6 $ 64.4 $380.0
Royalties(2) (75.2) (18.6) (93.8) (58.9) (12.7) (71.6)
Financial
contracts (90.3) - (90.3) (25.6) - (25.6)
Expenses
Operating $ 68.6 $ 3.4 $ 72.0 $ 63.9 $ 2.1 $ 66.0
General and
adminis-
trative 15.1 1.3 16.4 14.8 2.3 17.1
Depletion,
depreciation,
amortization
and
accretion 118.4 21.4 139.8 91.5 27.6 119.1
Current income
taxes
(recovery)/
expense (2.7) 12.2 9.5 - 2.0 2.0
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) U.S. Royalties include state production tax.
Quarterly Financial Information
Oil and gas sales for the first quarter of 2008 increased over the fourth quarter of 2007 as crude oil and natural gas prices began to increase. Overall oil and gas sales were lower in 2007 from 2006 as a result of softening natural gas prices throughout 2006 and remained lower during 2007 as a result of lower production.
Net income has been affected by fluctuating commodity prices and risk management costs, the strengthening Canadian dollar, higher operating and G&A costs, changes in future tax provisions as well as changes to accounting policies adopted during 2007. Furthermore, changes in the fair value of all our financial derivative instruments (commodity, interest and foreign exchange) are impacted by future prices causing net income to fluctuate between quarters.
Quarterly Financial Information
($ millions, Net Income per trust unit
except per trust Oil and Gas -------------------------
unit amounts) Sales(1) Net Income Basic Diluted
-------------------------------------------------------------------------
2008
First quarter $ 503.7 $ 121.4 $ 0.82 $ 0.82
-------------------------------------------------------------------------
2007
Fourth Quarter $ 389.8 $ 98.7 $ 0.76 $ 0.76
Third Quarter 364.8 93.0 0.72 0.72
Second Quarter 382.5 40.1 0.31 0.31
First quarter 380.0 107.9 0.88 0.87
-------------------------------------------------
Total $ 1,517.1 $ 339.7 $ 2.66 $ 2.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006
Fourth Quarter $ 369.5 $ 110.2 $ 0.90 $ 0.89
Third Quarter 398.0 161.3 1.31 1.31
Second Quarter 403.5 146.0 1.19 1.19
First Quarter 401.7 127.3 1.08 1.07
-------------------------------------------------
Total $ 1,572.7 $ 544.8 $ 4.48 $ 4.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Liquidity and Capital Resources
Sustainability of our Distributions and Asset Base
As an oil and gas producer we have a declining asset base and therefore rely on ongoing development activities and acquisitions to replace production and add additional reserves. Our future oil and natural gas production is highly dependent on our success in exploiting our asset base and acquiring or developing additional reserves. To the extent we are unsuccessful in these activities our cash distributions could be reduced.
Development activities and acquisitions may be funded internally by withholding a portion of cash flow or through external sources of capital such as debt or the issuance of equity. To the extent that we withhold cash flow to finance these activities, the amount of cash distributions to our unitholders may be reduced. Should external sources of capital become limited or unavailable, our ability to make the necessary development expenditures and acquisitions to maintain or expand our asset base may be impaired and ultimately reduce the amount of cash distributions.
Following the completion of the Focus acquisition, Enerplus has approximately $10 billion of safe harbour growth capacity within the context of the Government's "normal growth" guidelines associated with Bill C-52. This amount is calculated in reference to the combined market capitalizations of Enerplus and Focus on October 31, 2006 and also includes equity that may be issued to replace existing debt of both entities at that time.
Distribution Policy
The amount of cash distributions is proposed by management and approved by the Board of Directors. We continually assess distribution levels with respect to forecasted cash flows, debt levels and capital spending plans. The level of cash withheld has historically varied between 10% and 40% of annual cash flow from operating activities and is dependent upon numerous factors, the most significant of which are the prevailing commodity price environment, our current levels of production, debt obligations, funding requirements for our development capital program and our access to equity markets.
Although we intend to continue to make cash distributions to our unitholders, these distributions are not guaranteed. To the extent there is taxable income at the trust level, determined in accordance with the Canadian Income Tax Act, the distribution of that taxable income is non-discretionary.
Cash Flow from Operating Activities, Cash Distributions and Payout Ratio
Cash flow from operating activities and cash distributions are reported on the Consolidated Statements of Cash Flows. During the first quarter of 2008 cash distributions of $192.4 million were funded entirely through cash flow of $256.2 million.
Our payout ratio, which is calculated as cash distributions divided by cash flow, was 75% for the three months ended March 31, 2008 compared to 82% for the same period in 2007.
In aggregate, our 2008 first quarter cash distributions of $192.4 million and our development capital and office expenditures of $127.9 million totaled $320.3 million, or approximately 125% of our cash flow of $256.2 million. We rely on access to capital markets to the extent cash distributions combined with development capital and office expenditures exceed cash flow. Over the long term we would expect to support our distributions and capital expenditures with our cash flow, however we would continue to fund acquisitions and growth through additional debt and equity. There will be years when we are investing capital in opportunities that do not immediately generate cash flow (such as our Joslyn and Kirby oil sands projects) where this relationship will vary. Despite our 2008 first quarter cash flow being less than the aggregate of our cash distributions and development capital, we continue to have conservative debt levels with a trailing twelve month debt-to-cash flow ratio of 1.0x at March 31, 2008.
For the three months ended March 31, 2008, our cash distributions exceeded our net income by $71.0 million (2007 - $49.8 million). Net income includes $181.7 million of non-cash items (2007 - $129.0 million) such as DDA&A, changes in the fair value of our derivative instruments based on forward markets, and future income taxes that do not reduce or increase our cash flow from operations. Future income taxes can fluctuate from period to period as a result of changes in tax rates as well as changes in interest, royalties and dividends from our operating subsidiaries paid to the Fund. In addition, other non-cash charges such as DDA&A are not a good proxy for the cost of maintaining our productive capacity as they are based on the historical costs of our PP&E and not the fair market value of replacing those assets within the context of the current environment.
The level of investment in a given period may not be sufficient to replace productive capacity given the natural declines associated with oil and natural gas assets. In these instances a portion of the cash distributions paid to unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net income.
Three months ended Year ended Year ended
($ millions, except March 31, December 31, December 31,
per unit amounts) 2008 2007 2006
-------------------------------------------------------------------------
Cash flow from operating
activities: $ 256.2 $ 868.5 $ 863.7
Cash distributions 192.4 646.8 614.3
-------------------------------------------------------------------------
Excess of cash flow over cash
distributions $ 63.8 $ 221.7 $ 249.4
Net income $ 121.4 $ 339.7 $ 544.8
Shortfall of net income over
cash distributions $ (71.0) $ (307.1) $ (69.5)
Cash distributions per weighted
average trust unit $ 1.30 $ 5.07 $ 5.05
Payout ratio(1) 75% 74% 71%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow from operating
activities.
It is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities in the oil and gas sector due to the nature of reserve reporting, natural reservoir declines and the risks involved with capital investment. Therefore we do not disclose maintenance capital separately from development capital spending.
Long-Term Debt
Long-term debt at March 31, 2008 was $1,099.3 million, an increase of $372.6 million from $726.7 million at December 31, 2007.
Long-term debt at March 31, 2008 is comprised of $860.9 million of bank indebtedness, which increased $363.5 million from December 31, 2007 and $238.4 million of senior unsecured notes. The increase in long-term debt is mainly due to the $330.9 million of debt that was assumed on the Focus acquisition along with debt incurred to fund our development capital program.
Our working capital deficiency, excluding cash, at March 31, 2008 increased $63.3 million to $266.7 million from $203.4 million at December 31, 2007. Excluding current deferred financial assets and credits and the related current future income taxes, our working capital deficiency increased by $1.0 million compared to December 31, 2007. The increase in accounts receivable that is attributable to higher commodity prices and production levels offset the increase in accounts payable that resulted from higher capital spending activity and increased distributions payable for units issued in conjunction with the Focus acquisition.
We continue to maintain a conservative balance sheet as demonstrated below:
March 31, December 31,
Financial Leverage and Coverage 2008 2007
-------------------------------------------------------------------------
Long-term debt to trailing cash flow 1.0 x(1) 0.8 x
Cash flow to interest expense 19.3 x(1) 25.8 x
Long-term debt to long-term debt plus equity 22% 22%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
Cash flow and interest expense are 12-months trailing.
(1) Includes both Enerplus' and Focus' 12 month trailing cash flows and
interest expense.
At March 31, 2008 Enerplus had a $1.4 billion unsecured covenant based three-year term bank facility ending November 2010, through its wholly-owned subsidiary EnerMark Inc. We have the ability to extend the facility each year or repay the entire balance at the end of the three-year term. This bank debt carries floating interest rates that we expect to range between 55.0 and 110.0 basis points over Bankers' Acceptance rates, depending on Enerplus' ratio of senior debt to earnings before interest, taxes and non-cash items.
Payments with respect to the bank facilities, senior unsecured notes and other third party debt have priority over claims of and future distributions to the unitholders. Unitholders have no direct liability should cash flow be insufficient to repay this indebtedness. The agreements governing these bank facilities and senior unsecured notes stipulate that if we default or fail to comply with certain covenants, the ability of the Fund's operating subsidiaries to make payments to the Fund and consequently the Fund's ability to make distributions to the unitholders may be restricted. At March 31, 2008 we are in compliance with our debt covenants, the most restrictive of which limits our long-term debt to three times trailing cash flow reflecting acquisitions on a pro forma basis. Refer to "Debt of Enerplus" in our Annual Information Form for the year ended December 31, 2007 for a detailed description of these covenants.
Principal payments on Enerplus' senior unsecured notes are required commencing in 2010 and 2011 and are more fully discussed in Note 5.
We anticipate that we will continue to have adequate liquidity to fund planned development capital spending during 2008 through a combination of cash flow retained by the business and debt, if needed.
Commitments
Upon the completion of the Focus acquisition we assumed an office lease with commitments of $0.9 million a year for 3 years and transportation contracts resulting in a total commitment of $40.0 million over a variety of terms the longest of which is 10 years. The Focus natural gas term transportation contracts comprise of 40 MMcf/day in British Columbia, and 65 MMcf/day in Saskatchewan.
Trust Unit Information
We had 164,142,000 trust units outstanding at March 31, 2008. This includes the 30,150,000 units issued on February 13, 2008 to acquire Focus and the 9,087,000 exchangeable partnership units outstanding that were assumed with the Focus acquisition which are convertible at the option of the holder into 0.425 of an Enerplus trust unit (3,862,000 trust units). This compares to 123,434,000 trust units at March 31, 2007 and 129,813,000 trust units outstanding at December 31, 2007. Including the exchangeable partnership units the weighted average basic number of trust units outstanding during the first quarter of 2008 was 147,482,000 (2007 - 123,282,000). At May 6, 2008 we had 164,420,000 trust units outstanding including the equivalent partnership units.
During the three months ended March 31, 2008 317,000 trust units (2007 - 283,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights incentive plan, net of redemptions. This resulted in $11.9 million (2007 - $13.0 million) of additional equity to the Fund. For further details see Note 8.
Canadian and U.S. Taxpayers
Enerplus estimates that approximately 95% of cash distributions paid to Canadian unitholders and 90% of cash distributions paid to U.S. unitholders will be taxable and the remaining 5% and 10% will be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are dependent upon, among other things, production, commodity prices and cash flow experienced throughout the year.
For U.S. taxpayers the taxable portion of cash distributions are considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers this should be a "Qualified Dividend" eligible for the reduced tax rate. This preferential rate of tax for "Qualified Dividends" is set to expire at the end of 2010. On March 24, 2007, Bill 1672 was introduced into the U.S. House of Representatives which, if enacted as presented, would make dividends from Canadian income funds such as Enerplus ineligible for treatment as a "Qualified Dividend". The dividends would then become a "non-qualified dividend from a foreign corporation" subject to the normal rates of tax commencing with dividends received after the date of enactment. The proposed bill still requires the approval of the House of Representatives, the Senate and the President prior to it being enacted. Therefore, we are unable to determine when or even if the bill will become enacted as presented.
In April 2008, Enerplus estimated its non-resident ownership to be approximately 65%.
Greenhouse Gas and Carbon Emissions
Enerplus continues to monitor and evaluate the developments associated with carbon emissions regulations associated with environmental policy and legislations in all jurisdictions where we operate. In particular, we are currently reviewing the Government of Canada's "Turning the Corner" plan and will continue to evolve our strategies and responses to the plan. Draft regulations under the plan are expected to be published in the latter half of this year for public comment. Under the proposed plan, the oil and gas industry will be required to reduce its emissions intensity from 2006 levels by 18% by 2010 and 2% every following year. The proposed federal regulations also require oil sands upgraders and in-situ projects to meet certain carbon capture and storage targets by 2018. Given Enerplus' interest in various oil sands development areas (Kirby, Joslyn and Laricina), we will be closely monitoring the development of the proposed federal regulations.
In January, 2008, the Government of Alberta released its new climate change strategy. The Alberta strategy focuses on the three areas of carbon capture and storage, conserving and using energy more efficiently and "greening" energy production. The provincial government will be providing updates as to its specific plans for implementation of various portions of its strategy. Certain climate change regulations came in to effect in Alberta on July 1, 2007 which set an emissions level of 100,000 tonnes/year to be considered a "large final emitter" (under Alberta regulations). Enerplus does not have any operated facilities that meet this level; however, we do participate in a small number of partner-operated facilities that fall into this category. We also anticipate that our proposed Kirby project would fit this classification once operational. We will be evaluating carbon capture and storage alternatives for our Kirby development as a normal course of business.
We will be working with government at all levels where we have operations to assist in the development of regulatory design in an effort to strike a productive balance between environment responsibility and continued positive economic impact. At this stage, without further clarity and specific details from the governments of Canada and Alberta, it is very difficult to forecast the increased costs associated with the proposed greenhouse gas and carbon capture regulations.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
Convergence of Canadian GAAP with International Financial Reporting
Standards
In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic plan that will result in Canadian GAAP, as used by public entities, being converged with International Financial Reporting Standards (IFRS) by 2011. On February 13, 2008 the AcSB confirmed that use of IFRS will be required for public companies beginning January 1, 2011. We continue to assess the impact of adopting IFRS and implementing plans for transition.
Internal Controls and Procedures
There were no changes in our internal control over financial reporting during the quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 1,453 $ 1,702
Accounts receivable 247,675 145,602
Deferred financial assets (Note 9) 1,102 10,157
Future income taxes 33,284 10,807
Other current 3,807 6,373
-------------------------------------------------------------------------
287,321 174,641
Property, plant and equipment (Note 2) 5,652,942 3,872,818
Goodwill (Note 4) 604,645 195,112
Other assets (Note 9) 49,966 60,559
-------------------------------------------------------------------------
$ 6,594,874 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 355,464 $ 269,375
Distributions payable to unitholders 68,939 54,522
Deferred financial credits (Note 9) 128,145 52,488
-------------------------------------------------------------------------
552,548 376,385
-------------------------------------------------------------------------
Long-term debt (Note 5) 1,099,274 726,677
Deferred financial credits (Note 9) 77,769 90,090
Future income taxes 696,183 304,259
Asset retirement obligations (Note 3) 204,327 165,719
-------------------------------------------------------------------------
2,077,553 1,286,745
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 8) 5,407,195 4,032,680
Accumulated deficit (1,354,917) (1,283,953)
Accumulated other comprehensive income (87,505) (108,727)
-------------------------------------------------------------------------
(1,442,422) (1,392,680)
3,964,773 2,640,000
-------------------------------------------------------------------------
$ 6,594,874 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Accumulated income, beginning of period $ 2,286,927 $ 1,952,960
Adjustment for adoption of financial
instruments standards - (5,724)
-------------------------------------------------------------------------
Revised accumulated income, beginning of
period 2,286,927 1,947,236
Net income 121,394 107,873
-------------------------------------------------------------------------
Accumulated income, end of period $ 2,408,321 $ 2,055,109
Accumulated cash distributions, beginning
of period $(3,570,880) $(2,924,045)
Cash distributions (192,358) (157,671)
-------------------------------------------------------------------------
Accumulated cash distributions, end of period $(3,763,238) $(3,081,716)
-------------------------------------------------------------------------
Accumulated deficit, end of period $(1,354,917) $(1,026,607)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Balance, beginning of period $(108,727) $ (8,979)
Transition adjustments on adoption:
Cash flow hedges - 660
Available for sale marketable securities - 14,252
Other comprehensive income/(loss) 21,222 (21,458)
-------------------------------------------------------------------------
Balance, end of period $ (87,505) $ (15,525)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(CDN$ thousands except Three months ended March 31,
per trust unit amounts) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 510,069 $ 385,871
Royalties (93,836) (71,565)
Commodity derivative instruments (Note 9) (90,379) (25,606)
Other income 15,116 14,160
-------------------------------------------------------------------------
340,970 302,860
-------------------------------------------------------------------------
Expenses
Operating 72,016 66,030
General and administrative 16,437 17,110
Transportation 6,317 5,864
Interest (Note 6) 6,988 8,115
Foreign exchange (Note 7) 3,684 482
Depletion, depreciation, amortization and
accretion 139,794 119,091
-------------------------------------------------------------------------
245,236 216,692
-------------------------------------------------------------------------
Income before taxes 95,734 86,168
Current taxes 9,541 2,047
Future income tax recovery (35,201) (23,752)
-------------------------------------------------------------------------
Net Income $ 121,394 $ 107,873
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 0.82 $ 0.88
Diluted $ 0.82 $ 0.87
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)(1)
Basic 147,482 123,282
Diluted 147,583 123,363
-------------------------------------------------------------------------
(1) Includes the exchangeable partnership units.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Net income $ 121,394 $ 107,873
-------------------------------------------------------------------------
Other comprehensive income/(loss),
net of tax:
Unrealized gain/(loss) on marketable
securities 2,578 (3,156)
Realized gains on marketable securities
included in net income (6,158) (11,654)
Gains and losses on derivatives designated
as hedges in prior periods included in net
income 74 (204)
Change in cumulative translation adjustment 24,728 (6,444)
-------------------------------------------------------------------------
Other comprehensive income/(loss) 21,222 (21,458)
-------------------------------------------------------------------------
Comprehensive income $ 142,616 $ 86,415
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Operating Activities
Net income $ 121,394 $ 107,873
Non-cash items add/(deduct):
Depletion, depreciation, amortization
and accretion 139,794 119,091
Change in fair value of derivative
instruments (Note 9) 66,472 34,847
Unit based compensation (Note 8) 1,486 2,111
Foreign exchange on translation of senior
notes (Note 7) 9,233 (2,882)
Future income tax (35,201) (23,752)
Amortization of senior notes premium (153) (169)
Reclassification adjustments from AOCI to
net income 92 (204)
Gain on sale of marketable securities (8,263) (14,055)
Asset retirement obligations settled (Note 3) (4,020) (3,314)
-------------------------------------------------------------------------
290,834 219,546
Increase in non-cash operating working capital (34,618) (26,365)
-------------------------------------------------------------------------
Cash flow from operating activities 256,216 193,181
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue costs
(Note 8) 11,885 13,020
Cash distributions to unitholders (192,358) (157,671)
Increase in bank credit facilities 32,602 100,342
Decrease in non-cash financing working capital 14,417 2,369
-------------------------------------------------------------------------
Cash flow from financing activities (133,454) (41,940)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (127,923) (111,354)
Property acquisitions (7,549) (63,423)
Property dispositions 2,122 -
Proceeds on sale of marketable securities 18,320 16,467
Increase in non-cash investing working capital (10,418) 6,130
-------------------------------------------------------------------------
Cash flow from investing activities (125,448) (152,180)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash 2,437 909
-------------------------------------------------------------------------
Change in cash (249) (30)
Cash, beginning of period 1,702 124
-------------------------------------------------------------------------
Cash, end of period $ 1,453 $ 94
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ 9,002 $ 3,241
Cash interest paid $ 8,318 $ 6,086
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
The interim consolidated financial statements of Enerplus Resources Fund
("Enerplus" or the "Fund") have been prepared by management following the
same accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2007. The
note disclosure requirements for annual statements provide additional
disclosure to that required for these interim statements. Accordingly,
these interim statements should be read in conjunction with the Fund's
consolidated financial statements for the year ended December 31, 2007.
With the exception of additional disclosures included in Note 9 regarding
financial instruments and capital management, the disclosures provided
below are incremental to those included in the 2007 annual consolidated
financial statements of the Fund.
2. PROPERTY, PLANT AND EQUIPMENT (PP&E)
March 31, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Property, plant and equipment $ 8,355,812 $ 6,429,241
Accumulated depletion, depreciation and
accretion (2,702,870) (2,556,423)
-------------------------------------------------------------------------
Net property, plant and equipment $ 5,652,942 $ 3,872,818
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development general and administrative ("G&A") expense of
$4,909,000 (2007 - $4,019,000) is included in PP&E for the three months
ended March 31, 2008. Excluded from PP&E for the depletion and
depreciation calculation is $343,073,000 (2007 - $90,678,000) related to
the Joslyn development project and the Kirby Oil Sands project, both of
which have not yet commenced commercial production.
3. ASSET RETIREMENT OBLIGATIONS
Following is a reconciliation of the asset retirement obligations:
Three months ended Year ended
March 31, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Asset retirement obligations, beginning
of period $ 165,719 $ 123,619
Corporate acquisition 36,784 -
Changes in estimates 1,500 46,000
Acquisition and development activity 1,927 6,441
Dispositions (110) (756)
Asset retirement obligations settled (4,020) (16,280)
Accretion expense 2,527 6,695
-------------------------------------------------------------------------
Asset retirement obligations, end of period $ 204,327 $ 165,719
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. ACQUISITIONS
Focus Energy Trust
On February 13, 2008 Enerplus closed the acquisition of Focus Energy
Trust ("Focus"). Under the plan of arrangement, Focus unitholders
received 0.425 of an Enerplus trust unit for each Focus trust unit and
Focus Exchangeable Partnership Units became exchangeable into Enerplus
trust units at the option of the holder on the basis of 0.425 of an
Enerplus trust unit for each Focus Exchangeable Partnership Unit. Total
consideration was approximately $1,366,494,000, consisting of 30,149,752
trust units issued, 9,086,666 exchangeable partnership units assumed
(convertible into 3,861,833 trust units) and estimated transaction costs
of $5,350,000. The Fund also assumed bank debt plus an estimated working
capital deficit, including certain transaction costs paid by Focus of
$357,305,000.
The acquisition has been accounted for using the purchase method of
accounting and results from the operations of Focus from February 13,
2008 onward have been included in the Fund's consolidated financial
statements. The allocation of the consideration paid to the fair value of
the assets acquired and liabilities assumed plus future income tax cost
are summarized below.
Net Assets Acquired ($ thousands)
-------------------------------------------------------------------------
Property, plant and equipment $ 1,757,520
Other assets 4,566
Goodwill 403,588
Working capital deficit (26,393)
Deferred financial credits (5,919)
Long-term debt (330,912)
Asset retirement obligations (36,784)
Future income taxes (399,172)
-------------------------------------------------------------------------
Total net assets acquired $ 1,366,494
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consideration paid ($ thousands)
-------------------------------------------------------------------------
Trust units issued(1) $ 1,206,593
Exchangeable partnership units assumed(1) 154,551
Transaction costs 5,350
-------------------------------------------------------------------------
Total consideration paid $ 1,366,494
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Recorded based on a fair value of $40.02 per trust unit
5. LONG-TERM DEBT
March 31, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Bank credit facilities (a) $ 860,863 $ 497,347
Senior notes (b)
US$175 million (issued June 19, 2002) 182,904 175,973
US$54 million (issued October 1, 2003) 55,507 53,357
-------------------------------------------------------------------------
Total long-term debt $ 1,099,274 $ 726,677
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus currently has a $1.4 billion unsecured covenant based three year
term facility. The facility is extendible each year with a bullet payment
required at the end of the three year term. Various borrowing options are
available under the facility including prime rate based advances and
bankers' acceptance loans. This facility carries floating interest rates
that are expected to range between 55.0 and 110.0 basis points over
bankers' acceptance rates, depending on Enerplus' ratio of senior debt to
earnings before interest, taxes and non-cash items. The effective
interest rate on the facility for the three months ended March 31, 2008
was 4.3% (March 31, 2007 - 4.9 %).
(b) Senior Unsecured Notes
On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes
that mature June 19, 2014. The notes have a coupon rate of 6.62% priced
at par, with interest paid semi-annually on June 19 and December 19 of
each year. Principal payments are required in five equal installments
beginning June 19, 2010 and ending June 19, 2014. Concurrent with the
issuance of the notes on June 19, 2002, the Fund entered into a cross
currency and interest rate swap ("CCIRS") with a syndicate of financial
institutions. Under the terms of the swap, the amount of the notes was
fixed for purposes of interest and principal repayments at a notional
amount of CDN$268,328,000. Interest payments are made on a floating rate
basis, set at the rate for three-month Canadian bankers' acceptances,
plus 1.18%.
On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes
that mature October 1, 2015. The notes have a coupon rate of 5.46% priced
at par with interest paid semi-annually on April 1 and October 1 of each
year. Principal payments are required in five equal installments
beginning October 1, 2011 and ending October 1, 2015. The notes are
translated into Canadian dollars using the period end foreign exchange
rate. In September 2007 Enerplus entered into foreign exchange swaps that
effectively fix the five principal payments on the US$54,000,000 senior
unsecured notes at a CAD/US exchange rate of 1.02 or CAD $55,080,000.
On January 1, 2007 in conjunction with the adoption of CICA Sections 3855
and 3865, Enerplus elected to stop designating the CCIRS as a fair value
hedge on the US$175,000,000 senior notes. As a result, the Fund recorded
the senior notes at their fair value of US$178,681,000. The premium
amount of US$3,681,000, representing the difference between the
January 1, 2007 fair value and the face amount of the senior notes, will
be amortized to net income over the remaining term of the notes using the
effective interest method. The effective interest rate over the remaining
term of the senior notes is 6.16%. The senior notes are carried at
amortized cost and are translated into Canadian dollars using the period
end foreign exchange rate. At March 31, 2008 the amortized cost of the
US$175,000,000 senior notes was US$177,940,000.
6. INTEREST EXPENSE
Three months ended March 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Realized
Interest on long-term debt $ 13,345 $ 9,748
Unrealized
Gain on cross currency interest rate swap (8,344) (1,283)
Loss on interest rate swaps 2,140 (181)
Amortization of the premium on senior
unsecured notes (153) (169)
-------------------------------------------------------------------------
Interest Expense $ 6,988 $ 8,115
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. FOREIGN EXCHANGE
Three months ended March 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Unrealized foreign exchange loss/(gain) on
translation of U.S. dollar denominated
senior notes $ 9,233 $ (2,882)
Unrealized foreign exchange (gain)/loss on
cross currency interest rate swap (4,171) 2,776
Unrealized foreign exchange (gain)/loss on
foreign exchange swaps (1,946) -
Realized foreign exchange loss 568 588
-------------------------------------------------------------------------
Foreign exchange loss $ 3,684 $ 482
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed
to foreign currency fluctuations and are translated into Canadian dollars
at the exchange rate in effect at the balance sheet date. Foreign
exchange gains and losses are included in the determination of net income
for the period.
8. UNITHOLDERS' CAPITAL
Unitholders' capital as presented on the Consolidated Balance Sheets
consists of trust unit capital, exchangeable partnership unit capital and
contributed surplus.
Three months ended Year ended
March 31, December 31,
Unitholders' capital ($ thousands) 2008 2007
-------------------------------------------------------------------------
Trust units $ 5,239,767 $ 4,020,228
Exchangeable partnership units 154,551 -
Contributed surplus 12,877 12,452
-------------------------------------------------------------------------
Balance, end of period $ 5,407,195 $ 4,032,680
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Trust Units
Authorized: Unlimited number of trust units
Three months ended Year ended
(thousands) March 31, 2008 December 31, 2007
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance, beginning of
period 129,813 $ 4,020,228 123,151 $ 3,706,821
Issued for cash:
Pursuant to public
offerings - - 4,250 199,558
Pursuant to rights
incentive plan 53 1,636 205 6,758
Trust unit rights
incentive plan (non-cash)
- exercised - 1,061 - 2,288
DRIP*, net of redemptions 264 10,249 1,102 50,053
Issued for acquisition of
corporate and property
interests (non-cash) 30,150 1,206,593 1,105 54,750
-------------------------------------------------------------------------
160,280 $ 5,239,767 129,813 $ 4,020,228
Equivalent exchangeable
partnership units 3,862 154,551 - -
-------------------------------------------------------------------------
Balance, end of period 164,142 $ 5,394,318 129,813 $ 4,020,228
-------------------------------------------------------------------------
-------------------------------------------------------------------------
* Distribution Reinvestment and Unit Purchase Plan
On February 13, 2008 the Fund issued 30,149,752 trust units pursuant to
the Focus acquisition valued at $40.02 per trust unit, being the weighted
average trading price of the Fund's units on the Toronto Stock Exchange
during the five day trading period surrounding the announcement date of
December 3, 2007, for a recorded value of $1,206,593,000.
(b) Exchangeable Partnership Units
In conjunction with the Focus acquisition 9,086,666 Focus Exchangeable
Limited Partnership Units became exchangeable into Enerplus trust units
at a ratio of 0.425 of an Enerplus trust unit for each Limited
Partnership unit (3,861,833 trust units). The exchangeable partnership
units are convertible at any time into trust units at the option of the