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CALGARY, May 9, 2008 (Canada NewsWire via COMTEX) -- TSX: ERF.un NYSE: ERF 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
-------------------------------------------------------------------------
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)
-------------------------------------------------------------------------
Cash Flow from Operating Activities before
changes in non-cash working capital $ 35.85 $ 28.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
SELECTED OPERATING RESULTS
For the three months ended March 31, 2008 2007
-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------
(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$)
-------------------------------------------------------------------------
High $ 44.75 $ 44.31
Low $ 34.02 $ 32.59
Close $ 44.65 $ 43.40
2008 CASH DISTRIBUTIONS PER TRUST UNIT CDN$ US$
-------------------------------------------------------------------------
Production Month Payment Month
January March $ 0.42 $ 0.41
February April 0.42 0.42
March May 0.42 0.41*
-------------------------------------------------------------------------
First Quarter Total $ 1.26 $ 1.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
* 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
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Total Conventional 89,150 $104.8 256 124.8
Oil Sands
Kirby - 20.6 - -
Joslyn - .7 - -
Laricina - .2 - -
-------------------------------------------------------------------------
Total Oil Sands - $ 21.5 - -
Total 89,150 $126.3 256 124.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
* 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
-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------
>>
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
-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------
(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
-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------
>>
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)
-------------------------------------------------------------------------
April 1, November 1, April 1,
2008 - 2008 - 2009 -
October 31, March 31, October 31,
2008 2009 2009
-------------------------------------------------------------------------
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% -
-------------------------------------------------------------------------
Crude Oil
(US$/bbl)
-------------------------------------------------------------------------
April 1, July 1, January 1,
2008 - 2008 - 2009 -
June 30, December 31, December 31,
2008 2008 2009
-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------
>>
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
-------------------------------------------------------------------------
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
------- -------
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
------- -------
Total non-cash losses $(79.4) $(9.79)/BOE $(33.5) $(4.32)/BOE
------- -------
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
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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
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Quarter ended March 31, 2008 $260.3 $ 29.2 $214.2 $503.7
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(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
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Total G&A $ 16.4 $ 17.1
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-------------------------------------------------------------------------
(Per BOE) 2008 2007
-------------------------------------------------------------------------
Cash $ 1.85 $ 1.94
Trust unit rights incentive plan (non-cash) 0.18 0.27
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Total G&A $ 2.03 $ 2.21
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>>
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
-------------------------------------------------------------------------
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>>
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
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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) -
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Total Net Capital Expenditures $ 1,890.8 $ 174.8
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Total Capital Expenditures financed with
cash flow $ 63.9 $ 35.5
Total Capital Expenditures financed with
debt and equity 1,826.9 139.3
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Total Net Capital Expenditures $ 1,890.8 $ 174.8
-------------------------------------------------------------------------
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(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
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>>
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
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Copyright (C) 2008 CNW Group. All rights reserved. ********************************************************************** As of Monday, 05-05-2008 23:59, the latest Comtex SmarTrend® Alert, an automated pattern recognition system, indicated an UPTREND Please read the End User Agreement. News provided by COMTEX |
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