TSX: ERF.un
NYSE: ERF
CALGARY, Aug. 7 /CNW/ - Enerplus Resources Fund is pleased to report one
of the most successful quarters in our operating history. Highlights are as
follows:
- Cash flow from operating activities was $364.5 million, up 53% over
the second quarter of 2007 due to strong commodity prices and record
production volumes.
- Cash distributions for the quarter were maintained at $0.42 per unit
per month ($1.26 per unit for the quarter) resulting in a payout
ratio of 56% versus 68% for the second quarter of 2007. Including our
development capital expenditures, our adjusted payout ratio for the
second quarter was approximately 80% indicating that our cash flow
was more than covering both distributions and capital spending.
- Given the strength in commodity prices, the performance of our
operations and the health of our balance sheet, we will be
increasing the monthly cash distribution to unitholders by 12%
to $0.47 per unit per month effective with the September
20, 2008 cash distribution payment.
- Daily production volumes averaged a record 100,188 BOE during the
quarter, reflecting the full integration of the Focus assets within
our portfolio, the earlier than expected return of our Giltedge
production and the continued success of our development capital
program.
- With the exception of a small increase in operating costs, we remain
on track to meet our operational guidance for 2008. We continue to
expect to produce an average of 98,000 BOE/day for the year with an
exit rate of 100,000 BOE/day.
- We have completed the analysis of the core holes drilled in our
winter delineation program on our Kirby oil sands lease. Preliminary
estimates from our third party reserves engineers indicate a revised
best estimate contingent resource of approximately 414 million
barrels, representing an increase of 170 million barrels (70%) over
our original estimate of 244 million barrels for the entire lease. We
continue to prepare our regulatory application for the first
10,000 bbl/day project and expect to file the application later this
fall.
- Subsequent to quarter end we successfully divested our working
interest in the Joslyn oil sands lease for net proceeds of
approximately $500 million compared to our investment of
approximately $115 million.
- We continue to maintain a conservative balance sheet with a
debt-to-cash flow ratio of approximately 0.4x after using the
Joslyn sale proceeds to pay down bank debt. The flexibility of a
strong balance sheet will allow us to continue to develop our
existing conventional resource plays, fully develop our growing
Kirby oil sands resource and pursue high quality acquisitions to add
accretive cash flow to our business.
- We realized an average sales price of $9.87/Mcf on our natural gas
production and approximately $114.04/bbl on our crude oil
production. These represent increases of 40% and 84% respectively
over the second quarter of 2007. With the increase in commodity
prices, we realized cash hedging losses of $64 million in the
quarter.
- We invested $88 million on our development program drilling 100 gross
wells. 60% of our expenditures were focused on crude oil, but the
majority of our wells drilled were in our shallow gas resource play.
- Our cash operating costs were $9.43/BOE compared to $9.80/BOE last
year at this time. We are raising our guidance on operating costs for
the year to approximately $9.00/BOE from $8.65/BOE, primarily due to
increased service rig activity on optimization efforts in the U.S.
and additional costs for fuel and supplies. Although the well
optimization efforts in the U.S. have increased our overall operating
costs, we are pleased with the production performance from our Bakken
Oil resource play as a result.
- Cash general and administrative expenses were $1.67/BOE versus
$1.94/BOE during the second quarter of 2007.
SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS
All amounts are stated in Canadian dollars unless otherwise specified. In
accordance with Canadian practice, production volumes, reserve volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Where applicable, natural gas has been
converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE
rate is based on an energy equivalent conversion method primarily applicable
at the burner tip and does not represent a value equivalent at the wellhead.
Use of BOE in isolation may be misleading. Certain prior year amounts have
been restated to reflect current year presentation. Readers are also urged to
review the Management's Discussion & Analysis (MD&A) and Audited Financial
Statements for more fulsome disclosure on our operations. These reports can be
found on our website at www.enerplus.com, our SEDAR profile at www.sedar.com
and as part of our SEC filings available on www.sec.gov.
SELECTED FINANCIAL RESULTS
Three months Six months
ended June 30, ended June 30,
(in Canadian dollars) 2008 2007 2008 2007
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Financial (000's)
Cash Flow from
Operating
Activities $ 364,457 $ 237,482 $ 620,673 $ 430,663
Cash Distributions
to Unitholders(1) 202,346 162,607 394,704 320,278
Cash Withheld for
Acquisitions and
Capital
Expenditures 162,111 74,875 225,969 110,385
Net Income 112,230 40,084 233,624 147,957
Debt Outstanding
(net of cash) 1,027,578 657,945 1,027,578 657,945
Development Capital
Spending 88,008 80,446 214,270 190,398
Acquisitions 1,740 204,016 1,766,809 267,394
Divestments 86 5,518 2,208 5,473
Actual Cash
Distributions paid
to Unitholders $ 1.26 $ 1.26 $ 2.52 $ 2.52
Financial per Weighted
Average Trust Units(2)
Cash Flow from
Operating
Activities $ 2.22 $ 1.85 $ 3.98 $ 3.42
Cash Withheld for
Acquisitions and
Capital Expenditures 0.99 0.58 1.45 0.88
Net Income 0.68 0.31 1.50 1.18
Payout Ratio(3) 56% 68% 64% 74%
Selected Financial
Results per BOE(4)
Oil & Gas Sales(5) $ 80.56 $ 50.96 $ 71.85 $ 50.00
Royalties (15.14) (9.63) (13.46) (9.43)
Commodity Derivative
Instruments (7.03) (0.15) (4.35) 0.45
Operating Costs (9.43) (9.80) (9.21) (9.16)
General and
Administrative (1.67) (1.94) (1.75) (1.93)
Interest and Other
Income and Foreign
Exchange (1.32) (1.36) (1.10) (1.34)
Taxes (1.78) (0.43) (1.49) (0.35)
Restoration and
Abandonment (0.52) (0.51) (0.51) (0.48)
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Cash Flow from Operating
Activities before
changes in non-cash
working capital $ 43.67 $ 27.14 $ 39.98 $ 27.76
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Weighted Average Number
of Trust Units
Outstanding Including
Equivalent Exchangeable
Limited Partnership
Units (thousands) 164,483 128,361 155,984 125,849
Debt/Trailing 12 Month
Cash Flow Ratio(6) 0.9x 0.7x 0.9x 0.7x
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SELECTED OPERATING RESULTS
Three months Six months
ended June 30, ended June 30,
2008 2007 2008 2007
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Average Daily Production
Natural gas (Mcf/day) 359,349 264,946 333,559 270,300
Crude oil (bbls/day) 35,486 34,178 34,376 34,869
NGLs (bbls/day) 4,810 4,143 4,712 4,325
Total (BOE/day) 100,188 82,478 94,681 84,244
% Natural gas 60% 54% 59% 53%
Average Selling Price(5)
Natural gas
(per Mcf) $ 9.87 $ 7.04 $ 8.79 $ 7.13
Crude oil (per bbl) 114.04 61.93 100.47 59.56
NGLs (per bbl) 80.55 53.34 75.29 48.55
US$ exchange rate 0.99 0.91 0.99 0.88
Net Wells drilled 72 36 197 75
Success Rate 100% 100% 100% 99%
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(1) Calculated based on distributions paid or payable.
(2) Based on weighted average trust units outstanding for the period,
including the exchangeable limited partnership units assumed through
the Focus Energy Trust acquisition.
(3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
from Operating Activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(6) Including the trailing 12 month cash flow of Focus Energy Trust.
TRUST UNIT TRADING SUMMARY
for the three months TSX - ERF.un NYSE - ERF
ended June 30, 2008 (CDN$) (US$)
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High $ 49.85 $ 50.63
Low $ 43.44 $ 42.43
Close $ 47.18 $ 46.24
2008 CASH DISTRIBUTIONS PER TRUST UNIT
Production Month Payment Month CDN$ US$
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First Quarter Total $ 1.26 $ 1.24
April June $ 0.42 $ 0.41
May July 0.42 0.42
June August 0.42 0.41(*)
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Second Quarter Total $ 1.26 $ 1.24
Total Year-to-Date $ 2.52 $ 2.48
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(*) Calculated using a Canadian/US$ exchange rate of 1.02
2008 PRODUCTION AND DEVELOPMENT ACTIVITY
Three months ended June 30,
---------------------------------------------------
Wells Drilled(*)
-------------------------
Production Capital
Play Type Volumes Spending
(BOE/day) ($ millions) Gross Net
-------------------------------------------------------------------------
Shallow Gas & CBM 25,438 $ 23.9 68 67.4
Crude Oil Waterfloods 16,484 10.7 - -
Deep Tight Gas 15,613 8.9 2 1.2
Bakken Oil 11,346 13.5 4 2.9
Other Conventional
Oil & Gas 31,307 18.1 26 0.8
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Total Conventional 100,188 75.1 100 72.3
Oil Sands
Kirby - 3.9 - -
Joslyn - 8.5 - -
Laricina - 0.5 - -
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Total Oil Sands - 12.9 - -
Total 100,188 88.0 100 72.3
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Six months ended June 30,
---------------------------------------------------
Wells Drilled(*)
-------------------------
Production Capital
Play Type Volumes Spending
(BOE/day) ($ millions) Gross Net
-------------------------------------------------------------------------
Shallow Gas & CBM 22,939 $ 46.3 217 159.4
Crude Oil Waterfloods 15,777 27.9 22 10.5
Deep Tight Gas 14,407 31.8 30 5.2
Bakken Oil 11,124 33.0 8 6.0
Other Conventional
Oil & Gas 30,434 40.9 79 16.0
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Total Conventional 94,681 179.9 356 197.1
Oil Sands
Kirby - 24.5 - -
Joslyn - 9.2 - -
Laricina - 0.7 - -
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Total Oil Sands - 34.4 - -
Total 94,681 214.3 356 197.1
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(*) Drilling totals do not include delineation wells at Kirby or service
wells drilled during the quarter
Drilling success rate year-to-date: 100%
OPERATIONS REVIEW
Weather delays, a reduction in non-operated spending and lower than
budgeted spending at Joslyn resulted in slightly lower than planned
development capital spending of $88 million in the quarter. Redeployment of
approximately $40 million of development capital from oil sands (Joslyn) to
our conventional business, an increase in other operated conventional
development spending across our resource plays and an expectation of increased
non-operated spending for the balance of the year allows us to maintain our
annual development capital spending guidance of $580 million. We are raising
our guidance on operating costs for the year to approximately $9.00/BOE from
$8.65/BOE, primarily due to increased service rig activity on optimization
efforts in the U.S. and additional costs for fuel and supplies. Although the
well optimization efforts in the U.S. have increased our overall operating
costs, we are pleased with the production performance from our Bakken Oil
resource play as a result of these activities.
Approximately 60% of our capital spending this quarter was directed
toward crude oil development opportunities, although the majority of the wells
drilled were in our shallow gas resource play. Wet weather caused a delay on
some of our development capital expenditures in the quarter but significant
drilling and tie-ins prior to break-up in the first quarter and better than
expected production performance in key areas throughout the second quarter
resulted in strong overall operational performance. Efficient planning and
execution of turnarounds by our staff minimized facility downtime, offset
weather delays and also helped us meet our production targets.
In our shallow gas resource play, we invested nearly a third of our
quarterly conventional spending by drilling 68 gross wells in the second
quarter. At Shackleton, we drilled 48 wells and are expanding our development
program for the rest of the year to drill 60 additional wells above our
original plans, significantly increasing recompletion work and adding more
compression by the end of 2008.
Our Giltedge waterflood property, which was shut down late in 2007 due to
a facility fire and had been partially operating with temporary facilities
early in 2008, resumed full operations on April 14, 2008. The restart was two
weeks earlier than we anticipated and production has returned to near normal
levels.
Optimization efforts in the U.S. continued during the second quarter and
we anticipate resuming our refrac and 3rd well per section program in the
third quarter, increasing our development capital spending in the U.S.
throughout the balance of the year.
Our safety performance in the field for both employees and contractors
improved this quarter over last with no medical aid incidents. This was due
primarily to our increased emphasis on motor vehicle safety, proactive hazard
identification and improvements in near miss reporting.
CANADIAN FEDERAL TAX LEGISLATION
On July 14, 2008, the Canadian Department of Finance released draft
amendments to the Canadian Income Tax Act which included provisions to
facilitate the tax efficient conversion of a specified investment flow through
("SIFT") trust into a corporation. These draft provisions are designed to
ensure that the conversion of a trust to a corporation can be structured in
such a manner that neither the trust nor its unitholders will be subject to
Canadian tax on the transaction. We believe that any corporate conversion
transaction should be tax deferred for our U.S. unitholders as well. The
Department of Finance is accepting comments on these proposals until September
15, 2008 after which it intends to present the amendments as part of a tax
reform bill in the Fall of 2008.
As we have stated since the 2006 trust taxation announcement, we believe
that there is value in retaining the trust structure until the end of 2010. We
currently do not foresee any compelling reasons to make major changes to our
corporate structure before 2011.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated
August 6, 2008 and is to be read in conjunction with:
- the audited consolidated financial statements as at and for the years
ended December 31, 2007 and 2006; and
- the unaudited interim consolidated financial statements as at and for
the three and six months ended June 30, 2008 and 2007.
All amounts are stated in Canadian dollars unless otherwise specified.
All references to GAAP refer to Canadian generally accepted accounting
principles. All note references relate to the notes included with the
accompanying unaudited interim consolidated financial statements. In
accordance with Canadian practice revenues are reported on a gross basis,
before deduction of Crown and other royalties, unless otherwise stated. Where
applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading.
The following MD&A contains forward-looking information and statements.
We refer you to the end of the MD&A for our disclaimer on forward-looking
information and statements.
NON-GAAP MEASURES
Throughout the MD&A we use the term "payout ratio" to analyze operating
performance, leverage and liquidity. We calculate payout ratio by dividing
cash distributions to unitholders ("cash distributions") by cash flow from
operating activities ("cash flow"), both of which are measures prescribed by
GAAP which appear on our consolidated statements of cash flows. The term
"payout ratio" does not have a standardized meaning or definition as
prescribed by GAAP and therefore may not be comparable with the calculation of
similar measures by other entities.
Refer to the "Liquidity and Capital Resources" section of the MD&A for
further information on cash flow, cash distributions and payout ratio.
OVERVIEW
Production for the second quarter was in-line with our expectations
averaging 100,188 BOE/day. Cash flow from operating activities totaled
$364.5 million representing an increase of $108.3 million or 42% from the
first quarter of 2008 and $127.0 million or 53% from the second quarter of
2007. The increases are mainly due to higher commodity prices along with
increased production as a result of the acquisition of Focus Energy Trust
("Focus"). The higher commodity prices also impacted our price risk management
costs as we incurred cash losses of $64.0 million and non-cash losses of
$161.0 million due to higher forward commodity prices at quarter end.
For the second quarter of 2008 our development capital spending was
$88.0 million as we drilled 72 net wells with a 100% success rate. Operating
costs were slightly higher than anticipated due to optimization work in the
United States. All of our 2008 guidance targets remain unchanged with the
exception of our annual operating costs which we are increasing to $9.00/BOE,
primarily as a result of our U.S. optimization efforts.
On July 31, 2008, subsequent to quarter end, we successfully disposed of
our Joslyn oil sands lease ("Joslyn") for net proceeds of approximately
$500 million. The proceeds have been used to pay down bank debt which further
strengthens our balance sheet and positions us well for future growth. Given
the strength in commodity prices and the performance of our operations we are
increasing monthly cash distributions to $0.47/unit effective September 20,
2008.
RESULTS OF OPERATIONS
Production
Production in the second quarter of 2008 was in-line with our
expectations averaging 100,188 BOE/day, an increase of 12% from 89,150 BOE/day
in the first quarter of 2008. For the three and six months ended June 30, 2008
production increased 21% and 12% respectively, compared to the same periods in
2007. The increases are primarily due to the additional production from the
Focus assets acquired on February 13, 2008.
Average production volumes for the three and six months ended June 30,
2008 and 2007 are outlined below:
Daily Three months ended June 30, Six months ended June 30,
Production Volumes 2008 2007 % Change 2008 2007 % Change
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Natural gas (Mcf/day) 359,349 264,946 36% 333,559 270,300 23%
Crude oil (bbls/day) 35,486 34,178 4% 34,376 34,869 (1)%
Natural gas liquids
(bbls/day) 4,810 4,143 16% 4,712 4,325 9%
Total daily sales
(BOE/day) 100,188 82,478 21% 94,681 84,244 12%
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Based on the results of our second quarter we continue to expect 2008
annual production volumes to average 98,000 BOE/day and our 2008 exit rate to
be approximately 100,000 BOE/day.
Pricing
The prices received for our natural gas and crude oil production have a
direct impact on our earnings, cash flow and financial condition. The
following table compares our average selling prices for the three and six
months ended June 30, 2008 and 2007. It also compares the benchmark price
indices for the same periods:
Three months ended June 30, Six months ended June 30,
% %
Average Selling Price(1) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Natural gas (per Mcf) $ 9.87 $ 7.04 40% $ 8.79 $ 7.13 23%
Crude oil (per bbl) $114.04 $61.93 84% $100.47 $59.56 69%
Natural gas liquids
(per bbl) $ 80.55 $53.34 51% $ 75.29 $48.55 55%
Per BOE $ 80.56 $50.96 58% $ 71.85 $50.00 44%
Average Benchmark
Pricing
-------------------------------------------------------------------------
AECO natural gas -
monthly index
(CDN$/Mcf) $ 9.35 $ 7.37 27% $ 8.24 $ 7.42 11%
AECO natural gas -
daily index
(CDN$/Mcf) $ 10.22 $ 7.07 45% $ 9.06 $ 7.23 25%
NYMEX natural gas -
monthly NX3 index
(US$/Mcf) $ 10.80 $ 7.56 43% $ 9.43 $ 7.26 30%
NYMEX natural gas -
monthly NX3 index
CDN$ equivalent
(CDN$/Mcf) $ 10.91 $ 8.31 31% $ 9.53 $ 8.25 16%
WTI crude oil
(US$/bbl) $123.98 $ 65.03 91% $110.95 $ 61.65 80%
WTI crude oil CDN$
equivalent (CDN$/bbl) $125.23 $ 71.46 75% $112.07 $ 70.06 60%
CDN$/US$ exchange rate 0.99 0.91 9% 0.99 0.88 13%
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(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
During the quarter the AECO natural gas price rose 30% from a low of
$9.08/Mcf to a high of $11.80/Mcf. This price increase during the second
quarter was supported by the strength of crude oil, lower storage inventories,
lower liquefied natural gas imports into the U.S. and weather concerns.
We realized an average price on our natural gas of $9.87/Mcf (net of
transportation costs) during the three months ended June 30, 2008, an increase
of 40% from $7.04/Mcf for the same period in 2007. For the six months ended
June 30, 2008 we realized a 23% increase in our average price of $8.79/Mcf
compared to the same period in 2007. The majority of our natural gas sales are
priced with reference to the monthly or daily AECO indices. The 40% and 23%
increases for the three and six month periods ended June 30, 2008 are
comparable to the changes experienced at AECO.
Crude oil prices rose steadily during the second quarter as a result of
low inventories, a weak U.S. dollar and supply risks related to Nigeria and
Iran. The average price we received for our crude oil during the three months
ended June 30, 2008 increased 84% to $114.04/bbl (net of transportation costs)
compared to $61.93/bbl during the same period in 2007. Similarly, the West
Texas Intermediate ("WTI") crude oil benchmark price, in Canadian dollars,
increased 75% from the corresponding period in 2007. For the six months ended
June 30, 2008 our crude oil price increased 69% to $100.47/bbl (net of
transportation costs), while the WTI benchmark, in Canadian dollars, increased
60%. Medium and heavy differentials narrowed as a percentage of WTI compared
to the prior period of 2007.
The Canadian dollar strengthened against the U.S. dollar during the three
and six months ended June 30, 2008 compared to the same periods in 2007. As
most of our crude oil and natural gas is priced in reference to U.S. dollar
denominated benchmarks, this movement in the exchange rate reduced the
Canadian dollar prices that we would have otherwise realized.
Price Risk Management
We have developed a price risk management framework to respond to the
volatile commodity price environment in a prudent manner. Consideration is
given to our overall financial position together with the economics of our
development capital program and acquisitions. Consideration is also given to
the upfront costs of our risk management program as we seek to limit our
exposure to price downturns. Hedge positions for any given term are transacted
across a range of prices and time. With respect to our natural gas and crude
oil hedges for 2008, our overall hedge position was influenced by our desire
to provide a level of protection to the downside on cash flow.
Considering all financial contracts transacted as of July 25, 2008, we
have protected a portion of our natural gas price risk through to October 31,
2009 and a portion of our crude oil price risk through to December 31, 2009.
We have also taken steps to protect our exposure to rising electricity costs
for some of our consumption in the Alberta power market through to
December 31, 2009. See Note 9 for a list of our current price risk management
positions.
The following is a summary of the financial contracts in place at
July 25, 2008, expressed as a percentage of our forecasted net production
volumes:
Natural Gas (CDN$/Mcf) Crude Oil (US$/bbl)
----------------------------------------------------------------------
July 1, November 1, April 1, July 1, January 1,
2008 - 2008 - 2009 - 2008 - 2009 -
October 31, March 31, October 31, December December
2008 2009 2009 31, 2008 31, 2009
-------------------------------------------------------------------------
Floor Prices
(puts) $ 7.09 $ 9.20 $ 9.48 $72.09 $94.62
% (net of
royalties) 25% 21% 4% 34% 21%
Fixed Price
(swaps) $ 7.44 $ 9.35 $ 7.86 $79.97 $100.05
% (net of
royalties) 20% 3% 2% 18% 2%
Capped Price
(calls) $ 8.25 $11.24 - $85.48 $92.98
% (net of
royalties) 25% 12% - 22% 11%
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Based on weighted average price (before premiums), estimated average
annual production of 98,000 BOE/day and assuming a royalty rate of 19%
for 2008. For 2009 we have assumed a 26% royalty rate reflecting the
increased royalties for Alberta production at the current forward
commodity price levels.
Accounting for Price Risk Management
During the second quarter of 2008 our price risk management program
incurred cash losses of $16.0 million on our natural gas contracts and
$48.0 million on our crude oil contracts, compared to cash losses of $0.8
million and $0.3 million respectively during the second quarter of 2007. For
the six months ended June 30, 2008 we experienced cash losses of $11.8 million
on our natural gas contracts and cash losses of $63.2 million on our crude oil
contracts, compared to a loss of $1.3 million and a gain of $8.1 million
respectively for the same period in 2007. The increase in cash losses for the
three and six months ended June 30, 2008 is the result of commodity prices
rising above our swap and sold call positions.
At June 30, 2008 both the current and forward commodity prices for crude
oil and natural gas were at all time highs which impacted the fair value of
our commodity derivative instruments. The fair value of our natural gas and
crude oil derivative instruments, net of premiums, represented losses of
$89.9 million and $199.2 million respectively at June 30, 2008. These loss
positions are based on forward natural gas and crude oil prices and are
recorded as current deferred financial credits on our balance sheet. In
comparison, at March 31, 2008 the fair value of our natural gas and crude oil
derivative instruments represented losses of $50.2 million and $77.9 million
respectively. The change in the fair value of our commodity derivative
instruments during the second quarter of 2008 resulted in unrealized losses of
$39.7 million for natural gas and $121.3 million for crude oil. For the six
months ended June 30, 2008 the change in fair value of our commodity
derivative instruments resulted in unrealized losses of $98.0 million for
natural gas and $142.4 million for crude oil. See Note 9 for details.
Between June 30, 2008 and July 25, 2008 the market prices for crude oil
decreased by 12% while natural gas prices decreased by 31%. If the forward
market remains at these lower levels relative to June 30, 2008 we would expect
to record recoveries on our unrealized non-cash losses in subsequent quarters.
The following table summarizes the effects of our financial contracts on
income:
Risk Management Costs Three months ended Three months ended
($ millions, except June 30, June 30,
per unit amounts) 2008 2007
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Cash losses:
Natural gas $ (16.0) $(0.49)/Mcf $ (0.8) $(0.03)/Mcf
Crude oil (48.0) (14.86)/bbl (0.3) (0.10)/bbl
---------- ----------
Total Cash losses $ (64.0) $(7.03)/BOE $ (1.1) $(0.15)/BOE
Non-cash (losses)/gains
on financial contracts:
Change in fair value
- natural gas $ (39.7) $(1.21)/Mcf $ 25.4 $1.05/Mcf
Change in fair value
- crude oil (121.3) (37.56)/bbl (6.3) (2.03)/bbl
---------- ----------
Total non-cash
(losses)/gains $ (161.0) $(17.65)/BOE $ 19.1 $2.54/BOE
---------- ----------
Total (losses)/gains $ (225.0) $(24.68)/BOE $ 18.0 $2.39/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Risk Management Costs Six months ended Six months ended
($ millions, except June 30, June 30,
per unit amounts) 2008 2007
-------------------------------------------------------------------------
Cash (losses)/gains:
Natural gas $ (11.8) $(0.19)/Mcf $ (1.3) $(0.03)/Mcf
Crude oil (63.2) (10.10)/bbl 8.1 1.28/bbl
---------- ----------
Total Cash
(losses)/gains $ (75.0) $(4.35)/BOE $ 6.8 $0.45/BOE
Non-cash (losses)/
gains on financial
contracts:
Change in fair value
- natural gas $ (98.0) $(1.61)/Mcf $ 4.8 $0.10/Mcf
Change in fair value
- crude oil (142.4) (22.77)/bbl (19.2) (3.04)/bbl
---------- ----------
Total non-cash losses $ (240.4) $(13.95)/BOE $ (14.4) $(0.95)/BOE
---------- ----------
Total losses $ (315.4) $(18.30)/BOE $ (7.6) $(0.50)/BOE
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Cash Flow Sensitivity
The sensitivities below reflect the estimated impact on cash flow per
trust unit for the remaining two quarters of 2008 and include the commodity
contracts described in Note 9 as well as the impact of 2008 forward market
prices as at July 25, 2008. To the extent the market price of crude oil and
natural gas change significantly from the July 25, 2008 levels, the
sensitivities will no longer be relevant as the effect of our commodity
contracts will change.
Estimated Effect on 2008
Sensitivity Table Cash Flow per Trust Unit(1)
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Change of $0.15 per Mcf in the price of AECO
natural gas $0.03
Change of US$1.00 per barrel in the price of
WTI crude oil $0.02
Change of 1,000 BOE/day in production $0.07
Change of $0.01 in the US$/CDN$ exchange rate $0.06
Change of 1% in interest rate $0.03
-------------------------------------------------------------------------
(1) Assumes constant working capital and 164,709,000 units outstanding.
The impact of a change in one factor may be compounded or offset by
changes in other factors. This table does not consider the impact of any
inter-relationship among the factors.
Revenues
Crude oil and natural gas revenues were higher during the second quarter
of 2008 compared to the first quarter of 2008 due to an increase in commodity
prices and a full quarter of production from the Focus assets.
Crude oil and natural gas revenues for the three months ended June 30,
2008 were $734.4 million ($741.5 million, net of $7.1 million transportation)
compared to $382.5 million ($387.9 million, net of $5.4 million
transportation) for the same period in 2007. For the six months ended June 30,
2008 revenues were $1,238.1 million ($1,251.5 million, net of $13.4 million
transportation) compared to $762.5 million ($773.8 million, net of
$11.3 million transportation) during the same period in 2007.
The majority of the increase in revenues of $351.9 million or 92% and
$475.6 million or 62% for the three and six months ended June 30, 2008
compared to the same period in 2007 was due to higher commodity prices.
The following table summarizes the changes in sales revenue:
Analysis of Sales
Revenue(1)
($ millions) Crude Oil NGLs Natural Gas Total
-------------------------------------------------------------------------
Quarter ended June 30,
2007 $ 192.6 $ 20.1 $ 169.8 $ 382.5
Price variance(1) 168.3 12.0 96.4 276.7
Volume variance 7.4 3.3 64.5 75.2
-------------------------------------------------------------------------
Quarter ended June 30,
2008 $ 368.3 $ 35.4 $ 330.7 $ 734.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
($ millions) Crude Oil NGLs Natural Gas Total
-------------------------------------------------------------------------
Year-to-date ended
June 30, 2007 $ 375.9 $ 38.0 $ 348.6 $ 762.5
Price variance(1) 256.0 23.0 106.8 385.8
Volume variance (3.3) 3.6 89.5 89.8
-------------------------------------------------------------------------
Year-to-date ended
June 30, 2008 $ 628.6 $ 64.6 $ 544.9 $ 1,238.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Other Income
Other income for the three and six months ended June 30, 2008 was
$0.4 million and $15.5 million respectively, compared to $0.3 million and
$14.4 million for the same periods in 2007. Included in the first six months
of 2008 was a gain of $8.3 million on the sale of certain marketable
securities, as well as interim payments for our business interruption
insurance of $6.4 million related to the Giltedge fire. During the first
quarter of 2007 we realized a gain of $14.1 million on the sale of certain
marketable securities.
Royalties
Royalties are paid to various government entities and other land and
mineral rights owners. For the three and six months ended June 30, 2008
royalties were $138.0 million and $231.9 million respectively, both
approximately 19% of oil and gas sales net of transportation. For the three
and six months ended June 30, 2007 royalties were $72.2 million and
$143.8 million, both approximately 19% of oil and gas sales net of
transportation respectively. Increases in royalties for the three and six
months ended June 30, 2008 of $65.8 million and $88.1 million respectively,
compared to the same periods in 2007 were the result of higher commodity
prices and increased production. We continue to expect royalties to be
approximately 19% of oil and gas sales net of transportation during 2008.
In October 2007 the Alberta government announced a 'New Royalty
Framework' ("NRF") which will be effective January 1, 2009 and is expected to
increase our royalties as a percentage of oil and gas sales. In the context of
an annualized forward market of $130.00/bbl crude oil and $10.00/Mcf natural
gas, and relative to Enerplus' current properties and production profile, we
estimate the NRF will result in an average 2009 royalty rate for the Fund of
approximately 26% of oil and gas sales, net of transportation costs.
As at the date of this MD&A the Alberta government had not yet made the
necessary legislative and administrative changes to implement the NRF. The NRF
announcement can be found on the Alberta government's website at
www.gov.ab.ca.
Operating Expenses
Operating expenses during the second quarter of 2008 were $9.43/BOE or 6%
higher than the first quarter of 2008. This increase can be attributed to
additional service rig activity related to optimization work on our U.S.
properties.
Operating expenses for the three months ended June 30, 2008 were
$86.0 million or $9.43/BOE compared to $72.8 million or $9.69/BOE for the
second quarter of 2007. For the six months ended June 30, 2008 operating costs
were $158.0 million or $9.17/BOE compared to $138.8 million or $9.10/BOE for
the same period in 2007. Operating expenses are generally in-line with our
expectations however we have experienced a slight increase in costs for fuel
and supplies which can be attributed to higher oil prices. In addition, we are
continuing to spend more on optimization efforts on our U.S. properties which
has resulted in increased production.
As a result of the increased costs to date we are raising our annual
guidance for operating costs from $8.65/BOE to $9.00/BOE.
General and Administrative Expenses ("G&A")
During the second quarter of 2008 G&A expenses decreased 6% per BOE to
$1.90/BOE compared to $2.03/BOE for the first quarter of 2008.
G&A expenses for the three months ended June 30, 2008 were $17.3 million
or $1.90/BOE compared to $16.7 million or $2.22/BOE for the second quarter of
2007. G&A expenses totaled $33.8 million or $1.96/BOE for the six months ended
June 30, 2008 compared to $33.8 million or $2.21/BOE for the same period in
2007. G&A expenses remained relatively unchanged year-over-year however the
reduction on a $/BOE basis compared to 2007 is primarily due to the additional
volumes associated with the Focus acquisition.
For the three and six months ended June 30, 2008 our G&A expenses
included non-cash charges of $2.1 million or $0.23/BOE and $3.6 million or
$0.21/BOE respectively, compared to $2.1 million or $0.28/BOE and $4.2 million
or $0.28/BOE for the same periods in 2007. These amounts relate solely to our
trust unit rights incentive plan and are determined using a binomial lattice
option-pricing model. See Note 8 for further details.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and
Administrative
Costs Three months ended June 30, Six months ended June 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash $ 15.2 $ 14.6 $ 30.2 $ 29.6
Trust unit rights
incentive plan
(non-cash) 2.1 2.1 3.6 4.2
-------------------------------------------------------------------------
Total G&A $ 17.3 $ 16.7 $ 33.8 $ 33.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash $ 1.67 $ 1.94 $ 1.75 $ 1.93
Trust unit rights
incentive plan
(non-cash) 0.23 0.28 0.21 0.28
-------------------------------------------------------------------------
Total G&A $ 1.90 $ 2.22 $ 1.96 $ 2.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We are maintaining our guidance for G&A expenses at $2.20/BOE, which
includes non-cash G&A costs of approximately $0.20/BOE.
Interest Expense
Interest expense includes interest on long-term debt, the premium
amortization on our US$175 million senior unsecured notes, unrealized gains
and losses resulting from the change in fair value of our interest rate swaps
as well as the interest component on our cross currency interest rate swap
("CCIRS"). See Note 6 for further details.
Interest on long-term debt excluding non-cash charges totaled
$12.9 million and $26.2 million for the three and six months ended June 30,
2008, compared to $9.7 million and $19.5 million respectively for the same
periods in 2007. The increases in 2008 are due to higher average outstanding
indebtedness as a result of the Focus acquisition, partially offset by lower
interest rates.
Non-cash interest charges totaled $6.4 million and nil for the three and
six months ended June 30, 2008, compared to $2.1 million and $0.5 million
respectively for the same periods in 2007. The changes in the fair value of
our interest rate swaps and CCIRS that result from movements in forward market
interest rates cause non-cash interest to fluctuate between periods.
The following table summarizes the cash and non-cash interest expense
recorded:
Interest Expense Three months ended June 30, Six months ended June 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Interest on long-term
debt $ 12.9 $ 9.7 $ 26.3 $ 19.5
Non-cash interest loss 6.4 2.1 - 0.5
-------------------------------------------------------------------------
Total Interest
Expense $ 19.3 $ 11.8 $ 26.3 $ 20.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2008 approximately 15% of our debt was based on fixed
interest rates while 85% had floating interest rates. In comparison, at
June 30, 2007 approximately 20% of our debt was based on fixed interest rates
and 80% was floating.
Capital Expenditures
During the three and six months ended June 30, 2008 we spent
$88.0 million and $214.3 million on capital development respectively, compared
to $80.4 million and $190.4 million during the same periods in 2007. The
increase experienced during 2008 is largely due to drilling activities
associated with our shallow gas properties and additional activity on our
Focus assets. To date we have achieved a 100% success rate with our drilling
program on 197 net wells.
Corporate acquisitions for the six months ending June 30, 2008 totaled
approximately $1.7 billion and relate to the Focus acquisition which closed
February 13, 2008. Refer to Note 4 for further details.
Property acquisitions for the three and six months ended June 30, 2008
totaled $1.8 million and $9.3 million respectively, compared to $204.0 million
and $267.4 million for the same periods in 2007. Property acquisitions in 2007
included the purchase of our Jonah and Kirby assets in the first and second
quarter of 2007 respectively.
Total net capital expenditures for 2008 and 2007 are outlined below:
Capital
Expenditures Three months ended June 30, Six months ended June 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Development
expenditures $ 56.0 $ 69.4 $ 165.3 $ 160.2
Plant and facilities 32.0 11.0 49.0 30.2
-------------------------------------------------------------------------
Development Capital 88.0 80.4 214.3 190.4
Office 2.0 1.6 3.6 3.0
-------------------------------------------------------------------------
Sub-total 90.0 82.0 217.9 193.4
Property acquisitions(1) 1.8 204.0 9.3 267.4
Corporate acquisitions - - 1,757.5 -
Property dispositions(1) (0.1) (5.5) (2.2) (5.5)
-------------------------------------------------------------------------
Total Net Capital
Expenditures $ 91.7 $ 280.5 $ 1,982.5 $ 455.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital Expenditures
financed with cash
flow $ 91.7 $ 74.9 $ 226.0 $ 110.4
Capital Expenditures
financed with debt
and equity - 205.6 1,756.5 344.9
-------------------------------------------------------------------------
Total Net Capital
Expenditures $ 91.7 $ 280.5 $ 1,982.5 $ 455.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
Our year-to-date development capital spending is slightly behind schedule
and although we disposed of our interest in Joslyn subsequent to the quarter
end, we are maintaining our 2008 guidance of $580 million. Approximately
$40 million of planned spending for Joslyn will be redirected to conventional
development capital spending during the remainder of the year. Due to the
timing of these additional conventional capital expenditures we are not
expecting a significant impact to 2008 production volumes.
Oil Sands
Our oil sands development projects have not commenced commercial
production. As a result all associated costs inclusive of acquisition
expenditures, development capital spending, salaries and benefits, engineering
and planning, net of revenues generated, are capitalized and excluded from our
depletion calculation. At June 30, 2008 capitalized costs life-to-date for
Joslyn including other minor interests were $121.2 million and for Kirby were
$229.9 million for a combined total of $351.1 million.
During the second quarter of 2008 we capitalized costs of $3.9 million
associated with advancing our regulatory application for our Kirby project.
On July 31, 2008 we disposed of our interest in Joslyn for total cash
consideration of approximately $500 million. Proceeds from the disposition
have been used to pay down debt, improving our debt-to-cash flow ratio which
reinforces our borrowing capacity, supports our ability to fund future
development capital and acquisition activities and minimizes the need to issue
additional equity.
We continue to hold an interest in Laricina Energy Ltd., a private
company with significant resources in the Alberta oil sands. This interest
represents approximately 12% of the outstanding equity.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
DDA&A of property, plant and equipment ("PP&E") is recognized using the
unit-of-production method based on proved reserves.
For the three months ended June 30, 2008, DDA&A increased to $18.93/BOE
compared to $15.58/BOE during the corresponding period in 2007. For the six
months ended June 30, 2008 DDA&A increased to $18.12/BOE compared to
$15.48/BOE during the corresponding period in 2007. The increase is primarily
due to additional PP&E and production as a result of the Focus acquisition.
No impairment of the Fund's assets existed at June 30, 2008 using
year-end reserves updated for acquisitions, divestitures and management's
estimates of future prices.
Asset Retirement Obligations
In connection with our operations, we anticipate we will incur
abandonment and reclamation costs for surface leases, wells, facilities and
pipelines. Total future asset retirement obligations are estimated by
management based on the Fund's net ownership interest in wells and facilities,
estimated costs to abandon and reclaim the wells and facilities and the
estimated timing of the costs to be incurred in future periods and such
obligations are included on the Fund's balance sheet.
The Fund has estimated the net present value of its total asset
retirement obligations to be approximately $203.4 million at June 30, 2008
compared to $165.7 million at December 31, 2007. The increase of $37.7 million
relates primarily to the acquisition of Focus. See Note 3.
The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation and asset retirement
obligations settled during the period:
Three months ended June 30, Six months ended June 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Amortization of the
asset retirement
cost $ 5.1 $ 3.3 $ 9.8 $ 6.7
Accretion of the asset
retirement obligation 3.1 1.6 5.6 3.3
-------------------------------------------------------------------------
Total Amortization and
Accretion $ 8.2 $ 4.9 $ 15.4 $ 10.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement
Obligations Settled $ 4.8 $ 3.8 $ 8.8 $ 7.1
-------------------------------------------------------------------------
The timing of actual asset retirement costs will differ from the timing
of amortization and accretion charges. Actual asset retirement costs will be
incurred over the next 66 years with the majority between 2038 and 2047. For
accounting purposes, the asset retirement cost is amortized using a
unit-of-production method based on proved reserves before royalties while the
asset retirement obligation accretes until the time the obligation is settled.
Taxes
Future Income Taxes
Future income taxes arise from differences between the accounting and tax
bases of assets and liabilities. A portion of the future income tax liability
that is recorded on the balance sheet will be recovered through earnings
before 2011. The balance will be realized when future income tax assets and
liabilities are realized or settled.
Our future income tax recovery was $50.4 million for the quarter ended
June 30, 2008 compared to an expense of $71.0 million for the same period in
2007. During the second quarter of 2007, the Canadian Federal Government
enacted the new specified investment flow through ("SIFT") tax on publicly
traded income trusts effective January 1, 2011 which resulted in a one-time
future income tax expense of $78.1 million. After consideration of the SIFT
tax, the increased recovery in 2008 is due to higher income at the trust level
and the recording of a future tax asset relating to a previously unrecognized
tax pool.
Subsequent to June 30, 2008, the Department of Finance issued draft
amendments to the Income Tax Regulations regarding the provincial tax rate for
SIFT entities. These amendments are generally designed to tax SIFT entities at
the same level as a corporation and are expected to be enacted later in 2008.
The amendments were not considered substantively enacted at June 30, 2008. As
a result there was no consequential impact on future income taxes in the
second quarter however this will result in a future income tax recovery when
enacted.
On July 14, 2008, the Department of Finance released draft legislative
proposals which included proposed amendments which would allow a SIFT to
convert into a corporation on a tax efficient basis without adverse Canadian
tax consequences for the trust or its Canadian unitholders. We believe that
the trust conversion under the proposed rules would qualify as a U.S. tax
deferred transaction for our U.S. unitholders as well. The Canadian Department
of Finance is accepting comments on these proposals until September 15, 2008
and intends to introduce the amendments into Parliament later this year. We
are currently reviewing the legislative proposals to determine the impact to
Enerplus should we eventually decide to convert into a corporation.
Current Income Taxes
In our current structure payments are made between the operating entities
and the Fund, which ultimately transfers both the income and future tax
liability to our unitholders. As a result no cash income taxes have been paid
by our Canadian operating entities. However an income tax liability of
$24.3 million was triggered on the acquisition of Focus on February 13, 2008.
This liability was included in Focus' assumed working capital and was paid in
April 2008. We expect to recover these taxes over the next twelve months and
as such we have recorded a cash income tax recovery of $7.9 million for six
months ended June 30, 2008.
The amount of current taxes recorded in the year with respect to our U.S.
operations is dependent upon income levels, and the timing of both capital
expenditures and the repatriation of funds to Canada. For the three and six
months ended June 30, 2008 our U.S. operations incurred taxes (income and
withholding) in the amount of $21.5 million and $34.0 million respectively,
compared to $3.2 and $5.3 million during the same periods in 2007. The
increase in current taxes was due to an increase in net income combined with a
decrease in capital expenditures in 2008.
We expect our U.S. current income and withholding taxes to average
approximately 25% of cash flow from U.S. operations based on current commodity
prices, our current development capital program and assuming excess funds are
repatriated to Canada.
Net Income
Net income for the second quarter of 2008 was $112.2 million or $0.68 per
trust unit compared to $40.1 million or $0.31 per trust unit in the same
period for 2007. Net income for the six months ended June 30, 2008 was $233.6
million or $1.50 per trust unit compared to $148.0 million or $1.18 per trust
unit for the same period in 2007. The $85.6 million increase in net income for
the six months ended was primarily due to an increase in oil and gas sales of
$477.7 million which was offset by an increase in royalties of $88.1 million
and an increase in commodity derivative instrument losses of $307.7 million.
Cash Flow from Operating Activities
Cash flow for the three and six months ended June 30, 2008 was $364.5
million ($2.22 per trust unit) and $620.7 million ($3.98 per trust unit)
respectively, compared to $237.5 million ($1.85 per trust unit) and $430.7
million ($3.42 per trust unit) for the three and six months ended June 30,
2007. The increases per trust unit were primarily a result of strong commodity
prices combined with an increase in production due to the Focus acquisition.
Selected Financial Results
Three months ended June 30, Three months ended June 30,
2008 2007
Per BOE of Operating Non-Cash Operating Non-Cash
production Cash & Other Cash & Other
(6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production
per day 100,188 82,478
-------------------------------------------------------------------------
Weighted average
sales
price(2) $ 80.56 $ - $ 80.56 $ 50.96 $ - $ 50.96
Royalties (15.14) - (15.14) (9.63) - (9.63)
Commodity
derivative
instruments (7.03) (17.65) (24.68) (0.15) 2.54 2.39
Operating costs (9.43) - (9.43) (9.80) 0.11 (9.69)
General and
administrative (1.67) (0.23) (1.90) (1.94) (0.28) (2.22)
Interest expense,
net of other
income (1.37) (0.70) (2.07) (1.25) (0.29) (1.54)
Foreign exchange
gain/(loss) 0.05 0.10 0.15 (0.11) 0.64 0.53
Current income
tax (1.78) - (1.78) (0.43) - (0.43)
Restoration and
abandonment cash
costs (0.52) 0.52 - (0.51) 0.51 -
Depletion,
depreciation,
amortization and
accretion - (18.93) (18.93) - (15.58) (15.58)
Future income tax
recovery/
(expense) - 5.53 5.53 - (9.45) (9.45)
-------------------------------------------------------------------------
Total per BOE $ 43.67 $(31.36) $ 12.31 $ 27.14 $(21.80) $ 5.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash Flow from Operating Activities before changes in non-cash
working capital.
(2) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Six months ended June 30, Six months ended June 30,
2008 2007
Per BOE of Operating Non-Cash Operating Non-Cash
production Cash & Other Cash & Other
(6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production per
day 94,681 84,244
-------------------------------------------------------------------------
Weighted average
sales
price(2) $ 71.85 $ - $ 71.85 $ 50.00 $ - $ 50.00
Royalties (13.46) - (13.46) (9.43) - (9.43)
Commodity
derivative
instruments (4.35) (13.95) (18.30) 0.45 (0.95) (0.50)
Operating costs (9.21) 0.04 (9.17) (9.16) 0.06 (9.10)
General and
administrative (1.75) (0.21) (1.96) (1.93) (0.28) (2.21)
Interest expense,
net of other
income (1.10) (0.01) (1.11) (1.25) (0.03) (1.28)
Foreign exchange
(loss)/gain - (0.13) (0.13) (0.09) 0.32 0.23
Current income
tax (1.49) - (1.49) (0.35) - (0.35)
Restoration and
abandonment cash
costs (0.51) 0.51 - (0.48) 0.48 -
Depletion,
depreciation,
amortization
and accretion - (18.12) (18.12) - (15.48) (15.48)
Future income
tax recovery/
(expense) - 4.97 4.97 - (3.10) (3.10)
Gain on sale of
marketable
securities(3) - 0.48 0.48 - 0.92 0.92
-------------------------------------------------------------------------
Total per BOE $ 39.98 $(26.42) $ 13.56 $ 27.76 $(18.06) $ 9.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash Flow from Operating Activities before changes in non-cash
working capital.
(2) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(3) Gain on sale of marketable securities was a cash item however it is
included in cash flow from investing activities not cash flow from
operating activities.
Selected Canadian and U.S. Results
The following tables provide a geographical analysis of key operating and
financial results for the three and six months ended June 30, 2008 and 2007.
(CDN$ millions, Three months ended Three months ended
except per unit June 30, 2008 June 30, 2007
amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily
Production
Volumes
Natural gas
(Mcf/day) 346,554 12,795 359,349 254,122 10,824 264,946
Crude oil
(bbls/day) 25,652 9,834 35,486 24,563 9,615 34,178
Natural gas
liquids
(bbls/day) 4,810 - 4,810 4,143 - 4,143
Total Daily
Sales
(BOE/day) 88,221 11,967 100,188 71,059 11,419 82,478
Pricing(1)
Natural gas
(per Mcf) $ 9.80 $ 11.80 $ 9.87 $ 7.03 $ 7.37 $ 7.04
Crude oil
(per bbl) 112.41 118.27 114.04 59.59 67.94 61.93
Natural gas
liquids
(per bbl) 80.55 - 80.55 53.34 - 53.34
Capital Expenditures
Development
capital and
office $ 76.5 $ 13.5 $ 90.0 $ 49.1 $ 32.9 $ 82.0
Acquisitions
of oil and
gas
properties 2.0 (0.2) 1.8 204.5 (0.5) 204.0
Dispositions of
oil and gas
properties (0.1) - (0.1) (5.5) - (5.5)
Revenues
Oil and gas
sales(1) $ 614.8 $ 119.6 $ 734.4 $ 315.8 $ 66.7 $ 382.5
Royalties(2) (112.4) (25.6) (138.0) (58.9) (13.3) (72.2)
Financial
contracts (225.0) - (225.0) 18.0 - 18.0
Expenses
Operating $ 80.8 $ 5.2 $ 86.0 $ 70.6 $ 2.2 $ 72.8
General and
admini-
strative 16.0 1.3 17.3 14.9 1.8 16.7
Depletion,
depreciation,
amortization
and accretion 149.6 22.9 172.5 89.5 27.4 116.9
Current income
taxes
(recovery)/
expense (5.3) 21.5 16.2 - 3.2 3.2
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) U.S. royalties include state production tax.
(CDN$ millions, Six months ended Six months ended
except per June 30, 2008 June 30, 2007
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily Production
Volumes
Natural gas
(Mcf/day) 321,177 12,382 333,559 260,051 10,249 270,300
Crude oil
(bbls/day) 24,687 9,689 34,376 24,946 9,923 34,869
Natural gas
liquids
(bbls/day) 4,712 - 4,712 4,325 - 4,325
Total Daily
Sales
(BOE/day) 82,929 11,752 94,681 72,613 11,631 84,244
Pricing(1)
Natural gas
(per Mcf) $ 8.72 $ 10.42 $ 8.79 $ 7.12 $ 7.33 $ 7.13
Crude oil
(per bbl) 98.89 104.50 100.47 57.24 65.41 59.56
Natural gas
liquids (per
bbl) 75.29 - 75.29 48.55 - 48.55
Capital Expenditures
Development
capital and
office $ 184.8 $ 33.1 $ 217.9 $ 122.6 $ 70.8 $ 193.4
Acquisitions
of oil and
gas
properties 9.4 (0.1) 9.3 206.6 60.8 267.4
Dispositions
of oil and
gas
properties (2.2) - (2.2) (5.5) - (5.5)
Revenues
Oil and gas
sales(1) $1,030.3 $ 207.8 $1,238.1 $ 631.4 $ 131.1 $ 762.5
Royalties(2) (187.4) (44.5) (231.9) (117.7) (26.1) (143.8)
Financial
contracts (315.4) - (315.4) (7.6) - (7.6)
Expenses
Operating $ 149.4 $ 8.6 $ 158.0 $ 134.5 $ 4.3 $ 138.8
General and
admini-
strative 31.1 2.7 33.8 29.7 4.1 33.8
Depletion,
depreciation,
amortization
and accretion 268.0 44.3 312.3 181.0 55.0 236.0
Current income
taxes
(recovery)/
expense (7.9) 33.7 25.8 - 5.3 5.3
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) U.S. royalties include state production tax.
Quarterly Financial Information
Oil and gas sales were relatively flat for the first three quarters of
2006 but began to decrease in the fourth quarter 2006 through 2007 due to
softening natural gas prices. During the first half of 2008 production and
commodity prices were increasing resulting in additional oil and gas sales.
Net income has been affected by additional production from the Focus
acquisition, fluctuating commodity prices (both current and future), risk
management costs, the strengthening Canadian dollar, higher operating costs,
changes in future tax provisions as well as changes to accounting policies
adopted during 2007.
Net Income
Quarterly Financial Information Oil per trust unit
($ millions, except per trust and Gas Net ------------------
unit amounts) Sales(1) Income Basic Diluted
-------------------------------------------------------------------------
2008
Second Quarter $ 734.4 $ 112.2 $ 0.68 $ 0.68
First quarter 503.7 121.4 0.82 0.82
-----------------------------------------------------
Total $1,238.1 $ 233.6 $ 1.50 $ 1.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007
Fourth Quarter $ 389.8 $ 98.7 $ 0.76 $ 0.76
Third Quarter 364.8 93.0 0.72 0.72
Second Quarter 382.5 40.1 0.31 0.31
First quarter 380.0 107.9 0.88 0.87
-----------------------------------------------------
Total $1,517.1 $ 339.7 $ 2.66 $ 2.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006
Fourth Quarter $ 369.5 $ 110.2 $ 0.90 $ 0.89
Third Quarter 398.0 161.3 1.31 1.31
Second Quarter 403.5 146.0 1.19 1.19
First Quarter 401.7 127.3 1.08 1.07
-----------------------------------------------------
Total $1,572.7 $ 544.8 $ 4.48 $ 4.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Liquidity and Capital Resources
Sustainability of our Distributions and Asset Base
As an oil and gas producer we have a declining asset base and therefore
rely on ongoing development activities and acquisitions to replace production
and add additional reserves. Our future oil and natural gas production is
highly dependent on our success in exploiting our asset base and acquiring or
developing additional reserves. To the extent we are unsuccessful in these
activities our cash distributions could be reduced.
Development activities and acquisitions may be funded internally by
withholding a portion of cash flow or through external sources of capital such
as debt or the issuance of equity. To the extent that we withhold cash flow to
finance these activities, the amount of cash distributions to our unitholders
may be reduced. Should external sources of capital become limited or
unavailable, our ability to make the necessary development expenditures and
acquisitions to maintain or expand our asset base may be impaired and
ultimately reduce the amount of cash distributions.
Following the completion of the Focus acquisition, Enerplus has
approximately $10 billion of safe harbour growth capacity within the context
of the Government's "normal growth" guidelines for SIFT's. This amount is
calculated in reference to the combined market capitalizations of Enerplus and
Focus on October 31, 2006 and also includes equity that may be issued to
replace existing debt of both entities at that time.
Distribution Policy
The amount of cash distributions is proposed by management and approved
by the Board of Directors. We continually assess distribution levels with
respect to anticipated cash flows, debt levels and capital spending plans. The
level of cash withheld has historically varied between 10% and 40% of annual
cash flow from operating activities and is dependent upon numerous factors,
the most significant of which are the prevailing commodity price environment,
our current levels of production, debt obligations, funding requirements for
our development capital program and our access to equity markets.
Although we intend to continue to make cash distributions to our
unitholders, these distributions are not guaranteed. To the extent there is
taxable income at the trust level, determined in accordance with the Canadian
Income Tax Act, the distribution of that taxable income is non-discretionary.
Cash Flow from Operating Activities, Cash Distributions and Payout Ratio
Cash flow from operating activities and cash distributions are reported
on the Consolidated Statements of Cash Flows. During the second quarter of
2008 cash distributions of $202.3 million were funded entirely through cash
flow of $364.5 million. For the six months ended June 30, 2008 our cash
distributions were $394.7 million and were funded entirely through cash flow
of $620.7 million.
Our payout ratio, which is calculated as cash distributions divided by
cash flow, was 56% and 64% for the three and six months ended June 30, 2008
respectively, compared to 68% and 74% for the same periods in 2007. See
"Non-GAAP Measures" in this MD&A.
In aggregate, our 2008 second quarter cash distributions of
$202.3 million combined with our development capital and office expenditures
of $90.0 million totaled $292.3 million, or approximately 80% of our cash flow
of $364.5 million. For the six month ended June 30, 2008 our cash
distributions of $394.7 million combined with our development capital and
office expenditures of $217.9 million totaled $612.6 million, or approximately
99% of our cash flow of $620.7 million. We expect to support our distributions
and capital expenditures with our cash flow, however we will continue to fund
acquisitions and growth through additional debt and equity when required.
There will also be years when we are investing capital in opportunities that
do not immediately generate cash flow (such as our Kirby oil sands project)
where we may also use debt and equity to support the investment.
For the three months ended June 30, 2008, our cash distributions exceeded
our net income by $90.1 million (2007 - $122.5 million), however net income
includes $290.6 million of non-cash items (2007 - $167.4 million). For the six
months ended June 30, 2008 our cash distributions exceeded our net income by
$161.1 million (2007 - $172.3 million) which included $472.3 million of
non-cash items (2007 - $296.5 million). Non-cash items such as changes in the
fair value of our derivative instruments and future income taxes do not reduce
or increase our cash flow from operations. Future income taxes can fluctuate
from period to period as a result of changes in tax rates as well as changes
in interest, royalties and dividends from our operating subsidiaries paid to
the Fund. In addition, other non-cash charges such as DDA&A are not a good
proxy for the cost of maintaining our productive capacity as they are based on
the historical costs of our PP&E and not the fair market value of replacing
those assets within the context of the current environment.
It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. Therefore we do not
distinguish maintenance capital separately from development capital spending.
The level of investment in a given period may not be sufficient to
replace productive capacity given the natural declines associated with oil and
natural gas assets. In these instances a portion of the cash distributions
paid to unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income:
Three months Six months Year ended Year ended
($ millions, except ended June ended June December December
per unit amounts) 30, 2008 30, 2008 31, 2007 31, 2006
-------------------------------------------------------------------------
Cash flow from
operating
activities $ 364.5 $ 620.7 $ 868.5 $ 863.7
Cash distributions 202.3 394.7 646.8 614.3
-------------------------------------------------------------------------
Excess of cash flow
over cash
distributions $ 162.2 $ 226.0 $ 221.7 $ 249.4
Net income $ 112.2 $ 233.6 $ 339.7 $ 544.8
Shortfall of net
income over cash
distributions (90.1) (161.1) (307.1) (69.5)
Cash distributions
per weighted average
trust unit $ 1.23 $ 2.53 $ 5.07 $ 5.05
Payout ratio(1) 56% 64% 74% 71%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow from operating
activities. See "Non-GAAP Measures" in this MD&A.
Long-Term Debt
Long-term debt at June 30, 2008 was $1,028.3 million which is comprised
of $792.2 million of bank indebtedness and $236.1 million of senior unsecured
notes. The increase in long-term debt compared to December 31, 2007 of
$301.6 million is mainly due to the $330.9 million of debt that was assumed on
the Focus acquisition. We reduced long term debt by $68.7 million during the
second quarter of 2008 with excess cash flow.
Our working capital deficiency, excluding cash, at June 30, 2008
increased $106.9 million to $310.3 million from $203.4 million at December 31,
2007. Excluding current deferred financial assets and credits and the related
current future income taxes, our working capital deficiency decreased by
$63.5 million compared to December 31, 2007. This decrease is primarily due to
higher accounts receivable attributable to higher commodity prices and
production levels.
We continue to maintain a conservative balance sheet as demonstrated
below:
June December
Financial Leverage and Coverage 30, 2008 31, 2007
-------------------------------------------------------------------------
Long-term debt to trailing cash flow 0.9x 0.8x
Cash flow to interest expense 20.6x 25.8x
Long-term debt to long-term debt plus equity 21% 22%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
Cash flow and interest expense are 12-months trailing.
After applying the proceeds of approximately $500 million from the sale
of our Joslyn interest to our debt, we anticipate our debt to cash flow ratio
will be 0.4 times.
At June 30, 2008 Enerplus had a $1.4 billion unsecured covenant based
three-year term bank facility ending November 2010, through its wholly-owned
subsidiary EnerMark Inc. We have the ability to extend the facility each year
or repay the entire balance at the end of the three-year term. This bank debt
carries floating interest rates that we expect to range between 55.0 and
110.0 basis points over Bankers' Acceptance rates, depending on Enerplus'
ratio of senior debt to earnings before interest, taxes and non-cash items.
Payments with respect to the bank facilities, senior unsecured notes and
other third party debt have priority over claims of and future distributions
to the unitholders. Unitholders have no direct liability should cash flow be
insufficient to repay this indebtedness. The agreements governing these bank
facilities and senior unsecured notes stipulate that if we default or fail to
comply with certain covenants, the ability of the Fund's operating
subsidiaries to make payments to the Fund and consequently the Fund's ability
to make distributions to the unitholders may be restricted. At June 30, 2008
we were in compliance with our debt covenants, the most restrictive of which
limits our long-term debt to three times trailing cash flow including
acquisition cash flows. Refer to "Debt of Enerplus" in our Annual Information
Form for the year ended December 31, 2007 for a detailed description of these
covenants.
Principal payments on Enerplus' senior unsecured notes are required
commencing in 2010 and 2011 and are more fully discussed in Note 5.
We continue to have adequate liquidity to fund planned development
capital spending during 2008 through a combination of cash flow retained by
the business and debt, if needed.
Trust Unit Information
We had 164,709,000 trust units outstanding at June 30, 2008. This
includes the 30,150,000 units issued on February 13, 2008 to acquire Focus and
7,885,000 exchangeable limited partnership units of Enerplus Exchangeable
Limited Partnership outstanding from the original 9,087,000 exchangeable
limited partnership units which were assumed with the Focus acquisition. The
remaining 7,885,000 exchangeable limited partnership units are convertible at
the option of the holder into 0.425 of an Enerplus trust unit (3,351,000 trust
units). This compares to 129,205,000 trust units at June 30, 2007 and
129,813,000 trust units outstanding at December 31, 2007. Including the
exchangeable limited partnership units the weighted average basic number of
trust units outstanding for the six months ended June 30, 2008 was 155,984,000
(2007 - 125,849,000). At July 31, 2008 we had 164,807,000 trust units
outstanding including the equivalent limited partnership units.
During the three months ended June 30, 2008, 683,000 trust units (2007 -
416,000) were issued pursuant to the Trust Unit Monthly Distribution
Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights
incentive plan, net of redemptions. This resulted in $28.8 million (2007 -
$18.6 million) of additional equity to the Fund. For the six months ended
June 30, 2008 $40.7 million of additional equity (2007 - $31.7 million) and
1,000,000 trust units (2007 - 699,000) were issued pursuant to the DRIP and
the trust unit options and rights plans. For further details see Note 8.
Canadian and U.S. Taxpayers
Enerplus currently estimates that approximately 95% of cash distributions
paid to Canadian and U.S unitholders will be taxable and the remaining 5% will
be a tax deferred return of capital. Actual taxable amounts may vary depending
on actual distributions which are dependent upon, among other things,
production, commodity prices and cash flow experienced throughout the year.
For U.S. taxpayers the taxable portion of cash distributions are
considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers
this should be a "Qualified Dividend" eligible for the reduced tax rate. This
preferential rate of tax for "Qualified Dividends" is set to expire at the end
of 2010. Draft U.S. Tax Bill 1672, which proposes to make dividends from
Canadian income trusts such as Enerplus ineligible for treatment as a
"Qualified Dividend", has not progressed in the U.S. approval process.
Therefore, we still cannot determine when or even if Bill 1672 will be enacted
as presented.
In July 2008, Enerplus estimated its non-resident ownership to be
approximately 64%.
Greenhouse Gas and Carbon Emissions
Enerplus continues to monitor and evaluate the developments associated
with carbon emissions regulations associated with environmental policy and
legislation in all jurisdictions where we operate. In particular, we are
currently reviewing the Government of Canada's "Turning the Corner" plan.
Given Enerplus' interest in various oil sands development areas we will be
closely monitoring the development of these proposed federal regulations.
We will be working with government at all levels where we have operations
to assist in the development of regulatory design in an effort to strike a
productive balance between environmental responsibility and continued positive
economic impact. At this stage, without further clarity and specific details
from the government of Canada, it is very difficult to forecast the increased
costs associated with the proposed greenhouse gas and carbon capture
regulations.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
Convergence of Canadian GAAP with International Financial Reporting
Standards
In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP, as used by public entities, being
converged with International Financial Reporting Standards (IFRS) by 2011. On
February 13, 2008 the AcSB confirmed that use of IFRS will be required for
public companies beginning January 1, 2011. We continue to assess the impact
of adopting IFRS and implementing plans for transition.
INTERNAL CONTROLS AND PROCEDURES
There were no changes in our internal control over financial reporting
during the quarter ended June 30, 2008 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 723 $ 1,702
Accounts receivable 242,999 145,602
Deferred financial assets (Note 9) 1,122 10,157
Future income taxes 86,140 10,807
Other current 7,336 6,373
-------------------------------------------------------------------------
338,320 174,641
Property, plant and equipment (Note 2) 5,570,402 3,872,818
Goodwill (Note 4) 603,255 195,112
Other assets (Note 9) 50,216 60,559
-------------------------------------------------------------------------
$ 6,562,193 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 289,576 $ 269,375
Distributions payable to unitholders 69,180 54,522
Deferred financial credits (Note 9) 289,100 52,488
-------------------------------------------------------------------------
647,856 376,385
-------------------------------------------------------------------------
Long-term debt (Note 5) 1,028,301 726,677
Deferred financial credits (Note 9) 85,621 90,090
Future income taxes 697,065 304,259
Asset retirement obligations (Note 3) 203,411 165,719
-------------------------------------------------------------------------
2,014,398 1,286,745
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 8) 5,438,100 4,032,680
Accumulated deficit (1,445,033) (1,283,953)
Accumulated other comprehensive income (93,128) (108,727)
-------------------------------------------------------------------------
(1,538,161) (1,392,680)
3,899,939 2,640,000
-------------------------------------------------------------------------
$ 6,562,193 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
Three months ended Six months ended
(CDN$ thousands) June 30, June 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Accumulated income,
beginning of period $ 2,408,321 $ 2,055,109 $ 2,286,927 $ 1,952,960
Adjustment for adoption
of financial
instruments standards - - - (5,724)
-------------------------------------------------------------------------
Revised accumulated
income, beginning of
period 2,408,321 2,055,109 2,286,927 1,947,236
Net income 112,230 40,084 233,624 147,957
-------------------------------------------------------------------------
Accumulated income,
end of period $ 2,520,551 $ 2,095,193 $ 2,520,551 $ 2,095,193
Accumulated cash
distributions,
beginning of period $(3,763,238) $(3,081,716) $(3,570,880) $(2,924,045)
Cash distributions (202,346) (162,607) (394,704) (320,278)
-------------------------------------------------------------------------
Accumulated cash
distributions, end of
period $(3,965,584) $(3,244,323) $(3,965,584) $(3,244,323)
-------------------------------------------------------------------------
Accumulated deficit,
end of period $(1,445,033) $(1,149,130) $(1,445,033) $(1,149,130)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(CDN$ thousands) Three months ended June 30, Six months ended June 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Balance, beginning of
period $ (87,505) $ (15,525) $ (108,727) $ (8,979)
Transition
adjustments on
adoption:
Cash flow hedges - - - 660
Available for sale
marketable
securities - - - 14,252
Other comprehensive
(loss)/income (5,623) (49,853) 15,599 (71,311)
-------------------------------------------------------------------------
Balance, end of
period $ (93,128) $ (65,378) $ (93,128) $ (65,378)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(CDN$ thousands except Three months ended Six months ended
per trust unit amounts) June 30, June 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 741,470 $ 387,926 $ 1,251,539 $ 773,797
Royalties (138,040) (72,214) (231,876) (143,762)
Commodity derivative
instruments (Note 9) (225,015) 17,954 (315,394) (7,652)
Other income 411 272 15,527 14,432
-------------------------------------------------------------------------
378,826 333,938 719,796 636,815
-------------------------------------------------------------------------
Expenses
Operating 85,974 72,756 157,990 138,786
General and
administrative 17,327 16,660 33,764 33,770
Transportation 7,127 5,453 13,444 11,317
Interest (Note 6) 19,313 11,847 26,301 19,962
Foreign exchange
(Note 7) (1,408) (3,956) 2,276 (3,474)
Depletion,
depreciation,
amortization and
accretion 172,496 116,909 312,290 236,000
-------------------------------------------------------------------------
300,829 219,669 546,065 436,361
-------------------------------------------------------------------------
Income before taxes 77,997 114,269 173,731 200,454
Current taxes 16,211 3,227 25,752 5,291
Future income tax
(recovery)/expense (50,444) 70,958 (85,645) 47,206
-------------------------------------------------------------------------
Net Income $ 112,230 $ 40,084 $ 233,624 $ 147,957
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust
unit
Basic $ 0.68 $ 0.31 $ 1.50 $ 1.18
Diluted $ 0.68 $ 0.31 $ 1.50 $ 1.18
-------------------------------------------------------------------------
Weighted average number
of trust units
outstanding
(thousands)(1)
Basic 164,483 128,361 155,984 125,849
Diluted 164,633 128,419 156,102 125,904
-------------------------------------------------------------------------
(1) Includes the exchangeable limited partnership units.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(CDN$ thousands) Three months ended June 30, Six months ended June 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net income $ 112,230 $ 40,084 $ 223,624 $ 147,957
-------------------------------------------------------------------------
Other comprehensive
income/(loss), net
of tax:
Unrealized gain/(loss)
on marketable
securities - 2,502 2,578 (654)
Realized gains on
marketable securities
included in net
income - - (6,158) (11,654)
Gains and losses on
derivatives
designated as hedges
in prior periods
included in net
income - (176) 74 (380)
Change in cumulative
translation adjustment (5,623) (52,179) 19,105 (58,623)
-------------------------------------------------------------------------
Other comprehensive
income/(loss) (5,623) (49,853) 15,599 (71,311)
-------------------------------------------------------------------------
Comprehensive income $ 106,607 $ (9,769) $ 239,223 $ 76,646
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended Six months ended
(CDN$ thousands) June 30, June 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Operating Activities
Net income $ 112,230 $ 40,084 $ 233,624 $ 147,957
Non-cash items add/
(deduct):
Depletion, depreciation,
amortization and
accretion 172,496 116,909 312,290 236,000
Change in fair value
of derivative
instruments (Note 9) 168,787 (1,394) 235,259 33,453
Unit based
compensation (Note 8) 2,094 2,107 3,580 4,218
Foreign exchange on
translation of senior
notes (Note 7) (2,158) (20,808) 7,075 (23,690)
Future income tax (50,444) 70,958 (85,645) 47,206
Amortization of senior
notes premium (157) (159) (310) (328)
Reclassification
adjustments from AOCI
to net income - (176) 92 (380)
Gain on sale of
marketable securities - - (8,263) (14,055)
Asset retirement
obligations settled
(Note 3) (4,747) (3,803) (8,767) (7,117)
-------------------------------------------------------------------------
398,101 203,718 688,935 423,264
(Increase)/Decrease in
non-cash operating
working capital (33,644) 33,764 (68,262) 7,399
-------------------------------------------------------------------------
Cash flow from
operating activities 364,457 237,482 620,673 430,663
-------------------------------------------------------------------------
Financing Activities
Issue of trust units,
net of issue costs
(Note 8) 28,811 218,204 40,696 231,224
Cash distributions to
unitholders (202,346) (162,607) (394,704) (320,278)
(Decrease)/Increase in
bank credit facilities (68,656) (35,992) (36,054) 64,350
Decrease in non-cash
financing working capital 241 180 14,658 2,549
-------------------------------------------------------------------------
Cash flow from financing
activities (241,950) 19,785 (375,404) (22,155)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (89,961) (82,000) (217,884) (193,354)
Property acquisitions (1,740) (149,266) (9,289) (212,644)
Property dispositions 86 (1,107) 2,208 (1,152)
Proceeds on sale of
marketable securities - - 18,320 16,467
Increase in non-cash
investing working
capital (30,218) (20,627) (40,636) (14,497)
-------------------------------------------------------------------------
Cash flow from investing
activities (121,833) (253,000) (247,281) (405,180)
-------------------------------------------------------------------------
Effect of exchange rate
changes on cash (1,404) (2,311) 1,033 (1,402)
-------------------------------------------------------------------------
Change in cash (730) 1,956 (979) 1,926
Cash, beginning of period 1,453 94 1,702 124
-------------------------------------------------------------------------
Cash, end of period $ 723 $ 2,050 $ 723 $ 2,050
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes
paid $ 24,756 $ 4,005 $ 33,758 $ 7,246
Cash interest paid $ 17,980 $ 14,644 $ 26,298 $ 20,730
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements of Enerplus Resources Fund
("Enerplus" or the "Fund") have been prepared by management following the
same accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2007. The
note disclosure requirements for annual statements provide additional
disclosure to that required for these interim statements. Accordingly,
these interim statements should be read in conjunction with the Fund's
consolidated financial statements for the year ended December 31, 2007.
With the exception of additional disclosures included in Note 9 regarding
financial instruments and capital management, the disclosures provided
below are incremental to those included in the 2007 annual consolidated
financial statements of the Fund.
2. PROPERTY, PLANT AND EQUIPMENT (PP&E)
June 30, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Property, plant and equipment $ 8,440,623 $ 6,429,241
Accumulated depletion, depreciation and
accretion (2,870,221) (2,556,423)
-------------------------------------------------------------------------
Net property, plant and equipment $ 5,570,402 $ 3,872,818
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development general and administrative ("G&A") expense of
$10,812,000 (2007 - $8,158,000) is included in PP&E for the six months
ended June 30, 2008. Excluded from PP&E for the depletion and
depreciation calculation is $351,124,000 (2007 - $302,459,000) related to
the Joslyn development project and the Kirby Oil Sands project, both of
which have not yet commenced commercial production.
3. ASSET RETIREMENT OBLIGATIONS
Following is a reconciliation of the asset retirement obligations:
Six months Year
ended ended
June 30, December
($ thousands) 2008 31, 2007
-------------------------------------------------------------------------
Asset retirement obligations, beginning of
period $ 165,719 $ 123,619
Corporate acquisition 36,784 -
Changes in estimates 1,475 46,000
Property acquisition and development activity 2,667 6,441
Dispositions (110) (756)
Asset retirement obligations settled (8,767) (16,280)
Accretion expense 5,643 6,695
-------------------------------------------------------------------------
Asset retirement obligations, end of period $ 203,411 $ 165,719
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. ACQUISITIONS
Focus Energy Trust
On February 13, 2008 Enerplus closed the acquisition of Focus Energy
Trust ("Focus"). Under the plan of arrangement, Focus unitholders
received 0.425 of an Enerplus trust unit for each Focus trust unit and
Focus Exchangeable Limited Partnership Units became exchangeable into
Enerplus trust units at the option of the holder on the basis of 0.425 of
an Enerplus trust unit for each Focus Exchangeable Limited Partnership
Unit. Total consideration was approximately $1,366,494,000 consisting of
30,149,752 trust units issued, 9,086,666 exchangeable limited partnership
units assumed (convertible into 3,861,833 trust units) and estimated
transaction costs of $5,350,000. The Fund also assumed bank debt plus an
estimated working capital deficit including certain transaction costs
paid by Focus of $357,305,000.
The acquisition has been accounted for using the purchase method of
accounting and results from the operations of Focus from February 13,
2008 onward have been included in the Fund's consolidated financial
statements. The allocation of the consideration paid to the fair value of
the assets acquired and liabilities assumed plus future income tax cost
are summarized below:
Net Assets Acquired ($ thousands)
-------------------------------------------------------------------------
Property, plant and equipment $ 1,757,520
Other assets 4,566
Goodwill 403,588
Working capital deficit (26,393)
Deferred financial credits (5,919)
Long-term debt (330,912)
Asset retirement obligations (36,784)
Future income taxes (399,172)
-------------------------------------------------------------------------
Total net assets acquired $ 1,366,494
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consideration paid ($ thousands)
-------------------------------------------------------------------------
Trust units issued(1) $ 1,206,593
Exchangeable limited partnership units assumed(1) 154,551
Transaction costs 5,350
-------------------------------------------------------------------------
Total consideration paid $ 1,366,494
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Recorded based on a fair value of $40.02 per trust unit
5. LONG-TERM DEBT
June 30, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Bank credit facilities (a) $ 792,205 $ 497,347
Senior notes (b)
US$175 million (issued June 19, 2002) 181,092 175,973
US$54 million (issued October 1, 2003) 55,004 53,357
-------------------------------------------------------------------------
Total long-term debt $ 1,028,301 $ 726,677
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus currently has a $1.4 billion unsecured covenant based three-year
term facility. The facility is extendible each year with a bullet payment
required at the end of the three year term. Various borrowing options are
available under the facility including prime rate based advances and
bankers' acceptance loans. This facility carries floating interest rates
that are expected to range between 55.0 and 110.0 basis points over
bankers' acceptance rates, depending on Enerplus' ratio of senior debt to
earnings before interest, taxes and non-cash items. The effective
interest rate on the facility for the six months ended June 30, 2008 was
4.0% (June 30, 2007 - 4.9 %).
(b) Senior Unsecured Notes
On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes
that mature June 19, 2014. The notes have a coupon rate of 6.62% priced
at par, with interest paid semi-annually on June 19 and December 19 of
each year. Principal payments are required in five equal installments
beginning June 19, 2010 and ending June 19, 2014. Concurrent with the
issuance of the notes on June 19, 2002, the Fund entered into a cross
currency and interest rate swap ("CCIRS") with a syndicate of financial
institutions. Under the terms of the swap, the amount of the notes was
fixed for purposes of interest and principal repayments at a notional
amount of CDN$268,328,000. Interest payments are made on a floating rate
basis, set at the rate for three-month Canadian bankers' acceptances,
plus 1.18%.
On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes
that mature October 1, 2015. The notes have a coupon rate of 5.46% priced
at par with interest paid semi-annually on April 1 and October 1 of each
year. Principal payments are required in five equal installments
beginning October 1, 2011 and ending October 1, 2015. The notes are
translated into Canadian dollars using the period end foreign exchange
rate. In September 2007 Enerplus entered into foreign exchange swaps that
effectively fix the five principal payments on the US$54,000,000 senior
unsecured notes at a CDN/US exchange rate of 1.02 or CDN$55,080,000.
On January 1, 2007 in conjunction with the adoption of CICA Sections 3855
and 3865, Enerplus elected to stop designating the CCIRS as a fair value
hedge on the US$175,000,000 senior notes. As a result, the Fund recorded
the senior notes at their fair value of US$178,681,000. The premium
amount of US$3,681,000, representing the difference between the
January 1, 2007 fair value and the face amount of the senior notes, will
be amortized to net income over the remaining term of the notes using the
effective interest method. The effective interest rate over the remaining
term of the senior notes is 6.16%. The senior notes are carried at
amortized cost and are translated into Canadian dollars using the period
end foreign exchange rate. At June 30, 2008 the amortized cost of the
US$175,000,000 senior notes was US$177,785,000.
6. INTEREST EXPENSE
Three months ended June 30, Six months ended June 30,
($ thousands) 2008 2007 2008 2007
-------------------------------------------------------------------------
Realized
Interest on long-term
debt $ 12,918 $ 9,731 $ 26,263 $ 19,481
Unrealized
Loss/(gain) on cross
currency interest
rate swap 7,219 4,193 (1,125) 2,909
(Gain)/loss on
interest rate swaps (667) (1,918) 1,473 (2,100)
Amortization of the
premium on senior
unsecured notes (157) (159) (310) (328)
-------------------------------------------------------------------------
Interest expense $ 19,313 $ 11,847 $ 26,301 $ 19,962
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. FOREIGN EXCHANGE
Three months ended June 30, Six months ended June 30,
($ thousands) 2008 2007 2008 2007
-------------------------------------------------------------------------
Realized
Foreign exchange
(gain)/loss $ (550) $ 854 $ 18 $ 1,442
Unrealized
Foreign exchange
(gain)/loss on
translation of U.S.
dollar denominated
senior notes (2,158) (20,808) 7,075 (23,690)
Foreign exchange
(gain)/loss on
cross currency
interest rate
swap (320) 15,998 (4,491) 18,774
Foreign exchange
loss/(gain) on
foreign exchange
swaps 1,620 - (326) -
-------------------------------------------------------------------------
Foreign exchange
(gain)/loss $ (1,408) $ (3,956) $ 2,276 $ (3,474)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed
to foreign currency fluctuations and are translated into Canadian dollars
at the exchange rate in effect at the balance sheet date. Foreign
exchange gains and losses are included in the determination of net income
for the period.
8. UNITHOLDERS' CAPITAL
Unitholders' capital as presented on the Consolidated Balance Sheets
consists of trust unit capital, exchangeable partnership unit capital and
contributed surplus.
Six months Year ended
Unitholders' capital ended June December
($ thousands) 30, 2008 31, 2007
-------------------------------------------------------------------------
Trust units $ 5,286,045 $ 4,020,228
Exchangeable limited partnership units 134,106 -
Contributed surplus 17,949 12,452
-------------------------------------------------------------------------
Balance, end of period $ 5,438,100 $ 4,032,680
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Trust Units
Authorized: Unlimited number of trust units
Six months ended Year ended
(thousands) June 30, 2008 December 31, 2007
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance, beginning of
period 129,813 $ 4,020,228 123,151 $ 3,706,821
Issued for cash:
Pursuant to public
offerings - - 4,250 199,558
Pursuant to rights
incentive plan 174 5,755 205 6,758
Cancelled trust units (116) (3,794) - -
Exchangeable limited
partnership units
exchanged 511 20,445 - -
Trust unit rights
incentive plan (non-
cash) - exercised - 1,877 - 2,288
DRIP(*), net of redemptions 826 34,941 1,102 50,053
Issued for acquisition of
corporate and property
interests (non-cash) 30,150 1,206,593 1,105 54,750
-------------------------------------------------------------------------
161,358 $ 5,286,045 129,813 $ 4,020,228
Equivalent exchangeable
partnership units 3,351 134,106 - -
-------------------------------------------------------------------------
Balance, end of period 164,709 $ 5,420,151 129,813 $ 4,020,228
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Distribution Reinvestment and Unit Purchase Plan
On February 13, 2008 the Fund issued 30,149,752 trust units pursuant to
the Focus acquisition valued at $40.02 per trust unit, being the weighted
average trading price of the Fund's units on the Toronto Stock Exchange
during the five day trading period surrounding the announcement date of
December 3, 2007, for a recorded value of $1,206,593,000.
(b) Exchangeable Limited Partnership Units
In conjunction with the Focus acquisition 9,086,666 Exchangeable Limited
Partnership Units issued by Focus Limited Partnership (since renamed
Enerplus Exchangeable Limited Partnership) became exchangeable into
Enerplus trust units at a ratio of 0.425 of an Enerplus trust unit for
each Limited Partnership unit (3,861,833 trust units). The exchangeable
limited partnership units are convertible at any time into trust units at
the option of the holder and receive cash distributions and have voting
rights in accordance with the 0.425 exchange ratio. The Board of
Directors may redeem the exchangeable limited partnership units after
January 8, 2017, unless certain conditions are met to permit an earlier
redemption date. The exchangeable limited partnership units are not
listed on any stock exchange and are not transferable. The exchangeable
limited partnership units were recorded at fair value, based on the
Enerplus' five day weighted average trust unit trading price surrounding
the December 3, 2007 announcement date of $40.02 multiplied by the 0.425
exchange ratio.
During the second quarter of 2008, 1,202,000 exchangeable limited
partnership units were converted into 511,000 trust units. As at June 30,
2008, the 7,885,000 outstanding exchangeable limited partnership units
represent the equivalent of 3,351,000 trust units.
Six months ended Year ended
(thousands) June 30, 2008 December 31, 2007
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Assumed on February
13, 2008 9,087 $ 154,551 - $ -
Exchanged for trust units (1,202) (20,445) - -
-------------------------------------------------------------------------
Balance, end of period 7,885 $ 134,106 - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Contributed Surplus
Six months Year
ended ended
June 30, December
Contributed surplus ($ thousands) 2008 31, 2007
-------------------------------------------------------------------------
Balance, beginning of period $ 12,452 $ 6,305
Trust unit rights incentive plan (non-cash) -
exercised (1,877) (2,288)
Trust unit rights incentive plan (non-cash) -
expensed 3,580 8,435
Cancelled trust units 3,794 -
-------------------------------------------------------------------------
Balance, end of period $ 17,949 $ 12,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(d) Trust Unit Rights Incentive Plan
As at June 30, 2008 a total of 4,324,000 rights were issued pursuant to
the Trust Unit Rights Incentive Plan ("Rights Incentive Plan") with an
average exercise price of $45.73 and were outstanding. This represents
2.6% of the total trust units outstanding of which 1,795,000 rights, with
an average exercise price of $45.70, were exercisable. Under the Rights
Incentive Plan, distributions per trust unit to Enerplus unitholders in a
calendar quarter which represent a return of more than 2.5% of the net
PP&E of Enerplus at the end of such calendar quarter may result in a
reduction in the exercise price of the rights. Results for the first and
second quarter of 2008 reduced the exercise price of the outstanding
rights by $0.43 per trust unit effective July 2008 and $0.41 per trust
unit effective October 2008.
Activity for the rights issued pursuant to the Rights Plan is as follows:
Six months ended Year ended
June 30, 2008 December 31, 2007
-------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Rights Exercise Rights Exercise
(000's) Price(1) (000's) Price(1)
-------------------------------------------------------------------------
Trust unit rights
outstanding
Beginning of period 3,404 $ 47.59 3,079 $ 48.53
Granted 1,348 42.34 816 48.71
Exercised (174) 33.01 (205) 32.90
Cancelled (254) 47.04 (286) 50.74
-------------------------------------------------------------------------
End of period 4,324 $ 45.73 3,404 $ 47.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable at end
of period 1,795 $ 45.70 1,635 $ 44.84
-------------------------------------------------------------------------
(1) Exercise price reflects grant prices less reduction in strike price
discussed above.
The Fund uses a binomial lattice option-pricing model to calculate the
estimated fair value of rights granted under the plan. Non-cash
compensation costs charged to general and administrative related to
rights issued for the three and six months ended June 30, 2008 were
$2,094,000 ($0.01 per unit) and $3,580,000 ($0.02 per unit) respectively.
Non-cash compensation costs for the three and six months ended June 30,
2007 were $2,107,000 ($0.02 per unit) and $4,218,000 ($0.03 per unit)
respectively.
(e) Basic and Diluted per Trust Unit Calculations
Basic per-unit calculations are calculated using the weighted average
number of trust units and exchangeable partnership units (converted at
the 0.425 exchange ratio) outstanding during the period. Diluted per-unit
calculations include additional trust units for the dilutive impact of
rights outstanding pursuant to the Rights Plan.
Net income per trust unit has been determined based on the following:
Six months ended June 30,
(thousands) 2008 2007
-------------------------------------------------------------------------
Weighted average trust units 153,138 125,849
Weighted average exchangeable partnership units(1) 2,846 -
-------------------------------------------------------------------------
Basic weighted average units outstanding 155,984 125,849
Dilutive impact of rights 118 55
-------------------------------------------------------------------------
Diluted weighted average units outstanding 156,102 125,904
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on the exchange ratio of 0.425
(f) Performance Trust Unit Plan
The Fund has a Performance Trust Unit ("PTU") plan for executives and
employees. Under the plan employees and participants receive cash
compensation in relation to the value of a specified number of underlying
notional trust units. The number of notional trust units awarded is
variable to individuals and they vest at the end of three years. Upon
vesting, the plan participant receives a cash payment based on the fair
value of the underlying trust units plus notional accrued distributions.
The value determined upon vesting of the PTU plans is dependent upon the
performance of the Fund compared to its peers over the three year period.
The level of performance within the peer group then determines a
performance multiplier.
For the three months and six months ended June 30, 2008 the Fund recorded
cash compensation costs of $1,217,000 (2007 - $570,000) and $2,300,000
(2007 - $915,000), respectively, under the plan which are included in
general and administrative expenses.
At June 30, 2008 there were 435,000 performance trust units outstanding.
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
(a) Fair Value of Financial Instruments
The fair value of a financial instrument is the amount of consideration
that would be agreed upon in an arm's-length transaction between
knowledgeable, willing parties who are under no compulsion to act. Fair
values are determined by reference to quoted bid or ask prices, as
appropriate, in the most advantageous active market for that instrument
to which we have immediate access. Where bid and ask prices are
unavailable, we would use the closing price of the most recent
transaction for that instrument. In the absence of an active market, we
determine fair values based on prevailing market rates for instruments
with similar characteristics. Fair values may also be determined based on
internal and external valuation models, such as option pricing models and
discounted cash flow analysis, that use observable market based inputs
and assumptions.
(b) Carrying Value and Fair Value of Non-derivative Financial Instruments
i. Cash
Cash is classified as held-for-trading and is reported at fair value.
ii. Accounts Receivable
Accounts receivable are classified as loans and receivables and are
reported at amortized cost. At June 30, 2008 the carrying value of
accounts receivable approximated their fair value.
iii. Marketable Securities
Marketable securities with a quoted market price in an active market are
classified as available-for-sale and are reported at fair value, with
changes in fair value recorded in other comprehensive income. During the
first quarter of 2008 the Fund disposed of certain publicly traded
marketable securities which resulted in a gain of $8,263,000 ($6,158,000
net of tax) being reclassified from accumulated other comprehensive
income to other income on the Consolidated Statement of Income.
As at June 30, 2008 the Fund did not hold any investments in publicly
traded marketable securities. As at December 31, 2007 the Fund reported
investments in publicly traded marketable securities at a fair value of
$14,676,000.
Marketable securities without a quoted market price in an active market
are reported at cost. As at June 30, 2008 the Fund reported investments
in marketable securities of private companies at cost of $49,966,000
(December 31, 2007 - $45,400,000) in Other Assets on the Consolidated
Balance Sheet.
iv. Accounts Payable & Distributions Payable to Unitholders
Accounts payable and distributions payable to unitholders are classified
as other liabilities and are reported at amortized cost. At June 30, 2008
the carrying value of these accounts approximated their fair value.
v. Long-term debt
Bank Credit Facilities
The bank credit facilities are classified as other liabilities and are
reported at amortized cost. At June 30, 2008 the carrying value of the
bank credit facilities approximated their fair value.
US$175 million senior notes
The US$175,000,000 senior notes, which are classified as other
liabilities, are reported at amortized cost of US$177,785,000 and are
translated to Canadian dollars at the period end exchange rate. At June
30, 2008 the Canadian dollar amortized cost of the senior notes was
approximately $181,092,000 and the fair value of these notes was
$189,082,000.
US$54 million senior notes
The US$54,000,000 are classified as other liabilities and reported at
their amortized cost of US$54,000,000 and are translated into Canadian
dollars at the period end exchange rate. At June 30, 2008 the Canadian
dollar amortized cost of the senior notes was approximately $55,004,000
and the fair value of these notes was approximately $54,830,000.
(c) Fair Value of Derivative Financial Instruments
The Fund's derivative financial instruments are classified as held for
trading and are reported at fair value with changes in fair value
recorded through earnings. The deferred financial assets and credits on
the Consolidated Balance Sheets result from recording derivative
financial instruments at fair value. At June 30, 2008 a current deferred
financial asset of $1,122,000, a current deferred financial credit of
$289,100,000 and a long-term deferred financial credit of $85,621,000 are
recorded on the consolidated balance sheet.
The deferred financial credit relating to crude oil instruments of
$199,211,000 at June 30, 2008 consists of the fair value of the financial
instruments, representing a loss position of $186,054,000 plus the
related deferred premiums of $13,157,000. The deferred financial credit
relating to natural gas instruments of $89,889,000 at June 30, 2008
consists of the fair value of the financial instruments of $84,619,000
plus the related deferred premiums of $5,270,000.
The following table summarizes the fair value as at June 30, 2008 and
change in fair value for the period ended June 30, 2008 of the Fund's
derivative financial instruments. The fair values indicated below are
determined using observable market data including price quotations in
active markets.
Cross
Currency
Interest Interest Foreign
Rate Rate Exchange Electricity
($ thousands) Swaps Swaps Swaps Swaps
-------------------------------------------------------------------------
Deferred financial
assets/(credits), at
December 31, 2007 $ (226) $ (89,439) $ (425) $ 450
Change in fair value
asset/(credits) (1,473)(3) 5,616(4) 326(5) 672(6)
-------------------------------------------------------------------------
Deferred financial
assets/(credits), end
of period $ (1,699) $ (83,823) $ (99) $ 1,122
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance sheet
classification:
Current asset/
(liability) $ - $ - $ - $ 1,122
Non-current asset/
(liability) $ (1,699) $ (83,823) $ (99) $ -
-------------------------------------------------------------------------
Commodity Derivative
Instruments
-------------------------
($ thousands) Oil Gas Total
------------------------------------------------------------
Deferred financial
assets/(credits), at
December 31, 2007 $(56,783)(1) $ 8,083(2) $ (138,340)
Change in fair value
asset/(credits) (142,428)(7) (97,972)(7) (235,259)
------------------------------------------------------------
Deferred financial
assets/(credits), end
of period $ (199,211) $ (89,889) $ (373,599)
------------------------------------------------------------
------------------------------------------------------------
Balance sheet
classification:
Current asset/
(liability) $ (199,211) $ (89,889) $ (287,978)
Non-current asset/
(liability) $ - $ - $ (85,621)
------------------------------------------------------------
(1) Includes the Focus opening credit balance at February 13, 2008 of
$4,295.
(2) Includes the Focus opening credit balance at February 13, 2008 of
$1,624.
(3) Recorded in interest expense.
(4) Recorded in foreign exchange expense (gain of $4,491) and interest
expense (gain of $1,125).
(5) Recorded in foreign exchange expense.
(6) Recorded in operating expense.
(7) Recorded in commodity derivative instruments (see below).
The following table summarizes the income statement effects of commodity
derivative instruments:
Three months ended June 30, Six months ended June 30,
($ thousands) 2008 2007 2008 2007
-------------------------------------------------------------------------
Loss/(gain) due to
change in fair value $ 160,955 $ (19,052) $ 240,400 $ 14,430
Net realized cash
losses/(gain) 64,060 1,098 74,994 (6,778)
-------------------------------------------------------------------------
Commodity derivative
instruments
loss/(gain) $ 225,015 $ (17,954) $ 315,394 $ 7,652
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(d) Risk Management
The Fund is exposed to a number of financial risks including market,
counterparty credit and liquidity risk. Risk management policies have
been established by the Fund's Board of Directors to assist in managing a
portion of these risks, with the goal of protecting earnings, cash flow
and unitholder value.
i. Market Risk
Market risk is comprised of commodity price risk, currency risk and
interest rate risk.
Commodity Price Risk
--------------------
The Fund is exposed to commodity price fluctuations as part of its normal
business operations, particularly in relation to its crude oil and
natural gas sales. The Fund manages a portion of these risks through a
combination of financial derivative and physical delivery sales
contracts. The Fund's policy is to enter into commodity contracts
considered appropriate to a maximum of 80% of forecasted production
volumes net of royalties. The Fund's outstanding commodity derivative
contracts as at July 25, 2008 are summarized below:
Crude Oil:
WTI US$/bbl
----------------------------------------
Fixed
Daily Price
Volumes Sold Purchased Sold and
bbls/day Call Put Put Swaps
-------------------------------------------------------------------------
Term
July 1, 2008 -
December 31, 2008
Collar 750 $ 77.00 $ 67.00 - -
3-Way option 1,000 $ 84.00 $ 66.00 $ 50.00 -
3-Way option 1,000 $ 84.00 $ 66.00 $ 52.00 -
3-Way option 1,000 $ 86.00 $ 68.00 $ 52.00 -
3-Way option 1,000 $ 87.50 $ 70.00 $ 52.00 -
3-Way option 1,500 $ 90.00 $ 70.00 $ 60.00 -
Put Spread 1,500 - $ 76.50 $ 58.00 -
Put Spread 1,500 - $ 78.00 $ 58.00 -
Put 700 - $ 86.10 - -
Swap 750 - - - $ 72.94
Swap 750 - - - $ 74.00
Swap 750 - - - $ 73.80
Swap 750 - - - $ 73.35
Swap(3) 400 - - - $ 78.53
Swap 1,500 - - - $ 92.00
Swap(3) 400 - - - $ 84.60
January 1, 2009 -
December 31, 2009
Collar 850 $100.00 $ 85.00 - -
3-Way option 1,000 $ 85.00 $ 70.00 $ 57.50 -
3-Way option 1,000 $ 95.00 $ 79.00 $ 62.00 -
Put Spread 500 - $ 92.00 $ 79.00 -
Put Spread(1) 500 - $ 92.00 $ 79.00 -
Swap 500 - - - $100.05
Put(1) 1400 - $122.00 - -
Put(2) 500 - $120.00 - -
-------------------------------------------------------------------------
(1) Financial contracts entered into during the second quarter of 2008.
(2) Financial contracts entered into subsequent to June 30, 2008.
(3) Acquired through the acquisition of Focus.
Natural Gas:
AECO CDN$/Mcf
-------------------------------------------------
Fixed
Daily Price
Volumes Sold Purchased Sold and
MMcf/day Call Put Put Swaps
-------------------------------------------------------------------------
Term
July 1, 2008 -
October 31, 2008
Collar 6.6 $ 8.44 $ 7.17 - -
Collar 6.6 $ 7.49 $ 6.44 - -
Collar 5.7 $ 7.39 $ 6.65 - -
Collar 11.4 $ 8.65 $ 7.60 - -
Collar 2.8 $ 8.65 $ 7.49 - -
Collar 2.8 $ 8.86 $ 7.91 - -
Collar 2.8 $ 8.97 $ 7.91 - -
3-Way option 5.7 $ 9.50 $ 7.54 $ 5.28 -
3-Way option 11.8 $ 7.91 $ 6.75 $ 5.49 -
3-Way option 11.8 $ 7.91 $ 6.75 $ 5.38 -
3-Way option 4.7 $ 8.23 $ 7.18 $ 5.28 -
Swap 4.7 - - - $ 8.18
Swap 7.6 - - - $ 6.79
Swap(3) 14.2 - - - $ 6.70
Swap(3) 14.2 - - - $ 7.17
Swap 2.8 - - - $ 7.91
Swap 2.8 - - - $ 7.87
Swap 2.8 - - - $ 8.44
Swap 2.8 - - - $ 8.49
Swap 5.7 - - - $ 8.76
November 1, 2008 -
March 31, 2009
Collar 5.7 $ 9.50 $ 8.44 - -
3-Way option 5.7 $ 10.71 $ 7.91 $ 5.80 -
3-Way option 1.9 $ 10.55 $ 8.44 $ 6.33 -
3-Way option 5.7 $ 10.71 $ 8.44 $ 6.33 -
3-Way option 9.5 $ 12.45 $ 8.97 $ 7.39 -
3-Way option(1) 4.7 $ 12.45 $ 8.97 $ 7.39 -
Put Spread 4.7 - $ 8.97 $ 7.39 -
Put Spread(1) 4.7 - $ 8.97 $ 7.39 -
Swap 2.8 - - - $ 9.42
Swap 2.8 - - - $ 9.28
Swap 2.8 - - - $ 9.34
Put(1) 4.7 - $ 11.34 - -
Put(2) 4.7 - $ 11.61 - -
Put(2) 4.7 - $ 9.50 - -
April 1, 2009 -
October 31, 2009
Swap 3.8 - - - $ 7.86
Put Spread(1) 2.8 - $ 9.23 $ 7.65 -
Put Spread(1) 2.8 - $ 9.50 $ 7.91 -
Put Spread(1) 5.6 - $ 9.60 $ 7.91 -
2008 - 2010
Physical (escalated
pricing) 2.0 - - - $ 2.59
-------------------------------------------------------------------------
(1) Financial contracts entered into during the second quarter of 2008.
(2) Financial contracts entered into subsequent to June 30, 2008.
(3) Acquired through the acquisition of Focus.
The following sensitivities show the impact to after-tax net income for
the three months ended June 30, 2008 of the respective changes in forward
crude oil and natural gas prices as at June 30, 2008 on the Fund's
commodity derivative contracts, with all other variables held constant:
Increase/(decrease) to
after-tax net income
---------------------------
20% decrease 20% increase
in forward in forward
($ thousands) prices prices
-------------------------------------------------------------------------
Crude oil derivative contracts $ 70,934 $ (67,469)
Natural gas derivative contracts $ 39,235 $ (42,823)
Electricity:
The Fund is subject to electricity price fluctuations and it manages this
risk by entering into forward fixed rate electricity derivative contracts
on a portion of its electricity requirements. The Fund's outstanding
electricity derivative contracts as at July 25, 2008 are summarized
below:
Volumes Price
Term MWh CDN$/MWh
-------------------------------------------------------------------------
July 1, 2008 - September 30, 2008 4.0 $ 63.00
July 1, 2008 - December 31, 2009 4.0 $ 74.50
-------------------------------------------------------------------------
The Fund did not enter into any new electricity contracts in the second
quarter of 2008.
Currency Risk
-------------
The Fund is exposed to currency risk in relation to its U.S. dollar cash
balances and U.S. dollar denominated senior unsecured notes. The Fund
generally maintains a minimal amount of U.S. dollar cash and manages the
currency risk relating to the senior unsecured notes through the currency
derivative instruments that are detailed below.
Cross Currency Interest Rate Swap ("CCIRS")
Concurrent with the issuance of the US$175,000,000 senior notes on June
19, 2002, the Fund entered into a CCIRS with a syndicate of financial
institutions. Under the terms of the swap, the amount of the notes was
fixed for purposes of interest and principal payments at a notional
amount of CDN$268,328,000. Interest payments are made on a floating rate
basis, set at the rate for three-month Canadian bankers' acceptances,
plus 1.18%.
Foreign Exchange Swaps
In September 2007 the Fund entered into foreign exchange swaps on
US$54,000,000 of notional debt at an average CAD/US foreign exchange rate
of 1.02. These foreign exchange swaps mature between October 2011 and
October 2015 in conjunction with the principal repayments on the
US$54,000,000 senior notes.
The following sensitivities show the impact to after-tax net income for
the three months ended June 30, 2008 of the respective changes in the
period end and applicable forward foreign exchange rates as at June 30,
2008, with all other variables held constant:
Increase/(decrease)
to after-tax net income
--------------------------
10% decrease 10% increase
in $CDN in $CDN
relative relative
($ thousands) to $US to $US
-------------------------------------------------------------------------
Translation of senior unsecured notes $ (7,029) $ 7,029
Increase/(decrease)
to after-tax net income
--------------------------
10% decrease 10% increase
in $CDN in $CDN
relative relative
($ thousands) to $US to $US
-------------------------------------------------------------------------
Foreign exchange swaps $ 7 $ (7)
Cross currency interest rate swap(1) $ 6,732 $ (6,732)
(1) Represents change due to foreign exchange rates only
Interest Rate Risk
------------------
The Fund's cash flows are impacted by fluctuations in interest rates as
its outstanding bank debt carries floating interest rates and payments
made under the CCIRS are based on floating interest rates. To manage a
portion of interest rate risk relating to the bank debt, the Fund has
entered into interest rate swaps on $100,000,000 of notional debt at
rates varying from 3.70% to 4.61% before banking fees that are expected
to range between 0.55% and 1.10%. These interest rate swaps mature
between June 2011 and April 2013.
If interest rates change by 1%, either lower or higher, on our variable
rate debt outstanding at June 30, 2008 with all other variables held
constant, the Fund's after-tax net income for a quarter would change by
$1,063,000.
The following sensitivities show the impact to after-tax net income for
the three months ended June 30, 2008 of the respective changes in the
applicable forward interest rates as at June 30, 2008, with all other
variables held constant:
Increase/(decrease)
to after-tax net income
-------------------------------
20% decrease 20% increase
in forward in forward
interest interest
($ thousands) rates rates
-------------------------------------------------------------------------
Interest rate swaps $ (239) $ 239
Cross currency interest rate swap(1) $ 1,687 $ (1,687)
(1) Represents change due to interest rates only
ii. Credit Risk
Credit risk represents the financial loss the Fund would experience due
to the potential non-performance of counterparties to our financial
instruments. The fund is exposed to credit risk mainly through its joint
venture, marketing and financial counterparty receivables.
The Fund mitigates credit risk through credit management techniques,
including conducting financial assessments to establish and monitor a
counterparty's credit worthiness, setting exposure limits, monitoring
exposures against these limits and obtaining financial assurances such as
letters of credit, parental guarantees, or third party credit insurance
where warranted. The Fund monitors and manages its concentration of
counterparty credit risk on an ongoing basis.
The Fund's maximum credit exposure at the balance sheet date consists of
the carrying amount of its non-derivative financial assets as well as the
fair value of its derivative financial assets. At June 30, 2008
approximately 80% of our marketing receivables were with companies
considered investment grade or just below investment grade. This level of
credit concentration is typical of oil and gas companies of our size
producing in similar regions.
At June 30, 2008 approximately $7,700,000 or 3% of our total accounts
receivable are aged over 120 days and considered past due. The majority
of these accounts are due from various joint venture partners. The Fund
actively monitors past due accounts and takes the necessary actions to
expedite collection, which can include withholding production or net
paying when the accounts are with joint venture partners. Should the Fund
determine that the ultimate collection of a receivable is in doubt, it
will provide the necessary provision in its allowance for doubtful
accounts with a corresponding charge to earnings. If the Fund
subsequently determines an account is uncollectible the account is
written off with a corresponding charge to the allowance account. The
Fund's allowance for doubtful accounts balance at June 30, 2008 is
$3,800,000, which includes a $1,000,000 provision made during the quarter
relating to receivables from a Canadian subsidiary of SemGroup LP. There
were no accounts written off during the quarter.
iii. Liquidity Risk & Capital Management
Liquidity risk represents the risk that the Fund will be unable to meet
its financial obligations as they become due. The Fund mitigates
liquidity risk through actively managing its capital, which it defines as
long-term debt (net of cash) and unitholders' capital. Enerplus'
objective is to provide adequate short and longer term liquidity while
maintaining a flexible capital structure to sustain the future
development of the business. The Fund strives to balance the portion of
debt and equity in its capital structure given its current oil and gas
assets and planned investment opportunities.
Management monitors a number of key variables with respect to its capital
structure, including debt levels, capital spending plans, distributions
to unitholders, access to capital markets, as well as acquisition and
divestment activity.
Debt Levels
-----------
The Fund commonly measures its debt levels relative to its "debt-to-cash
flow ratio" which is defined as long-term debt (net of cash) divided by
the trailing twelve month cash flow from operating activities. The debt-
to-cash flow ratio represents the time period, expressed in years, it
would take to pay off the debt if no further capital investments were
made or distributions paid and if cash flow from operating activities
remained constant.
At June 30, 2008 the debt to cash flow ratio was 0.9x including the 12
months of trailing cash flow from Focus (June 30, 2007 - 0.7x). Enerplus'
bank credit facilities and senior debenture covenants carry a maximum
debt-to-cash flow ratio of 3.0x including cash flow from acquisitions on
a proforma basis. Traditionally Enerplus has managed its debt levels such
that the debt-to-cash flow ratio has been below 1.5x, which has provided
flexibility in pursuing acquisitions and capital projects. After applying
the proceeds from the sale of our Joslyn interest our debt to trailing
cash flow ratio will be 0.4x. Enerplus' five-year history of debt to cash
flow is illustrated below:
Q2/ Q1/
2008 2008 2007 2006 2005 2004 2003
------------------------------------------------
Debt-to-Cash Flow Ratio 0.9x 1.0x 0.8x 0.8x 0.8x 1.1x 0.6x
At June 30, 2008 Enerplus had additional borrowing capacity of
$607,795,000 under its $1.4 billion bank credit facility. The Fund also
has the ability to increase the bank credit facility and borrowing
capacity beyond this level, however increasing the credit facility at
this time would result in increased fees. Enerplus does not have any
subordinated or convertible debt outstanding at this time.
Capital Spending Plans
----------------------
In 2008 Enerplus expects to spend approximately $580 million developing
existing assets. A portion of this capital spending is considered
discretionary. There are limitations to changing the capital spending
plans during a year. Long project lead times, economies of scale,
logistical considerations, and partner commitments reduce the ability to
adjust or down-size the capital program. Alternatively, the ability to
rapidly increase spending may be limited by staff capacity, availability
of services and equipment, access to sites, and regulatory approvals.
Distributions to Unitholders
----------------------------
Enerplus distributes a significant portion of its cash flow to its
unitholders every month. These distributions are not guaranteed and the
board of directors can change the amount at any time. In the past, in
periods of sustained commodity price declines, distributions have been
reduced. Similarly, in periods of sustained higher commodity prices,
distributions have increased. To the extent that cash flow exceeds
distributions the additional funds are available to reduce debt, spend on
capital development or finance acquisitions. The less cash required to
finance these activities typically means more cash available for
distributions and vice versa.
Enerplus does not forecast distribution levels as it is difficult to
predict the direction of commodity prices. To the extent possible,
distributions are set at a level that can be maintained for a sustained
period. Historical performance has demonstrated that Enerplus investors
do not reward short-term sporadic increases, nor do they appreciate a
series of decreases. Enerplus has maintained the current distribution
level of $0.42/unit for 34 consecutive months. A stable or growing
distribution pattern typically helps support the market price of the
trust units. This unit price is important as equity is often issued in
association with large acquisitions and the higher the unit price the
less dilutive the equity issuance.
By paying distributions, we effectively earn a tax deduction against the
corporate taxes in our underlying subsidiaries and pass along Canadian
tax liability to our unitholders. If distributions are lowered and too
much cash flow is retained within the structure there is a risk that tax
obligations in the operating entities may be created thereby eroding the
flow-through advantage of the trust structure.
Access to Capital Markets
-------------------------
Enerplus relies on both the debt and equity markets to manage its cost of
capital and fund future opportunities. There are times when the cost and
access to these markets will vary. For example, the ability to issue new
equity at a reasonable cost is strongly influenced by the equity market's
perceptions of energy prices, macroeconomic factors, and Enerplus' future
prospects. Similarly, the ability to increase bank credit or issue
debentures is dependent on the overall state of the credit markets, as
well as creditors' perceptions of the energy sector and Enerplus' credit
quality. In times of uncertainty cash flow is preserved as a defense
against capital market downturns rather than invested in capital programs
or increasing distributions.
Enerplus currently has an NAIC2 rating on the senior unsecured debentures
in the U.S. private debt markets. In addition, the equity capital markets
have indicated their continued support. Nonetheless, the capital markets
can change rapidly with very little notice.
Acquisition & Divestment Activity
---------------------------------
In periods of market uncertainty and volatility, it is important to have
a conservative balance sheet and access to capital markets to take
advantage of acquisition opportunities as they arise. The Fund attempts
to manage its capital in a manner that reflects the likelihood and
magnitude of potential acquisitions and/or opportunities to dispose of
non-core assets.
Enerplus was successful in disposing of its Joslyn interest subsequent to
the quarter, the proceeds of which will be used to repay debt,
reinforcing Enerplus' borrowing capacity and enhancing the ability to
fund future capital spending and acquisition activity.
Liability Maturity Analysis
---------------------------
The following tables detail the principal maturity analysis for the
Fund's non-derivative financial liabilities at June 30, 2008:
Payments Due by Period
--------------------------------------
($ thousands) Total 2008 2009 2010
-------------------------------------------------------------------------
Accounts Payable $ 289,576(1) $ 289,576 $ - $ -
Distributions payable
to unitholders 69,180(2) 69,180 - -
Bank credit facility 792,205 - - 792,205
Senior unsecured notes 323,408(3) - - 53,666
-------------------------------------------------------------------------
Total commitments $ 1,474,369 $ 358,756 $ - $ 845,871
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Payments Due by Period Total
------------------------- Committed
($ thousands) 2011 2012 after 2013
------------------------------------------------------------
Accounts Payable $ - $ - $ -
Distributions payable
to unitholders - - -
Bank credit facility - - -
Senior unsecured notes 64,682 64,682 140,378
------------------------------------------------------------
Total commitments $ 64,682 $ 64,682 $ 140,378
------------------------------------------------------------
------------------------------------------------------------
(1) Accounts payable are generally settled between 30 and 90 days from
the balance sheet date.
(2) Distributions payable to unitholders are paid on the 20th day of the
month following the balance sheet date.
(3) Includes the economic impact of derivative instruments directly
related to the senior unsecured notes (CCIRS and foreign exchange
swap).
It is Enerplus' intention to renew the bank credit facilities before or
as they come due. Historically, the bank credit facilities have been
renewed annually, refreshing the associated three year term period.
Similarly, it is expected that the senior unsecured notes will be
replaced with replacement notes or bank debt as they become due. Over the
long-term, Enerplus expects to balance short-term credit requirements
with bank credit and to look to the term debt markets for longer-term
credit support.
10. SUBSEQUENT EVENT
On July 31, 2008, subsequent to the quarter, Enerplus disposed of its
Joslyn interest for net proceeds of approximately $500 million.
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund, including our
Annual Information Form, is available under our profile on the SEDAR website
at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.
Gordon J. Kerr President & Chief Executive Officer Enerplus Resources
Fund
INFORMATION REGARDING CONTINGENT RESOURCE DISCLOSURE IN THIS NEWS RELEASE
This news release contains estimates of "contingent resources". "Contingent
resources" are not, and should not be confused with, oil and gas reserves.
"Contingent resources" are defined in the Canadian Oil and Gas Evaluation
Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as
of given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as economic, legal,
environmental, political and regulatory matters or a lack of markets. It is
also appropriate to classify as contingent resources the estimated discovered
recoverable quantities associated with a project in the early evaluation
stage." There is no certainty that Enerplus will produce any portion of the
volumes currently classified as "contingent resources". The primary
contingencies which currently prevent the classification of Enerplus'
disclosed contingent resources associated with the Kirby oil sands project as
reserves consist of current uncertainties around the specific scope and timing
of the project development, proposed reliance on technologies that have not
yet been demonstrated to be commercially applicable in oil sands applications,
the uncertainty regarding marketing plans for production from the subject
areas and improved estimation of project costs. Based on current information
and market conditions, Enerplus believes that development of the Kirby project
will proceed as described in this news release. However, there are a number of
inherent risks and contingencies associated with the development of the Kirby
project, including commodity price fluctuations, project costs, receipt of
regulatory approvals and those other risks and contingencies described above
and under "Risk Factors and Risk Management" in the Management's Discussion an
Analysis section of this news release and under "Risk Factors" in the Fund's
Annual Information Form (and corresponding Form 40-F) dated March 12, 2007, as
well as the risk factors to be contained in the Fund's Annual Information Form
(and corresponding Form 40-F) filed in March 2008.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and
statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans", "intends",
"strategy" and similar expressions are intended to identify forward-looking
information or statements. In particular, but without limiting the foregoing,
this news release contains forward-looking information and statements
pertaining to the following: the volumes and estimated value of the Fund's oil
and gas reserves; the life of the Fund's reserves; the volume and product mix
of the Fund's oil and gas production; future oil and natural gas prices and
the Fund's commodity risk management programs; the amount of future asset
retirement obligations; future liquidity and financial capacity; future
results from operations and operating metrics; future costs, expenses and
royalty rates; future interest costs; future development, exploration,
acquisition and development activities (including drilling plans) and related
capital expenditures, including with respect to both our conventional and oil
sands activities and in particular the development of the Kirby and Joslyn
leases; future acquisitions and dispositions; the reinstatement of production
from the Giltedge property and the availability of business interruption
insurance to mitigate the costs of the Giltedge fire; the making and timing of
future regulatory filings and applications; the value of the Fund's equity
investments; future tax treatment of income trusts and future taxes payable by
the Fund; the Fund's tax pools; the impact of the Focus acquisition on the
Fund; the amount, timing and tax treatment of cash distributions to
unitholders; and future payout ratios.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
the Fund including, without limitation: that the Fund will continue to conduct
its operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing (and
in certain circumstances, the implementation of proposed) tax, royalty and
regulatory regimes; the accuracy of the estimates of the Fund's reserve and
resource volumes; certain commodity price and other cost assumptions; the
continued availability of adequate debt and equity financing and cash flow to
fund its plans expenditures; and accurate assessment of the value of Focus'
assets and the extent of its liabilities. The Fund believes the material
factors, expectations and assumptions reflected in the forward-looking
information and statements are reasonable but no assurance can be given that
these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
changes in the demand for or supply of the Fund's products; unanticipated
operating results or production declines; changes in tax or environmental
laws, royalty rates or other regulatory matters; changes in development plans
the Fund or by third party operators of the Fund's properties, including the
operator of the Joslyn oil sands project; increased debt levels or debt
service requirements; inaccurate estimation of the Fund's and Focus' oil and
gas reserve and resource volumes; limited, unfavourable or a lack of access to
capital markets; increased costs; a lack of adequate insurance coverage;
declines in the value of the Fund's equity investments; the impact of
competitors; and certain other risks detailed from time to time in the Fund's
public disclosure documents (including, without limitation, those risks
identified in this news release and in the Fund's Annual Information Form).
The forward-looking information and statements contained in this news
release speak only as of the date of this news release, and none of the Fund
or its subsidiaries assumes any obligation to publicly update or revise them
to reflect new events or circumstances, except as may be required pursuant to
applicable laws.
Emergency Number
