TSX: ERF.un
NYSE: ERF
CALGARY, Nov. 7 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our results from operations for the period ending September 30,
2008. Highlights are as follows:
- Cash flow from operating activities was $383.6 million ($2.33 per
unit) on the sale of our crude oil and natural gas production,
slightly higher than the cash flows earned during the second quarter
of 2008.
- Actual cash distributions paid to unitholders were $1.31 per unit, up
4% from the second quarter. Our payout ratio was approximately 59%
during the period. When we include our development capital
expenditures, our adjusted payout ratio was 102% for the quarter.
- We closed the sale of our Joslyn oil sands lease for net proceeds of
$502 million, which greatly enhanced our financial flexibility and
put us in an enviable position with regard to the strength of our
balance sheet. Our debt to trailing 12 month cash flow ratio is
currently 0.4x, one of the lowest in our sector.
- We have achieved another milestone regarding our operated Kirby oil
sands project by filing the regulatory application slightly earlier
than planned for Phase 1 development of 10,000 bbls/day of bitumen
production.
- Daily production during the third quarter averaged 95,644 BOE/day.
The majority of the production shortfall was related to our
development program at Shackleton where higher than normal rainfall
in both the second and third quarters hampered our ability to execute
our shallow gas program. As well, we undertook a review of our
completion techniques at Shackleton in order to optimize production
from additional zones delaying the tie-in of a number of wells in the
area.
- We invested $163.2 million on our development capital expenditure
program in the third quarter drilling 272 net wells. We also invested
approximately $43 million on pre-investment spending, which included
the purchase of land in the Montney region of Alberta and British
Columbia and the Bakken region of southeast Saskatchewan as well as
our oil sands activities.
Revised 2008 Guidance
- The downturn in commodity prices throughout the quarter combined with
the current uncertainty in the capital markets has reinforced our
belief in the importance of maintaining strong financial flexibility.
As a result, we have reduced our monthly cash distribution level from
$0.47/unit to $0.38/unit effective with the November 2008
distribution payment. We are also reducing our overall capital
spending plans for 2008 by $35 million (6%) to $545 million for the
year which includes an additional $20 million of land acquisitions
over our original plans which do not provide near-term production or
cash flow, but which we expect will help build development
opportunities for the future.
- As a result of our adjustment in capital spending and lower than
expected third quarter production, we are lowering our 2008 average
annual production guidance slightly to 96,000 BOE/day and adjusting
our anticipated exit rate from 100,000 BOE/day to 98,500 BOE/day.
- Our cash operating costs were $10.10/BOE, up from $9.61/BOE during
the third quarter of 2007. We are increasing our estimate of full
year 2008 operating costs by $0.50/BOE to $9.50/BOE due to the
reduced production forecast as well as by continued cost increases
related to our optimization activities in the U.S.
- General and administrative cash expenses were $1.50/BOE, down from
$2.11/BOE during the third quarter of 2007. We are decreasing our
estimate for 2008 general and administrative expenses by $0.20/BOE to
approximately $2.00/BOE primarily due to lower expenses associated
with long-term compensation plans.
- Looking ahead to 2009, given the lower commodity price environment we
currently face as well as the uncertainty in the financial and credit
markets, we are expecting our 2009 capital spending to be moderately
lower than our 2008 spending. We expect to provide detailed
operational and production guidance for 2009 in mid-December.
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 ended Nine months ended
September 30, September 30,
(in Canadian dollars) 2008 2007 2008 2007
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Financial (000's)
Cash Flow from
Operating Activities $ 383,573 $ 232,801 $1,004,246 $ 663,464
Cash Distributions to
Unitholders(1) 224,417 163,110 619,121 483,388
Cash Withheld for
Acquisitions and
Capital Expenditures 159,156 69,691 385,125 180,076
Net Income 465,773 93,033 699,397 240,990
Debt Outstanding
(net of cash) 522,254 649,829 522,254 649,829
Development Capital
Spending 163,215 90,647 377,485 281,045
Acquisitions 4,574 1,755 1,771,383 269,149
Divestments 502,489 96 504,697 5,569
Actual Cash Distributions
to Unitholders per
Trust Unit $ 1.31 $ 1.26 $ 3.83 $ 3.78
Financial per Weighted
Average Trust Units(2)
Cash Flow from
Operating Activities $ 2.33 $ 1.80 $ 6.32 $ 5.22
Cash Withheld for
Acquisitions and
Capital Expenditures 0.97 0.54 2.42 1.42
Net Income 2.82 0.72 4.40 1.90
Payout Ratio(3) 59% 70% 62% 73%
Selected Financial
Results per BOE(4)
Oil & Gas Sales(5) $ 73.62 $ 49.64 $ 72.44 $ 49.89
Royalties (13.71) (9.28) (13.54) (9.38)
Commodity Derivative
Instruments (6.82) 1.00 (5.19) 0.63
Operating Costs (10.10) (9.61) (9.51) (9.32)
General and
Administrative (1.50) (2.11) (1.66) (2.00)
Interest and Other
Income and Foreign
Exchange (1.46) (1.34) (1.23) (1.34)
Taxes (0.59) (0.70) (1.19) (0.46)
Restoration and
Abandonment (0.54) (0.48) (0.52) (0.47)
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Cash Flow from Operating
Activities before
changes in non-cash
working capital $ 38.90 $ 27.12 $ 39.60 $ 27.55
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Weighted Average Number
of Trust Units
Outstanding Including
Equivalent Exchangeable
Limited Partnership
Units (thousands) 164,908 129,373 158,980 127,025
Debt/Trailing 12 Month
Cash Flow Ratio(6) 0.4x 0.7x 0.4x 0.7x
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SELECTED OPERATING RESULTS
Three months ended Nine months ended
September 30, September 30,
2008 2007 2008 2007
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Average Daily Production
Natural gas (Mcf/day) 341,803 251,264 336,328 263,884
Crude oil (bbls/day) 34,119 34,077 34,295 34,602
NGLs (bbls/day) 4,557 3,937 4,660 4,194
Total (BOE/day) 95,644 79,891 95,010 82,777
% Natural gas 60% 52% 59% 53%
Average Selling Price(5)
Natural gas (per Mcf) $ 8.25 $ 5.59 $ 8.60 $ 6.63
Crude oil (per bbl) 110.63 69.16 103.85 62.75
NGLs (per bbl) 81.20 50.79 77.21 49.26
US$ exchange rate 0.96 0.96 0.98 0.91
Net Wells drilled 272 101 469 177
Success Rate 99% 99% 99% 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. See "Non-GAAP Measures" in the following
Management's Discussion and Analysis.
(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 ended TSX - ERF.un NYSE - ERF
September 30, 2008 (CDN$) (US$)
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High $ 48.15 $ 47.47
Low $ 35.57 $ 33.64
Close $ 38.86 $ 37.19
2008 Cash Distributions
Per Trust Unit
Payment Month CDN$ US$
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First Quarter Total $ 1.26 $ 1.23
Second Quarter Total $ 1.26 $ 1.25
July $ 0.42 $ 0.42
August 0.42 0.39
September 0.47 0.45
Third Quarter Total $ 1.31 $ 1.26
Total Year-to-Date $ 3.83 $ 3.74
2008 Production and Development Activity
Three months ended September 30,
-------------------------------------------------
Wells Drilled(*)
-------------------
Production Capital
Volumes Spending
Play Type (BOE/day) ($ millions) Gross Net
-------------------------------------------------------------------------
Shallow Gas & CBM 23,479 $ 55.0 254 235
Crude Oil Waterfloods 16,904 19.7 20 18
Deep Tight Gas 15,730 11.0 22 3
Bakken/Tight Oil 10,118 45.0 3 2
Other Conventional
Oil & Gas 29,413 26.7 78 14
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Total Conventional 95,644 157.4 377 272
Oil Sands
Kirby - 5.0 - -
Other Oil Sands - 0.8 - -
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Total Oil Sands - 5.8 - -
Total 95,644 $ 163.2 377 272
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Nine months ended September 30,
-------------------------------------------------
Wells Drilled(*)
-------------------
Production Capital
Volumes Spending
Play Type (BOE/day) ($ millions) Gross Net
-------------------------------------------------------------------------
Shallow Gas & CBM 23,183 $ 101.3 471 394
Crude Oil Waterfloods 16,061 47.6 42 28
Deep Tight Gas 14,431 42.8 52 8
Bakken/Tight Oil 10,778 78.0 11 8
Other Conventional
Oil & Gas 30,557 67.6 157 31
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Total Conventional 95,010 337.3 733 469
Oil Sands
Kirby - 29.5 - -
Other Oil Sands - 10.7 - -
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Total Oil Sands - 40.2 - -
Total 95,010 $ 377.5 733 469
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(*) Drilling totals do not include delineation wells at Kirby or service
wells
Drilling success rate year-to-date: 99%
Development capital spending was $163.2 million in the third quarter and
$377.5 million for the year. Our activities have included both oil and natural
gas projects however a greater concentration of spending was directed at
natural gas opportunities during the quarter. A total of 272 net wells were
drilled in the third quarter, the majority of which were at Shackleton, our
largest and most profitable shallow natural gas property which is located in
southwest Saskatchewan.
Our crude oil activities were concentrated on our waterflood properties
and our Bakken oil property in the U.S. In Alberta, a key waterflood
development project was undertaken at our Giltedge property where we drilled
13 wells and have identified further development potential associated with the
significant amount of oil remaining in this pool. In the U.S. we also
continued our refrac program and our third well per section drilling program
on our Sleeping Giant field. We continue to be encouraged by the performance
from this field and plan to continue our drilling program into 2009. As a
result of this activity, we expect our capital spending to increase from
approximately $60 million to between $70 million and $80 million in this area
in 2008. The aggressive pace of Bakken development in Montana and North Dakota
continues to be a concern as pipeline capacity has not kept pace with
production growth. Through management of our inventory volumes, we have not
faced any significant production curtailments to date, however we have seen an
increase in transportation differentials which have impacted our netbacks. We
continue to monitor the situation closely.
Overall, our investment activities are aimed at helping to replace our
annual production volumes and establishing future development opportunities
for the years to come. During the quarter, we invested approximately $43
million primarily on the purchase of land in the Montney region of Alberta and
British Columbia and the Bakken region of southeast Saskatchewan and oil sands
project work. Year-to-date, our pre-investment spending has totaled
approximately $87 million, approximately one half of which has been invested
in our Kirby oil sands lease and the majority of the remainder being invested
in undeveloped land.
Oil Sands Activities
Enerplus achieved another milestone during the quarter on our operated
Kirby steam assisted gravity drainage ("SAGD") Oil Sands project by filing our
regulatory application for the first phase of development ("Phase 1") with the
Energy Resources Conservation Board and Alberta Environment on September 26,
2008, slightly earlier than expected. We plan to continue to advance the Kirby
project to be in a position to present this project for a sanctioning decision
by our Board of Directors once we receive regulatory approval and have
completed additional engineering design planning. We expect to be in this
position by the fourth quarter of 2009. We are also continuing to delineate
the lease to set up expansion of this project over time.
Phase 1 of the Kirby lease consists of a 10,000 bbl/day SAGD development
that we expect to produce bitumen for approximately 25 years. We tentatively
plan to begin construction in 2009 following regulatory approval. First steam
is anticipated in late 2011, first production is expected in 2012 and full
commercial production volumes of 10,000 bbls/day are expected in 2013. Our
current estimate of the capital costs associated with construction of Phase 1
is approximately $400 million (2008 dollars).
Our 2007/08 winter drilling program was focused on delineating the
northern block of the lease which is where Phase I will be located. Based on
the results of this delineation work, our third party reserve engineers have
confirmed a best estimate contingent resource of approximately 414 million
barrels, a 70% increase from the original resource estimate completed when we
purchased the lease in the spring of 2007. The following table summarizes the
contingent resource estimate for the Kirby Lease:
Northern Area Wabiskaw D (Project area) 118 million barrels
Northern Area McMurray 191 million barrels
Central and Southern Areas 105 million barrels
-------------------
Total Kirby Lease Contingent Resource Estimate 414 million barrels
-------------------
-------------------
For additional information relating to contingent resource estimates, see
"Information Regarding Contingent Resource Estimates" in the following
Management's Discussion and Analysis. As well, for additional information
regarding our Kirby Oil Sands project, see pages 16 and 17 of our Annual
Information Form for the year ended December 31, 2007, a copy of which is
available on our SEDAR profile at www.sedar.com and which also forms part of
our Form 40-F for the year ended December 31, 2007 filed with the SEC, a copy
of which is available at www.sec.gov.
Looking Ahead
We are experiencing unprecedented volatility in the commodity, credit and
equity markets on a global scale not seen in decades. We are fortunate to be
in a position of strength not only due to the opportunities we have within our
asset base, but also the financial flexibility we have with over $1.1 billion
of available credit capacity. We will continue to invest in our assets and
will evaluate opportunities for acquisitions in this attractive market, but we
will do so judiciously. We believe that in tumultuous times like these, it is
in our best interest to maintain our financial flexibility by controlling
costs and managing our cash flows. I believe we will not only weather these
uncertain times as we have previously in our 22 year history but that we will
attract new highly skilled people and capture opportunities which will allow
us to further build and strengthen our company.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated
November 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 nine months ended September 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
Cash flow from operating activities for the third quarter increased to
$383.6 million from $364.5 million in the second quarter, largely due to
decreases in our non-cash operating working capital. Our payout ratio was 59%
for the quarter and 62% year to date. Commodity prices remained strong for
most of the quarter however the sharp decline in prices towards the end of the
quarter resulted in $280.7 million of non-cash gains on our commodity
derivative instruments. We received net proceeds of $502.0 million for the
Joslyn disposition on July 31, 2008 which was used to pay down debt. At
September 30, 2008 our balance sheet remains strong with a trailing 12 month
debt to cash flow ratio of 0.4x, leaving us with available capacity of over
$1.1 billion on our $1.4 billion credit facility.
Our year-to-date development capital spending totaled $377.5 million and
is behind schedule mainly due to weather and project delays at both operated
and non-operated properties. Based on our year-to-date spending and project
deferrals and cancellations in the fourth quarter we are revising our annual
development capital guidance to $545 million from $580 million, based on a $55
million reduction in our conventional program which is partially offset by $20
million of additional land acquisitions.
Production for the quarter was 95,644 BOE/day, slightly lower than
expected due to a combination of development delays and unplanned facility
downtime. Given our year-to-date results and revised capital program we are
decreasing our annual average production guidance from 98,000 BOE/day to
96,000 BOE/day and our 2008 exit rate guidance from 100,000 BOE/day to 98,500
BOE/day. In conjunction with the revised production estimates we are
increasing our operating cost guidance from $9.00/BOE to $9.50/BOE however our
general and administrative expense guidance is being revised downwards to
$2.00/BOE from $2.20/BOE primarily due to decreased expenses associated with
our long-term compensation plans.
The significant decrease in commodity prices combined with the current
uncertainty in the capital markets has reinforced our belief in the importance
of maintaining strong financial flexibility therefore we have lowered our
monthly cash distribution to $0.38 per unit from $0.47 per unit effective
November 20, 2008.
RESULTS OF OPERATIONS
Production
Production in the third quarter of 2008 averaged 95,644 BOE/day, a
decrease of 5% from 100,188 BOE/day in the second quarter of 2008. The
decrease for the quarter was primarily due to capital project delays and
unplanned downtime at our non-operated plants including Brooks South, K3,
McMahon and Elmworth. We also experienced tie-in delays at our operated
Shackleton property during the quarter as we were assessing alternative well
completion techniques. As a result of these capital delays and unplanned
downtime, we are reducing our annual average production guidance from 98,000
BOE/day to 96,000 BOE/day and our 2008 exit rate from 100,000 BOE/day to
98,500 BOE/day.
For the three and nine months ended September 30, 2008 production
increased 20% and 15% respectively, compared to the same periods in 2007.
These increases were primarily due to the additional production from the Focus
Energy Trust ("Focus") assets acquired on February 13, 2008.
Average production volumes for the three and nine months ended September
30, 2008 and 2007 are outlined below:
Three months ended Nine months ended
September 30, September 30,
% %
Daily Production Volumes 2008 2007 Change 2008 2007 Change
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Natural gas (Mcf/day) 341,803 251,264 36% 336,328 263,884 27%
Crude oil (bbls/day) 34,119 34,077 -% 34,295 34,602 (1)%
Natural gas liquids
(bbls/day) 4,557 3,937 16% 4,660 4,194 11%
Total daily sales
(BOE/day) 95,644 79,891 20% 95,010 82,777 15%
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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, net of transportation
costs, for the three and nine months ended September 30, 2008 and 2007. It
also compares the benchmark price indices for the same periods:
Three months ended Nine months ended
September 30, September 30,
% %
Average Selling Price(1) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Natural gas (per Mcf) $ 8.25 $ 5.59 48% $ 8.60 $ 6.63 30%
Crude oil (per bbl) $110.63 $ 69.16 60% $103.85 $ 62.75 65%
Natural gas liquids
(per bbl) $ 81.20 $ 50.79 60% $ 77.21 $ 49.26 57%
Per BOE $ 73.62 $ 49.64 48% $ 72.44 $ 49.89 45%
Average Benchmark Pricing
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AECO natural gas -
monthly index
(CDN$/Mcf) $ 9.25 $ 5.61 65% $ 8.58 $ 6.81 26%
AECO natural gas -
daily index
(CDN$/Mcf) $ 7.75 $ 5.18 50% $ 8.62 $ 6.55 32%
NYMEX natural gas -
monthly NX3 index
(US$/Mcf) $ 10.09 $ 6.13 65% $ 9.65 $ 6.88 40%
NYMEX natural gas -
monthly NX3 index
CDN$ equivalent
(CDN$/Mcf) $ 10.51 $ 6.39 64% $ 9.85 $ 7.56 30%
WTI crude oil
(US$/bbl) $117.98 $ 75.38 57% $113.29 $ 66.23 71%
WTI crude oil CDN$
equivalent
(CDN$/bbl) $122.90 $ 78.52 57% $115.60 $ 72.78 59%
CDN$/US$ exchange rate 0.96 0.96 -% 0.98 0.91 8%
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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 fell approximately 51% from
a high of $11.83/Mcf on July 1 to a low of $5.79/Mcf at the end of September.
This sharp decrease was triggered by significant increases in U.S. natural gas
production and reduced demand caused by moderate cooling loads and a weakening
economy.
We realized an average price on our natural gas of $8.25/Mcf during the
three months ended September 30, 2008, an increase of 48% from $5.59/Mcf for
the same period in 2007. For the nine months ended September 30, 2008 we
realized a 30% increase in our average price of $8.60/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 30% increase for the nine
month period is comparable to the increases experienced by the AECO indices
over the same period. However, the increases in our current quarter realized
gas prices over the same period in 2007 were lower than the increases in the
AECO indices over the same periods due to lower prices received for our U.S.
natural gas production resulting from excess supply in the region and the fact
that a small portion of our Canadian natural gas sold at a discount to the
August month index with the sharp decline in prices during the month of July.
Crude oil prices fell 37%, from US$145.29/bbl to US$91.15/bbl, during the
third quarter in response to demand destruction as the threat of a global
economic slowdown grew. The average price we received for our crude oil during
the three months ended September 30, 2008 increased 60% to $110.63/bbl
compared to $69.16/bbl during the same period in 2007. Similarly, the West
Texas Intermediate ("WTI") crude oil benchmark price, in Canadian dollars,
increased 57% from the corresponding period in 2007. For the nine months ended
September 30, 2008 our crude oil price increased 65% to $103.85/bbl, while the
WTI benchmark, in Canadian dollars, increased 59%. The narrowing of the market
differential for our heavy oil production was the main contributor to the
higher year-over-year price increase received on our crude oil relative to the
increase in WTI.
For the third quarter of 2008 the Canadian dollar remained unchanged
against the U.S. dollar relative to the same period in 2007. The Canadian
dollar strengthened against the U.S. dollar during the nine months ended
September 30, 2008 compared to the same period in 2007. As most of our crude
oil and natural gas sales are priced in reference to U.S. dollar denominated
benchmarks, this movement in the exchange rate reduced the Canadian dollar
prices that we would have otherwise realized.
Since the end of the third quarter there has been a dramatic reduction in
crude oil prices and to a lesser extent natural gas prices in response to the
global credit crisis and concerns over the health of economies around the
world. The impact of these lower prices has been partially offset by a weaker
Canadian dollar which helps energy producers such as Enerplus. As at October
28, 2008 crude oil prices (WTI) and natural gas prices (AECO) had fallen to
U.S. $62.73/bbl and $7.16/Mcf respectively from September 30, 2008 partially
offset by a 22% change in the CDN$/US$ exchange rate to 0.77.
Price Risk Management
We continue to evolve our price risk management framework in response to
the increased volatility of the commodity price environment. Consideration is
given to our overall financial position together with the economics of our
development capital program and potential acquisitions. Consideration is also
given to the upfront and potential 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.
Considering all financial contracts transacted as of October 28, 2008, we
have protected a portion of our natural gas price risk through to October 31,
2009 and a portion of our crude oil price risk through to December 31, 2009.
We have also taken steps to protect our exposure to rising electricity costs
for a portion of our consumption in the Alberta power market through to
December 31, 2010. 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 October
28, 2008, expressed as a percentage of our forecasted net production volumes:
Natural Gas (CDN$/Mcf) Crude Oil (US$/bbl)
-------------------------------------------------------
October 1, November 1, April 1, October 1, January 1,
2008 - 2008 - 2009 - 2008 - 2009 -
October March October December December
31, 2008 31, 2009 31, 2009 31, 2008 31, 2009
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Floor Price (puts) $7.09 $9.20 $9.01 $72.09 $98.08
% (net of royalties) 26% 23% 8% 35% 26%
Fixed Price (swaps) $7.44 $9.35 $7.86 $79.97 $100.05
% (net of royalties) 21% 3% 2% 19% 2%
Capped Price (calls) $8.25 $11.60 - $85.48 $92.98
% (net of royalties) 26% 11% - 22% 11%
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Based on weighted average price (before premiums), estimated average
annual production of 96,000 BOE/day and assuming a royalty rate of 19% in
2008 and 22% in 2009.
Accounting for Price Risk Management
During the third quarter of 2008 our price risk management program
incurred cash losses of $18.8 million on our natural gas contracts and $41.2
million on our crude oil contracts, compared to cash gains of $14.1 million
and cash losses of $6.7 million respectively during the third quarter of 2007.
For the nine months ended September 30, 2008 we experienced cash losses of
$30.6 million on our natural gas contracts and cash losses of $104.4 million
on our crude oil contracts, compared to a gain of $12.8 million and a gain of
$1.4 million respectively for the same period in 2007. The increase in cash
losses for the three and nine months ended September 30, 2008 compared to the
corresponding periods in 2007 was the result of commodity prices rising above
our swap and sold call positions. As noted above, commodity prices have
continued to decrease since the end of the third quarter which we believe will
result in improved performance of our price risk management program in the
fourth quarter of 2008.
The fair value of our commodity derivative instruments was impacted by
the significant decrease in forward commodity prices at September 30, 2008
compared to June 30, 2008. At September 30, 2008 the fair value of our natural
gas derivative instruments represented a gain of $14.0 million and the fair
value of our crude oil derivative instruments represented a loss of $22.4
million. In comparison, at June 30, 2008 the fair value of our natural gas and
crude oil derivative instruments represented losses of $89.9 million and
$199.2 million respectively. The change in fair value of our commodity
derivative instruments during the third quarter of 2008 resulted in unrealized
gains of $280.7 million which was comprised of $103.9 million for natural gas
and $176.8 million for crude oil. For the nine months ended September 30, 2008
the change in fair value of our commodity derivative instruments resulted in
unrealized gains of $5.9 million for natural gas and $34.4 million for crude
oil. See Note 9 for details.
The following table summarizes the effects of our financial contracts on
income:
Risk Management Costs
Three months ended Three months ended
($ millions, except per September 30, September 30,
unit amounts) 2008 2007
-------------------------------------------------------------------------
Cash (losses)/gains:
Natural gas $ (18.8) $(0.60)/Mcf $ 14.1 $0.61/Mcf
Crude oil (41.2) (13.13)/bbl (6.7) (2.14)/bbl
---------- ----------
Total cash (losses)/
gains $ (60.0) $(6.82)/BOE $ 7.4 $1.00/BOE
Non-cash gains/(losses)
on financial contracts:
Change in fair value -
natural gas $ 103.9 $ 3.30/Mcf $ 2.8 $0.12/Mcf
Change in fair value -
crude oil 176.8 56.30/bbl (6.6) (2.12)/bbl
---------- ----------
Total non-cash
gains/(losses) $ 280.7 $31.90/BOE $ (3.8) $(0.51)/BOE
---------- ----------
Total gains $ 220.7 $25.08/BOE $ 3.6 $0.49/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Risk Management Costs Nine months ended Nine months ended
($ millions, except per September 30, September 30,
unit amounts) 2008 2007
-------------------------------------------------------------------------
Cash (losses)/gains:
Natural gas $ (30.6) $(0.33)/Mcf $ 12.8 $0.18/Mcf
Crude oil (104.4) (11.11)/bbl 1.4 0.15/bbl
---------- ----------
Total cash
(losses)/gains $ (135.0) $(5.19)/BOE $ 14.2 $0.63/BOE
Non-cash gains/(losses)
on financial contracts:
Change in fair value -
natural gas $ 5.9 $ 0.06/Mcf $ 7.6 $0.11/Mcf
Change in fair value -
crude oil 34.4 3.66/bbl (25.8) (2.74)/bbl
---------- ----------
Total non-cash
gains/(losses) $ 40.3 $ 1.55/BOE $ (18.2) $(0.81)/BOE
---------- ----------
Total (losses) $ (94.7) $(3.64)/BOE $ (4.0) $(0.18)/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Flow Sensitivity
The sensitivities below reflect the estimated impact on cash flow per
trust unit for the remaining quarter of 2008 and include the commodity
contracts described in Note 9 as well as the impact of 2008 forward market
prices as at October 28, 2008. We have not finalized our budget or plans for
2009 and consequently 2009 sensitivities are not available. To the extent the
market price of crude oil and natural gas change significantly from the
October 28, 2008 levels, the sensitivities will no longer be relevant as the
effect of our commodity contracts will change.
Estimated Effect
on Fourth Quarter
2008 Cash Flow
Sensitivity Table per Trust Unit(1)
-------------------------------------------------------------------------
Change of $0.15 per Mcf in the price of AECO natural gas $0.02
Change of US$1.00 per barrel in the price of WTI crude oil $0.01
Change of 1,000 BOE/day in production $0.02
Change of $0.01 in the US$/CDN$ exchange rate $0.03
Change of 1% in interest rate $0.01
-------------------------------------------------------------------------
(1) Assumes constant working capital and 165,197,000 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 lower during the third quarter of
2008 compared to the second quarter of 2008 due to decreased commodity prices
and lower production.
Crude oil and natural gas revenues for the three months ended September
30, 2008 were $647.8 million ($654.6 million, net of $6.8 million
transportation) compared to $364.8 million ($370.2 million, net of $5.4
million transportation) for the same period in 2007. For the nine months ended
September 30, 2008 revenues were $1,885.9 million ($1,906.1 million, net of
$20.2 million transportation) compared to $1,127.3 million ($1,144.0 million,
net of $16.7 million transportation) during the same period in 2007. Revenues
have increased compared to 2007 due to higher commodity prices and increased
production resulting from the Focus acquisition which closed on February 13,
2008.
The following table summarizes the changes in sales revenue:
Analysis of Sales
Revenue(1) Natural
($ millions) Crude Oil NGLs Gas Total
-------------------------------------------------------------------------
Quarter ended
September 30, 2007 $ 216.8 $ 18.4 $ 129.6 $ 364.8
Price variance(1) 130.2 12.7 86.8 229.7
Volume variance 0.3 2.9 50.1 53.3
-------------------------------------------------------------------------
Quarter ended
September 30, 2008 $ 347.3 $ 34.0 $ 266.5 $ 647.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
($ millions) Crude Oil NGLs Gas Total
-------------------------------------------------------------------------
Year-to-date ended
September 30, 2007 $ 592.7 $ 56.4 $ 478.2 $ 1,127.3
Price variance(1) 386.3 35.7 190.7 612.7
Volume variance (3.1) 6.5 142.5 145.9
-------------------------------------------------------------------------
Year-to-date ended
September 30, 2008 $ 975.9 $ 98.6 $ 811.4 $ 1,885.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Other Income
Other income for the three and nine months ended September 30, 2008 was
$0.3 million and $15.8 million respectively, compared to $0.1 million and
$14.6 million for the same periods in 2007. The first nine months of 2008
includes a gain of $8.3 million on the sale of certain marketable securities
and interim receipts from 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 marketable securities.
Royalties
Royalties are paid to various government entities and other land and
mineral rights owners. For the three and nine months ended September 30, 2008
royalties were $120.6 million and $352.5 million respectively, compared to
$68.2 million and $211.9 million for the same periods in 2007. Royalties as a
percentage of oil and gas sales net of transportation have been approximately
19% during these periods. The increases in royalties in 2008 are the result of
higher commodity prices and increased production. For the remainder of 2008 we
expect royalties to continue to be approximately 19% of oil and gas sales, net
of transportation.
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 outlook of US$70.00/bbl crude oil and $8.00/Mcf
natural gas, and relative to Enerplus' current properties and production
profile in Alberta, we estimate the NRF will increase our average 2009 royalty
rate to approximately 22% of oil and gas sales, net of transportation costs.
If commodity prices are higher than such estimates, we expect our average
royalty rate for 2009 to increase as well. Further information on the NRF can
be found on the Alberta government's website at www.gov.ab.ca.
Operating Expenses
Operating expenses for the third quarter of 2008 increased to $89.8
million ($10.21/BOE) from $86.0 million ($9.43/BOE) during the second quarter
of 2008 due to lower production volumes along with higher repairs and
maintenance and chemical and supply costs.
Operating expenses for the three months ended September 30, 2008 were
$89.8 million ($10.21/BOE) compared to $71.6 million ($9.73/BOE) for the third
quarter of 2007. For the nine months ended September 30, 2008 operating
expenses were $247.8 million ($9.52/BOE) compared to $210.3 million
($9.31/BOE) for the same period in 2007. This year-over-year increase is due
to additional service rig activity related to our U.S. optimization program
and higher than expected costs for repairs and maintenance, labour, and
chemicals and supplies.
Based on our year to date results and our revised 2008 production
expectations we are increasing our annual operating expense guidance from
$9.00/BOE to $9.50/BOE.
General and Administrative Expenses ("G&A")
During the third quarter of 2008 G&A expenses were $1.70/BOE compared to
$1.90/BOE for the second quarter of 2008.
G&A expenses for the three months ended September 30, 2008 were $14.9
million ($1.70/BOE) compared to $17.7 million ($2.41/BOE) for the third
quarter of 2007. G&A expenses totaled $48.7 million ($1.87/BOE) for the nine
months ended September 30, 2008 compared to $51.5 million ($2.28/BOE) for the
same period in 2007. G&A expenses have decreased year over year mainly due to
lower long-term incentive plan expenses. However, higher production volumes
during 2008 which are attributable to the Focus acquisition have helped to
reduce G&A costs per BOE.
We do not expect our long-term compensation expense to change over the
next quarter, therefore we are lowering our annual guidance for G&A expenses
from $2.20/BOE to $2.00/BOE for the year.
For the three and nine months ended September 30, 2008 our G&A expenses
included non-cash charges of $1.8 million ($0.20/BOE) and $5.4 million
($0.21/BOE) respectively, compared to $2.2 million ($0.30/BOE) and $6.4
million ($0.28/BOE) for the same periods in 2007. These amounts relate solely
to our trust unit rights incentive plan and are determined using a binomial
lattice option-pricing model. See Note 8 for further details.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and Three months ended Nine months ended
Administrative Costs September 30, September 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash $ 13.1 $ 15.5 $ 43.3 $ 45.1
Trust unit rights incentive
plan (non-cash) 1.8 2.2 5.4 6.4
-------------------------------------------------------------------------
Total G&A $ 14.9 $ 17.7 $ 48.7 $ 51.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2008 2007 2008 2007
-------------------------------------------------------------------------
Cash $ 1.50 $ 2.11 $ 1.66 $ 2.00
Trust unit rights incentive
plan (non-cash) 0.20 0.30 0.21 0.28
-------------------------------------------------------------------------
Total G&A $ 1.70 $ 2.41 $ 1.87 $ 2.28
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 was $8.8 million for the third quarter of 2008
compared to $10.4 million for the same period in 2007. Lower year over year
average debt resulting from the July 31, 2008 Joslyn disposition is the
primary reason for the decrease. For the nine months ended September 30, 2008
interest on long-term debt totaled $35.1 million compared to $29.8 million for
the same period in 2007. This increase is due to higher average outstanding
indebtedness and higher interest rates for the nine months ended September 30,
2008 over the same period in 2007.
For the three and nine months ended September 30, 2008 we recorded non-
cash interest gains of $1.6 million for both periods compared to gains of $4.0
million and $3.4 million for the same periods in 2007. The changes in the fair
value of our interest rate swaps and CCIRS that result from movements in
forward market interest rates cause non-cash interest to fluctuate between
periods.
The following table summarizes our cash and non-cash interest expense:
Three months ended Nine months ended
Interest Expense September 30, September 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Interest on long-term
debt $ 8.8 $ 10.4 $ 35.1 $ 29.8
Non-cash interest gain (1.6) (4.0) (1.6) (3.4)
-------------------------------------------------------------------------
Total Interest Expense $ 7.2 $ 6.4 $ 33.5 $ 26.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At September 30, 2008 approximately 34% of our debt was based on fixed
interest rates while 66% had floating interest rates. In comparison, at
September 30, 2007 approximately 20% of our debt was based on fixed interest
rates and 80% was floating.
Capital Expenditures
Development capital spending for the three and nine months ended
September 30, 2008 was $163.2 million and $377.5 million respectively,
compared to $90.6 million and $281.0 million during the same periods in 2007.
The increased spending levels in 2008 are largely due to our expanded asset
base resulting from the Focus acquisition and stronger commodity prices. In
addition our 2008 development capital expenditures include approximately $20
million of completed incremental land acquisitions over original budget
amounts as we look to increase our efforts on resource capture in strategic
areas. For the nine months ended September 30, 2008 we have achieved a 99%
drilling success rate on 469 net wells.
Overall our 2008 development capital program is behind schedule mainly
due to weather and project delays primarily in our shallow natural gas
program. Based on our year-to-date spending and project deferrals and
cancellations in the fourth quarter we are revising our annual development
capital guidance to $545 million from $580 million, based on a $55 million
reduction in our conventional program which is partially offset by the $20
million we have spent on additional land acquisitions. The reduction and
reallocation of expenditures within our 2008 development capital program has
modestly lowered our 2008 average annual production and exit rate
expectations.
Corporate acquisitions for the nine months ended September 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
dispositions for the three months ended September 30, 2008 relate to the
Joslyn disposition which closed on July 31, 2008.
Property acquisitions for the three and nine months ended September 30,
2008 were $4.6 million and $13.9 million respectively, compared to $1.8
million and $269.1 million for the same periods in 2007. Property acquisitions
in 2007 included the purchase of our Jonah and Kirby assets in the first and
second quarter of 2007 respectively.
Total net capital expenditures for 2008 and 2007 are outlined below:
Three months ended Nine months ended
Capital Expenditures September 30, September 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Development expenditures $ 131.7 $ 72.1 $ 299.9 $ 232.3
Plant and facilities 31.5 18.5 77.6 48.7
-------------------------------------------------------------------------
Development Capital 163.2 90.6 377.5 281.0
Office 2.4 1.7 6.0 4.6
-------------------------------------------------------------------------
Sub-total 165.6 92.3 383.5 285.6
Property acquisitions(1) 4.6 1.8 13.9 269.1
Corporate acquisitions - - 1,757.5 -
-------------------------------------------------------------------------
Capital Expenditures 170.2 94.1 2,154.9 554.7
-------------------------------------------------------------------------
Property dispositions(1) (502.5) (0.1) (504.7) (5.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Net Capital
Expenditures $ (332.3) $ 94.0 $ 1,650.2 $ 549.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Funding of Capital
Expenditures
-------------------------------------------------------------------------
Capital Expenditures
financed with cash flow $ 159.2 $ 69.7 $ 385.1 $ 180.1
Capital Expenditures
financed with debt and
equity 11.0 24.4 1,769.8 374.6
-------------------------------------------------------------------------
Total Capital Expenditures $ 170.2 $ 94.1 $ 2,154.9 $ 554.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
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 September 30, 2008 capitalized costs life-to-date
for our oil sands development were $246.0 million compared to $351.1 million
at June 30, 2008, prior to our disposition of Joslyn on July 31, 2008 for cash
consideration of $502.0 million after transaction costs.
During the third quarter of 2008 we capitalized costs of $4.4 million
associated with advancing our regulatory application for our Kirby project,
which we successfully filed on September 26, 2008.
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 Laricina's 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 September 30, 2008, DDA&A increased to
$18.32/BOE compared to $15.78/BOE during the corresponding period in 2007. For
the nine months ended September 30, 2008 DDA&A increased to $18.19/BOE
compared to $15.58/BOE during the corresponding period in 2007. The increase
is attributable to additional PP&E and production from the Focus acquisition.
No impairment of the Fund's assets existed at September 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 included on the Fund's
balance sheet are estimated by management based on the Fund's net ownership
interest in wells and facilities, estimated costs to abandon and reclaim the
wells and facilities and the estimated timing of the costs to be incurred in
future periods.
The Fund has estimated the net present value of its total asset
retirement obligations to be approximately $203.8 million at September 30,
2008 compared to $165.7 million at December 31, 2007. The increase of $38.1
million relates primarily to the Focus acquisition. See Note 3.
The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation and asset retirement
obligations settled during the period:
Three months ended Nine months ended
September 30, September 30,
($ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
Amortization of the asset
retirement cost $ 4.9 $ 3.4 $ 14.7 $ 6.9
Accretion of the asset
retirement obligation 3.1 1.7 8.7 5.0
-------------------------------------------------------------------------
Total Amortization and
Accretion $ 8.0 $ 5.1 $ 23.4 $ 11.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement
Obligations Settled $ 4.7 $ 3.5 $ 13.5 $ 10.7
-------------------------------------------------------------------------
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.
Our future income tax expense was $1.4 million for the quarter ended
September 30, 2008 compared to a recovery of $8.8 million for the same period
in 2007. The increased expense is the result of commodity derivative
instrument gains during the third quarter of 2008 which were partially offset
by a future tax recovery related to the Joslyn disposition that closed July
31, 2008.
In July 2008, the Department of Finance issued draft amendments to the
Income Tax Regulations regarding the provincial tax rate for new specified
investment flow through ("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 and be effective January 1, 2011. The
amendments were not considered substantively enacted at September 30, 2008. As
a result there was no consequential impact on future income taxes in the third
quarter however this will result in a future income tax recovery when enacted.
The Department of Finance has released draft legislative proposals which
include amendments to allow a SIFT to convert into a corporation without
adverse Canadian tax consequences for the trust or its Canadian unitholders.
We believe that a trust conversion under the proposed rules would qualify as a
U.S. tax deferred transaction for our U.S. unitholders as well. Enerplus
submitted comments on these proposals as permitted by the Canadian Department
of Finance. We continue to review the legislative proposals to determine the
impact to Enerplus should we 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. This liability was included
in Focus' assumed working capital and was paid in April 2008. We expect to
recover the majority of this amount during 2008 as a result of claiming
taxable deductions. For the nine months ended September 30, 2008 we have
recorded $16.9 million in recoveries related to the $24.3 million.
The amount of current taxes recorded with respect to our U.S. operations
is dependent upon income levels along with the timing of capital expenditures
and the repatriation of funds to Canada. For the three and nine months ended
September 30, 2008 our U.S. operations incurred taxes (income and withholding)
in the amount of $14.2 million and $47.9 million respectively, compared to
$5.1 and $10.4 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 third quarter of 2008 was $465.8 million or $2.82 per
trust unit compared to $93.0 million or $0.72 per trust unit in the same
period for 2007. The third quarter 2008 increase compared to the same period
in 2007 is primarily due to an increase in oil and gas sales of $284.4 million
and an increase in cash and non-cash commodity derivative instrument gains of
$217.1 million, which were offset by increased royalties of $52.5 million and
a $45.2 million increase in DDA&A.
Net income for the nine months ended September 30, 2008 was $699.4
million or $4.40 per trust unit compared to $241.0 million or $1.90 per trust
unit for the same period in 2007. The $458.4 million increase in net income
for the nine months ended September 30, 2008 was primarily due to an increase
in oil and gas sales of $762.2 million and a $122.7 million increase in the
future tax recovery, which were partially offset by increases in royalties of
$140.6 million, cash and non-cash commodity derivative instrument losses of
$90.7 million and DDA&A of $121.5 million.
Cash Flow from Operating Activities
Cash flow for the three and nine months ended September 30, 2008 was
$383.6 million ($2.33 per trust unit) and $1,004.2 million ($6.32 per trust
unit) respectively, compared to $232.8 million ($1.80 per trust unit) and
$663.5 million ($5.22 per trust unit) for the three and nine months ended
September 30, 2007. The increases per trust unit were primarily a result of
higher commodity prices combined with increased oil and gas sales resulting
from the Focus acquisition.
Selected Financial Results
Three months ended Three months ended
September 30, 2008 September 30, 2007
-------------------------- ---------------------------
Operating Non-Cash Operating Non-Cash
Per BOE of Cash & Other Cash & Other
production (6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production per day 95,644 79,891
-------------------------------------------------------------------------
Weighted average
sales price(2) $ 73.62 $ - $ 73.62 $ 49.64 $ - $ 49.64
Royalties (13.71) - (13.71) (9.28) - (9.28)
Commodity derivative
instruments (6.82) 31.90 25.08 1.00 (0.51) 0.49
Operating costs (10.10) (0.11) (10.21) (9.61) (0.12) (9.73)
General and
administrative (1.50) (0.20) (1.70) (2.11) (0.30) (2.41)
Interest expense,
net of other income (0.97) 0.18 (0.79) (1.40) 0.54 (0.86)
Foreign exchange
gain/(loss) (0.49) 0.19 (0.30) 0.06 0.03 0.09
Current income tax (0.59) - (0.59) (0.70) - (0.70)
Restoration and
abandonment cash
costs (0.54) 0.54 - (0.48) 0.48 -
Depletion, depreci-
ation, amortization
and accretion - (18.32) (18.32) - (15.78) (15.78)
Future income tax
recovery/(expense) - (0.15) (0.15) - 1.20 1.20
-------------------------------------------------------------------------
Total per BOE $ 38.90 $ 14.03 $ 52.93 $ 27.12 $(14.46) $ 12.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
Nine months ended Nine months ended
September 30, 2008 September 30, 2007
--------------------------- ---------------------------
Operating Non-Cash Operating Non-Cash
Per BOE of Cash & Other Cash & Other
production (6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production per day 95,010 82,777
-------------------------------------------------------------------------
Weighted average
sales price(2) $ 72.44 $ - $ 72.44 $ 49.89 $ - $ 49.89
Royalties (13.54) - (13.54) (9.38) - (9.38)
Commodity derivative
instruments (5.19) 1.55 (3.64) 0.63 (0.81) (0.18)
Operating costs (9.51) (0.01) (9.52) (9.32) 0.01 (9.31)
General and
administrative (1.66) (0.21) (1.87) (2.00) (0.28) (2.28)
Interest expense,
net of other income (1.06) 0.06 (1.00) (1.29) 0.15 (1.14)
Foreign exchange
(loss)/gain (0.17) (0.02) (0.19) (0.05) 0.23 0.18
Current income tax (1.19) - (1.19) (0.46) - (0.46)
Restoration and
abandonment cash
costs (0.52) 0.52 - (0.47) 0.47 -
Depletion, depreci-
ation, amortization
and accretion - (18.19) (18.19) - (15.58) (15.58)
Future income tax
recovery/(expense) - 3.24 3.24 - (1.70) (1.70)
Gain on sale of
marketable
securities(3) - 0.32 0.32 - 0.62 0.62
-------------------------------------------------------------------------
Total per BOE $ 39.60 $(12.74) $ 26.86 $ 27.55 $(16.89) $ 10.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 nine months ended September 30, 2008 and
2007.
(CDN$ millions, Three months ended Three months ended
except per unit September 30, 2008 September 30, 2007
amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily
Production
Volumes
Natural gas
(Mcf/day) 329,047 12,756 341,803 241,196 10,068 251,264
Crude oil
(bbls/day) 25,484 8,635 34,119 24,236 9,841 34,077
Natural gas
liquids
(bbls/day) 4,557 - 4,557 3,937 - 3,937
Total Daily
Sales
(BOE/day) 84,883 10,761 95,644 68,372 11,519 79,891
Pricing(1)
Natural gas
(per Mcf) $ 8.17 $ 10.39 $ 8.25 $ 5.58 $ 5.67 $ 5.59
Crude oil
(per bbl) 110.10 112.02 110.63 65.78 77.49 69.16
Natural gas
liquids
(per bbl) 81.20 - 81.20 50.79 - 50.79
Capital
Expenditures
Development
capital and
office $ 146.7 $ 18.9 $ 165.6 $ 70.5 $ 21.8 $ 92.3
Acquisitions
of oil and
gas
properties 4.5 0.1 4.6 1.8 - 1.8
Dispositions of
oil and gas
properties (502.6) 0.1 (502.5) (0.1) - (0.1)
Revenues
Oil and gas
sales(1) $ 546.5 $ 101.3 $ 647.8 $ 289.4 $ 75.4 $ 364.8
Royalties(2) (98.8) (21.8) (120.6) (52.6) (15.6) (68.2)
Financial
contracts 220.7 - 220.7 3.6 - 3.6
Expenses
Operating $ 85.1 $ 4.7 $ 89.8 $ 68.9 $ 2.7 $ 71.6
General and
admini-
strative 13.6 1.3 14.9 16.3 1.4 17.7
Depletion,
depreciation,
amortization
and accretion 139.2 22.0 161.2 88.9 27.1 116.0
Current income
taxes
(recovery)/
expense (9.0) 14.2 5.2 - 5.1 5.1
-------------------------------------------------------------------------
(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, Nine months ended Nine months ended
except per unit September 30, 2008 September 30, 2007
amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily Production
Volumes
Natural gas
(Mcf/day) 323,819 12,509 336,328 253,698 10,186 263,884
Crude oil
(bbls/day) 24,955 9,340 34,295 24,705 9,897 34,602
Natural gas
liquids
(bbls/day) 4,660 - 4,660 4,194 - 4,194
Total Daily
Sales
(BOE/day) 83,585 11,425 95,010 71,182 11,595 82,777
Pricing(1)
Natural gas
(per Mcf) $ 8.53 $ 10.41 $ 8.60 $ 6.63 $ 6.78 $ 6.63
Crude oil
(per bbl) 103.73 106.83 103.85 60.06 69.45 62.75
Natural gas
liquids
(per bbl) 77.21 - 77.21 49.26 - 49.26
Capital
Expenditures
Development
capital and
office $ 331.5 $ 52.0 $ 383.5 $ 193.1 $ 92.5 $ 285.6
Acquisitions
of oil and
gas
properties 13.9 - 13.9 208.3 60.8 269.1
Dispositions
of oil and gas
properties (504.8) 0.1 (504.7) (5.6) - (5.6)
Revenues
Oil and gas
sales(1) $ 1,576.8 $ 309.1 $ 1,885.9 $ 920.8 $ 206.5 $ 1,127.3
Royalties(2) (286.2) (66.3) (352.5) (170.2) (41.7) (211.9)
Financial
contracts (94.7) - (94.7) (4.1) - (4.1)
Expenses
Operating $ 234.5 $ 13.3 $ 247.8 $ 203.3 $ 7.0 $ 210.3
General and
admini-
strative 44.7 4.0 48.7 46.1 5.4 51.5
Depletion,
depreciation,
amortization
and accretion 407.2 66.3 473.5 269.9 82.1 352.0
Current income
taxes
(recovery)/
expense (16.9) 47.9 31.0 - 10.4 10.4
-------------------------------------------------------------------------
(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 primarily
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. During the third quarter of 2008 our realized natural gas and crude oil
prices reduced 16% and 3% to $8.25/Mcf and $110.63/bbl compared to the second
quarter of 2008 respectively, resulting in lower oil and gas sales.
Net income has been affected by additional production from the Focus
acquisition, fluctuating commodity prices (both current and future), risk
management costs, the strengthening Canadian dollar, higher operating costs,
changes in future tax provisions as well as changes to accounting policies
adopted during 2007.
Net Income
Quarterly Financial Information Oil per trust unit
($ millions, except per trust and Gas Net -------------------
unit amounts) Sales(1) Income Basic Diluted
-------------------------------------------------------------------------
2008
Third Quarter $ 647.8 $ 465.8 $ 2.82 $ 2.82
Second Quarter 734.4 112.2 0.68 0.68
First quarter 503.7 121.4 0.82 0.82
-----------------------------------------------------
Total $ 1,885.9 $ 699.4 $ 4.40 $ 4.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
Capital Markets and Enerplus' Credit Exposure
The recent turmoil in the financial markets has negatively impacted the
availability of credit and equity in the marketplace. The current market
conditions indicate that it may be difficult to issue additional equity or
increase credit capacity without significant costs at this time. In addition,
there has been a dramatic reduction in crude oil and natural gas prices since
September 30, 2008. As a result there has been a greater emphasis on
evaluating credit capacity, credit counterparties and liquidity. We have
discussed these risks as they relate to our credit facility, oil and gas sales
counterparties, financial derivative counterparties and joint venture partners
below.
Credit Facility
----------------
Enerplus' bank credit facility is an unsecured, covenant-based credit
agreement with a syndicate of thirteen financial institutions, a summary of
which was filed on March 18, 2008 as a "Material document" on the Fund's SEDAR
profile at www.sedar.com. Of the thirteen syndicate members in Enerplus'
facility, seven are major Canadian banks which represent approximately $1.025
billion or 73% of the commitments under the $1.4 billion facility. The
facility is extendable each year and is currently set to expire in November
2010. Rates under the facility range between 55.0 and 110.0 basis points over
bankers' acceptance rates and are significantly lower than rates currently
being negotiated in the marketplace. At September 30, 2008 we have drawn
$277.3 million or approximately 20% of our $1.4 billion facility and have a
trailing debt-to-cash flow ratio of 0.4x. Our borrowing cost is currently 55.0
basis points over bankers' acceptance rates.
As at September 30, 2008 Enerplus is in compliance with all covenants
under the credit facility. Our exposure to our lenders relates to their
potential inability to fund. Should a lender be unable or choose not to fund,
other lenders have the right, but not the obligation, to increase their
commitment levels to cover the shortfall. Failure to fund would be considered
a breach of contract and could result in potential damages in favor of
Enerplus, however the likelihood of substantiating and receiving damages is
unknown. We have not experienced any funding issues under the facility to date
and we anticipate that the proposed government measures to guarantee
inter-bank lending will improve market liquidity and reduce this potential
risk for Enerplus.
Oil and Gas Sales Counterparties
--------------------------------
The Fund's oil and gas receivables are with customers in the petroleum
and natural gas business and are subject to normal credit risks. Concentration
of credit risk is mitigated by marketing production to numerous purchasers
under normal industry sale and payment terms. We also have a credit review
process that we use to assess and monitor our counterparties' credit
worthiness on a regular basis. This process involves reviewing and ratifying
our corporate credit guidelines, assessing the credit ratings of our
counterparties and setting exposure limits. When warranted we obtain financial
assurances such as letters of credit, parental guarantees, or third party
insurance to mitigate our credit risk. This process is completed for both our
oil and gas sales counterparties as well as our financial derivative
counterparties. For the nine months ended September 30, 2008, we have made a
$1.5 million bad debt provision, the majority of which relates to our exposure
to a Canadian subsidiary of SemGroup L.P., which is currently subject to
insolvency proceeding in the U.S.
Financial Derivative Counterparties
-----------------------------------
The Fund is exposed to credit risk in the event of non-performance by our
financial counterparties regarding our derivative contracts. The Fund
mitigates this risk by entering into transactions with highly rated major
financial institutions, the majority of which are members of our bank
syndicate. We have no exposure to Lehman Brothers, which is currently in
insolvency proceedings. We have International Swaps and Derivatives
Association ("ISDA") agreements in place with the majority of our financial
counterparties. These agreements provide some credit protection in that they
allow parties to aggregate amounts owing to each other under all outstanding
transactions and settle with a single net amount in the case of a credit
event. Absent an ISDA we rely on long form confirmations which provide
Enerplus with similar credit protection in terms of aggregating transactions
and netting for settlement in the case of a credit event.
We will continue to monitor developments in the financial markets that
could impact the credit worthiness of our financial counterparties however it
has recently been very difficult to foresee counterparty solvency issues. To
date we have not experienced any losses due to non-performance by our
derivative counterparties.
Joint Venture Partners
----------------------
We continue to attempt to mitigate the credit risk associated with our
joint interest receivables by reviewing and actively following up on older
accounts. In addition, we are specifically monitoring our receivables against
a watch list of publicly traded companies that have high debt-to-cash flow
ratios or highly drawn bank facilities. We do not anticipate any significant
issues in the collection of our joint interest receivables at this time
outside of those for which we have already provided. However, if the current
low commodity prices and tight capital markets prevail, there is a risk of
increased bad debts related to our industry partners.
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.
Enerplus currently 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 approximately 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.
The significant decrease in crude oil and natural gas prices has resulted
in a decrease in our overall cash flows. This commodity downturn, combined
with the current uncertainty in the capital markets, has reinforced our belief
in the importance of maintaining strong financial flexibility. To that end, we
have reduced our monthly cash distribution to $0.38 per unit from $0.47 per
unit effective November 20, 2008.
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 third quarter of 2008
cash distributions of $224.4 million were funded entirely through cash flow of
$383.6 million. For the nine months ended September 30, 2008 our cash
distributions of $619.1 million were funded entirely through cash flow of
$1,004.2 million.
Our payout ratio, which is calculated as cash distributions divided by
cash flow, was 59% and 62% for the three and nine months ended September 30,
2008 respectively, compared to 70% and 73% for the same periods in 2007. See
"Non-GAAP Measures" in this MD&A.
In aggregate, our 2008 third quarter cash distributions of $224.4 million
combined with our development capital and office expenditures of $165.6
million totaled $390.0 million, or approximately 102% of our cash flow of
$383.6 million. For the nine months ended September 30, 2008 our cash
distributions of $619.1 million combined with our development capital and
office expenditures of $383.5 million totaled $1,002.6 million, or
approximately 100% of our cash flow of $1,004.2 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 September 30, 2008, our net income exceeded
our cash distributions by $241.4 million whereas in 2007 our cash
distributions exceeded our net income by $70.1 million. For the nine months
ended September 30, 2008 our net income exceeded our cash distributions by
$80.3 million whereas in 2007 our cash distributions exceeded our net income
by $242.4 million. Non-cash items, such as changes in the fair value of our
derivative instruments and future income taxes, cause net income to fluctuate
between periods but do not impact cash flow from operations. Future income
taxes can fluctuate from period to period as a result of changes in tax rates
as well as changes in interest, royalties and dividends from our operating
subsidiaries paid to the Fund. In addition, other non-cash charges such as
DDA&A are not a good proxy for the cost of maintaining our productive capacity
as they are based on the historical costs of our PP&E and not the fair market
value of replacing those assets within the context of the current environment.
It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. Therefore we do not
distinguish maintenance capital separately from development capital spending.
The level of investment in a given period may not be sufficient to replace
productive capacity given the natural declines associated with oil and natural
gas assets. In these instances a portion of the cash distributions paid to
unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income:
Three months Nine months
ended ended Year ended Year ended
($ millions, except September September December December
per unit amounts) 30, 2008 30, 2008 31, 2007 31, 2006
-------------------------------------------------------------------------
Cash flow from
operating activities $ 383.6 $ 1,004.2 $ 868.5 $ 863.7
Cash distributions 224.4 619.1 646.8 614.3
-------------------------------------------------------------------------
Excess of cash flow
over cash distributions $ 159.2 $ 385.1 $ 221.7 $ 249.4
Net income $ 465.8 $ 699.4 $ 339.7 $ 544.8
Excess/(shortfall)
of net income over
cash distributions 241.4 80.3 (307.1) (69.5)
Cash distributions per
weighted average trust
unit $ 1.36 $ 3.89 $ 5.07 $ 5.05
Payout ratio (1) 59% 62% 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 September 30, 2008 was $522.8 million which is
comprised of $277.3 million of bank indebtedness and $245.5 million of senior
unsecured notes. Long-term debt decreased by $203.9 million from December 31,
2007 due to the $502.0 million of net proceeds received from the Joslyn
disposition partially offset by additional debt acquired in the Focus
acquisition.
Our working capital deficiency, excluding cash, at September 30, 2008
decreased to $161.7 million from $203.4 million at December 31, 2007.
Excluding current deferred financial assets and credits and the related
current future income taxes, our working capital deficiency decreased by $16.4
million compared to December 31, 2007. This decrease is primarily due to
higher production levels and commodity prices which more than offset the
additional payables associated with more units and higher distributions.
We continue to maintain a conservative balance sheet as demonstrated
below:
Financial Leverage and Coverage September December
30, 2008 31, 2007
-------------------------------------------------------------------------
Long-term debt to trailing cash flow 0.4x 0.8x
Cash flow to interest expense 25.3x 25.8x
Long-term debt to long-term debt plus equity 11% 22%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
Cash flow and interest expense are 12-months trailing.
At September 30, 2008 Enerplus had a $1.4 billion unsecured covenant
based term bank facility maturing 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 term. Due to the volatility in
the credit capital markets we chose not to extend the term of the credit
facility this year. The facility 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 September 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.
Net proceeds of $502.0 million from the Joslyn disposition which closed
July 31, 2008 have been used to pay down debt, improving our debt-to-cash flow
ratio which supports our ability to fund future development capital and
acquisition activities and minimizes the need to issue additional equity. We
continue to have adequate liquidity to fund planned development capital
spending for the remainder of 2008 through a combination of cash flow retained
by the business and debt, if needed.
Commitments
During the quarter we acquired additional office space which results in
the following total commitments for our office leases:
Total
Minimum Annual Commitment Each Year Committed
--------------------------------------- after
($ thousands) Total 2009 2010 2011 2012 2013 2013
-------------------------------------------------------------------------
Office leases $69,493 $ 8,722 $12,266 $12,316 $12,400 $12,400 $11,389
-------------------------------------------------------------------------
Trust Unit Information
We had 165,197,000 trust units outstanding at September 30, 2008. This
includes the 30,150,000 units issued on February 13, 2008 to acquire Focus and
7,586,000 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
7,586,000 exchangeable limited partnership units are convertible at the option
of the holder into 0.425 of an Enerplus trust unit (3,224,000 trust units).
This compares to 129,552,000 trust units at September 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 nine months ended September 30, 2008 was 158,980,000 (2007
- 127,025,000). At October 31, 2008 we had 165,286,000 trust units outstanding
including the equivalent limited partnership units.
During the three months ended September 30, 2008, 488,000 trust units
(2007 - 347,000) 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 $19.3 million (2007 -
$15.1 million) of additional equity to the Fund. For the nine months ended
September 30, 2008 $60.0 million of additional equity (2007 - $46.8 million)
and 1,488,000 trust units (2007 - 1,046,000) were issued pursuant to the DRIP
and the trust unit incentive 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. The terms for continuing this Qualified Dividend tax rate are largely
dependent on the outcome of the U.S. presidential election. 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 are unable to determine
when or if Bill 1672 will be enacted as presented.
In October 2008, Enerplus estimated its non-resident ownership to be
approximately 66%.
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. At this stage, without
further clarity and specific details from the Government of Canada, it is
impossible to forecast with any certainty 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. Currently, we are assessing the
effects of adoption and developing a plan accordingly. We will continue to
monitor any changes in the adoption of IFRS and will update plans as
necessary.
INTERNAL CONTROLS AND PROCEDURES
There were no changes in our internal control over financial reporting
during the quarter ended September 30, 2008 that have materially affected, or
are reasonably likely to materially affect, our internal control over
financial reporting.
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
(CDN$ thousands) (Unaudited) 2008 2007
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 560 $ 1,702
Accounts receivable 182,821 145,602
Deferred financial assets (Note 9) 14,164 10,157
Future income taxes 2,129 10,807
Other current 6,560 6,373
-------------------------------------------------------------------------
206,234 174,641
Property, plant and equipment (Note 2) 5,105,710 3,872,818
Goodwill (Note 4) 609,423 195,112
Deferred financial assets (Note 9) 2,040 -
Other assets (Note 9) 57,116 60,559
-------------------------------------------------------------------------
$ 5,980,523 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 267,304 $ 269,375
Distributions payable to unitholders 77,643 54,522
Deferred financial credits (Note 9) 22,398 52,488
-------------------------------------------------------------------------
367,345 376,385
-------------------------------------------------------------------------
Long-term debt (Note 5) 522,814 726,677
Deferred financial credits (Note 9) 74,986 90,090
Future income taxes 621,133 304,259
Asset retirement obligations (Note 3) 203,837 165,719
-------------------------------------------------------------------------
1,422,770 1,286,745
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 8) 5,459,138 4,032,680
Accumulated deficit (1,203,677) (1,283,953)
Accumulated other comprehensive income (65,053) (108,727)
-------------------------------------------------------------------------
(1,268,730) (1,392,680)
4,190,408 2,640,000
-------------------------------------------------------------------------
$ 5,980,523 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
Three months ended Nine months ended
(CDN$ thousands) September 30, September 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Accumulated income,
beginning of period $ 2,520,551 $ 2,095,193 $ 2,286,927 $ 1,952,960
Adjustment for
adoption of financial
instruments standards - - - (5,724)
-------------------------------------------------------------------------
Revised accumulated
income, beginning of
period 2,520,551 2,095,193 2,286,927 1,947,236
Net income 465,773 93,033 699,397 240,990
-------------------------------------------------------------------------
Accumulated income,
end of period 2,986,324 2,188,226 2,986,324 2,188,226
Accumulated cash
distributions,
beginning of period (3,965,584) (3,244,323) (3,570,880) (2,924,045)
Cash distributions (224,417) (163,110) (619,121) (483,388)
-------------------------------------------------------------------------
Accumulated cash
distributions, end
of period (4,190,001) (3,407,433) (4,190,001) (3,407,433)
-------------------------------------------------------------------------
Accumulated deficit,
end of period $(1,203,677) $(1,219,207) $(1,203,677) $(1,219,207)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Three months ended Nine months ended
(CDN$ thousands) September 30, September 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Balance, beginning
of period $ (93,128) $ (65,378) $ (108,727) $ (8,979)
Transition
adjustments on
adoption:
Cash flow hedges - - - 660
Available for
sale marketable
securities - - - 14,252
Other comprehensive
income/(loss) 28,075 (39,343) 43,674 (110,654)
-------------------------------------------------------------------------
Balance, end of
period $ (65,053) $ (104,721) $ (65,053) $ (104,721)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(CDN$ thousands)
except per trust Three months ended Nine months ended
unit amounts) September 30, September 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 654,592 $ 370,163 $ 1,906,131 $ 1,143,960
Royalties (120,635) (68,165) (352,511) (211,927)
Commodity derivative
instruments (Note 9) 220,652 3,585 (94,742) (4,067)
Other income 295 143 15,822 14,575
-------------------------------------------------------------------------
754,904 305,726 1,474,700 942,541
-------------------------------------------------------------------------
Expenses
Operating 89,801 71,551 247,791 210,337
General and
administrative 14,935 17,718 48,699 51,488
Transportation 6,757 5,334 20,201 16,651
Interest (Note 6) 7,238 6,438 33,539 26,400
Foreign exchange (Note 7) 2,655 (643) 4,931 (4,117)
Depletion, depreciation,
amortization and
accretion 161,178 116,001 473,468 352,001
-------------------------------------------------------------------------
282,564 216,399 828,629 652,760
-------------------------------------------------------------------------
Income before taxes 472,340 89,327 646,071 289,781
Current taxes 5,211 5,081 30,963 10,372
Future income tax
expense/(recovery) 1,356 (8,787) (84,289) 38,419
-------------------------------------------------------------------------
Net Income $ 465,773 $ 93,033 $ 699,397 $ 240,990
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust
unit
Basic $ 2.82 $ 0.72 $ 4.40 $ 1.90
Diluted $ 2.82 $ 0.72 $ 4.40 $ 1.90
-------------------------------------------------------------------------
Weighted average
number of trust
units outstanding
(thousands)(1)
Basic 164,908 129,373 158,980 127,025
Diluted 165,001 129,402 159,089 127,083
-------------------------------------------------------------------------
(1) Includes exchangeable limited partnership units.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three months ended Nine months ended
(CDN$ thousands) September 30, September 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net income $ 465,773 $ 93,033 $ 699,397 $ 240,990
-------------------------------------------------------------------------
Other comprehensive
income/(loss), net
of tax:
Unrealized gain/
(loss) on
marketable
securities - 545 2,578 (109)
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 - (177) 74 (557)
Change in cumulative
translation adjustment 28,075 (39,711) 47,180 (98,334)
-------------------------------------------------------------------------
Other comprehensive
income/(loss) 28,075 (39,343) 43,674 (110,654)
-------------------------------------------------------------------------
Comprehensive income $ 493,848 $ 53,690 $ 743,071 $ 130,336
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended Nine months ended
(CDN$ thousands) September 30, September 30,
(Unaudited) 2008 2007 2008 2007
-------------------------------------------------------------------------
Operating Activities
Net income $ 465,773 $ 93,033 $ 699,397 $ 240,990
Non-cash items
add/(deduct):
Depletion, depreciation,
amortization and
accretion 161,178 116,001 473,468 352,001
Change in fair value
of derivative
instruments (Note 9) (292,419) 16,388 (57,160) 49,841
Unit based
compensation (Note 8) 1,783 2,192 5,363 6,410
Foreign exchange on
translation of senior
notes (Note 7) 9,570 (15,586) 16,645 (39,276)
Future income tax 1,356 (8,787) (84,289) 38,419
Amortization of
senior notes premium (164) (155) (474) (483)
Reclassification
adjustments from
AOCI to net income - (177) 92 (557)
Gain on sale of
marketable securities - - (8,263) (14,055)
Asset retirement
obligations settled
(Note 3) (4,734) (3,547) (13,501) (10,664)
-------------------------------------------------------------------------
342,343 199,362 1,031,278 622,626
Decrease/(Increase) in
non-cash operating
working capital 41,230 33,439 (27,032) 40,838
-------------------------------------------------------------------------
Cash flow from operating
activities 383,573 232,801 1,004,246 663,464
-------------------------------------------------------------------------
Financing Activities
Issue of trust units,
net of issue costs
(Note 8) 19,255 15,087 59,951 246,311
Cash distributions to
unitholders (224,417) (163,110) (619,121) (483,388)
(Decrease)/Increase in
bank credit facilities (514,893) 8,145 (550,947) 72,495
Decrease in non-cash
financing working
capital 8,463 141 23,121 2,690
-------------------------------------------------------------------------
Cash flow from financing
activities (711,592) (139,737) (1,086,996) (161,892)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (165,647) (92,324) (383,531) (285,678)
Property acquisitions (4,574) (1,755) (13,863) (214,399)
Property dispositions
(Note 2) 502,489 96 504,697 (1,056)
Proceeds on sale of
marketable securities - - 18,320 16,467
Purchase of equity
investments (7,150) - (7,150) -
Decrease/(increase)
in non-cash financing
working capital 3,378 3,419 (37,258) (11,078)
-------------------------------------------------------------------------
Cash flow from
investing activities 328,496 (90,564) 81,215 (495,744)
-------------------------------------------------------------------------
Effect of exchange rate
changes on cash (640) (1,980) 393 (3,382)
-------------------------------------------------------------------------
Change in cash (163) 520 (1,142) 2,446
Cash, beginning of period 723 2,050 1,702 124
-------------------------------------------------------------------------
Cash, end of period $ 560 $ 2,570 $ 560 $ 2,570
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash
Flow Information
Cash income taxes
paid $ 28,320 $ 3,340 $ 62,078 $ 10,586
Cash interest paid $ 5,017 $ 6,052 $ 31,315 $ 26,782
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)
September 30, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Property, plant and equipment $ 8,145,193 $ 6,429,241
Accumulated depletion, depreciation
and accretion (3,039,483) (2,556,423)
-------------------------------------------------------------------------
Net property, plant and equipment $ 5,105,710 $ 3,872,818
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development general and administrative ("G&A") expense of
$16,870,000 (2007 - $12,497,000) is included in PP&E for the nine months
ended September 30, 2008. Excluded from PP&E for the depletion and
depreciation calculation is $245,988,000 related to the oil sands
projects which have not yet commenced commercial production. In 2007
$303,678,000 was excluded from PP&E for the depletion and depreciation
calculation related to the Kirby oil sands project as well as the oil
sands Joslyn project. The Joslyn project was sold on July 31, 2008 for
net proceeds of approximately $502.0 million.
3. ASSET RETIREMENT OBLIGATIONS
Following is a reconciliation of the asset retirement obligations:
Nine months ended Year ended
September 30, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Asset retirement obligations, beginning of
period $ 165,719 $ 123,619
Corporate acquisition 36,784 -
Changes in estimates 1,589 46,000
Property acquisition and development activity 4,611 6,441
Dispositions (110) (756)
Asset retirement obligations settled (13,501) (16,280)
Accretion expense 8,745 6,695
-------------------------------------------------------------------------
Asset retirement obligations, end of period $ 203,837 $ 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 $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 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 $40.02 per trust unit
5. LONG-TERM DEBT
September 30, December 31,
($ thousands) 2008 2007
-------------------------------------------------------------------------
Bank credit facilities (a) $ 277,312 $ 497,347
Senior notes (b)
US$175 million (issued June 19, 2002) 188,267 175,973
US$54 million (issued October 1, 2003) 57,235 53,357
-------------------------------------------------------------------------
Total long-term debt $ 522,814 $ 726,677
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus has a $1.4 billion unsecured covenant based term facility that
matures November 18, 2010. The facility is extendible each year with a
bullet payment required at the end of the 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 nine months ended September 30,
2008 was 3.8% (September 30, 2007 - 5.0%).
(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 September 30, 2008 the amortized cost of
the US$175,000,000 senior notes was US$177,627,000.
6. INTEREST EXPENSE
Three months ended Nine months ended
September 30, September 30,
($ thousands) 2008 2007 2008 2007
-------------------------------------------------------------------------
Realized
Interest on long-term
debt $ 8,813 $ 10,405 $ 35,076 $ 29,842
Unrealized
Gain on cross currency
interest rate swap (2,426) (4,718) (3,551) (1,808)
Loss/(gain) on interest
rate swaps 1,015 871 2,488 (1,228)
Amortization of senior
notes premium (164) (120) (474) (406)
-------------------------------------------------------------------------
Interest expense $ 7,238 $ 6,438 $ 33,539 $ 26,400
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. FOREIGN EXCHANGE
Three months ended Nine months ended
September 30, September 30,
($ thousands) 2008 2007 2008 2007
-------------------------------------------------------------------------
Realized
Foreign exchange
loss/(gain) $ 4,349 $ (415) $ 4,367 $ 1,027
Unrealized
Foreign exchange
loss/(gain) on
translation of U.S.
dollar denominated
senior notes 9,570 (15,586) 16,645 (39,276)
Foreign exchange
(gain)/loss on
cross currency
interest rate swap (9,125) 14,105 (13,616) 32,879
Foreign exchange
(gain)/loss on
foreign exchange swaps (2,139) 1,253 (2,465) 1,253
-------------------------------------------------------------------------
Foreign exchange
loss/(gain) $ 2,655 $ (643) $ 4,931 $ (4,117)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed
to foreign currency fluctuations and are translated into Canadian dollars
at the exchange rate in effect at the balance sheet date. Foreign
exchange gains and losses are included in the determination of net income
for the period.
8. UNITHOLDERS' CAPITAL
Unitholders' capital as presented on the Consolidated Balance Sheets
consists of trust unit capital, exchangeable partnership unit capital and
contributed surplus.
Nine months ended Year ended
September 30, December 31,
Unitholders' capital ($ thousands) 2008 2007
-------------------------------------------------------------------------
Trust units $ 5,310,972 $ 4,020,228
Exchangeable limited partnership units 129,035 -
Contributed surplus 19,131 12,452
-------------------------------------------------------------------------
Balance, end of period $ 5,459,138 $ 4,032,680
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Trust Units
Authorized: Unlimited number of trust units
Nine months ended Year ended
(thousands) September 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 200 6,595 205 6,758
Cancelled trust units (116) (3,794) - -
Exchangeable limited
partnership units exchanged 638 25,516 - -
Trust unit rights
incentive plan
(non-cash) - exercised - 2,478 - 2,288
DRIP(*), net of redemptions 1,288 53,356 1,102 50,053
Issued for acquisition of
corporate and property
interests (non-cash) 30,150 1,206,593 1,105 54,750
-------------------------------------------------------------------------
161,973 $5,310,972 129,813 $4,020,228
Equivalent exchangeable
partnership units 3,224 129,035 - -
-------------------------------------------------------------------------
Balance, end of period 165,197 $5,440,007 129,813 $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 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 third quarter of 2008, 299,000 exchangeable limited
partnership units were converted into 127,000 trust units. As at
September 30, 2008, the 7,586,000 outstanding exchangeable limited
partnership units represent the equivalent of 3,224,000 trust units.
Nine months ended Year ended
(thousands) September 30, 2008 December 31, 2007
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Assumed on February 13, 2008 9,087 $ 154,551 - $ -
Exchanged for trust units (1,501) (25,516) - -
-------------------------------------------------------------------------
Balance, end of period 7,586 $ 129,035 - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Contributed Surplus
Nine months ended Year ended
September 30, December 31,
Contributed surplus ($ thousands) 2008 2007
-------------------------------------------------------------------------
Balance, beginning of period $ 12,452 $ 6,305
Trust unit rights incentive plan
(non-cash) - exercised (2,478) (2,288)
Trust unit rights incentive plan
(non-cash) - expensed 5,363 8,435
Cancelled trust units 3,794 -
-------------------------------------------------------------------------
Balance, end of period $ 19,131 $ 12,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(d) Trust Unit Rights Incentive Plan
As at September 30, 2008 a total of 4,236,000 rights were issued and
outstanding pursuant to the Trust Unit Rights Incentive Plan ("Rights
Incentive Plan") with an average exercise price of $45.32. This
represents 2.6% of the total trust units outstanding of which 1,874,000
rights, with an average exercise price of $45.62, 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, second and third quarter of 2008 reduced the exercise price of
the outstanding rights by $0.43 per trust unit effective July 2008,
$0.41 per trust unit effective October 2008 and $0.59 per trust unit
effective January 2009.
Activity for the rights issued pursuant to the Rights incentive Plan is
as follows:
Nine months ended Year ended
September 30, 2008 December 31, 2007
-------------------------------------------------------------------------
Weighted Weighted
Number Average Number Average
of Rights Exercise of 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 1,384 42.25 816 48.71
Exercised (200) 32.89 (205) 32.90
Cancelled (352) 46.84 (286) 50.74
-------------------------------------------------------------------------
End of period 4,236 $ 45.32 3,404 $ 47.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable at
end of period 1,874 $ 45.62 1,635 $ 44.84
-------------------------------------------------------------------------
(1) Exercise price reflects grant prices less reduction in exercise 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 expenses related
to rights issued for the three and nine months ended September 30, 2008
were $1,783,000 ($0.01 per unit) and $5,363,000 ($0.03 per unit)
respectively. Non-cash compensation costs for the three and nine months
ended September 30, 2007 were $2,192,000 ($0.02 per unit) and $6,410,000
($0.05 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 limited 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 Incentive
Plan.
Net income per trust unit has been determined based on the following:
Nine months ended September 30,
(thousands) 2008 2007
-------------------------------------------------------------------------
Weighted average trust units 155,977 127,025
Weighted average exchangeable
limited partnership units(1) 3,003 -
-------------------------------------------------------------------------
Basic weighted average units outstanding 158,980 127,025
Dilutive impact of trust unit incentive rights 109 58
-------------------------------------------------------------------------
Diluted weighted average units outstanding 159,089 127,083
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 varies
by individual and vest at the end of a three year performance period.
Upon vesting the plan participant receives a cash payment based on the
fair value of the PTU combined with the accrued distributions paid on the
notional trust units over the performance period. The fair value of the
PTU is dependent upon the underlying trading price of a trust unit
multiplied by a performance factor that is determined by comparing the
performance of the Fund to its peers over the three year period.
For the three months and nine months ended September 30, 2008 the Fund
recorded cash compensation costs of $1,240,000 (2007 - $509,000) and
$3,540,000 (2007 - $1,424,000), respectively, under the plan which are
included in general and administrative expenses.
At September 30, 2008 there were 419,000 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 September 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 September 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 September 30, 2008 the Fund reported
investments in marketable securities of private companies at cost of
$57,116,000 (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 September 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 September 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$177,627,000 and are
translated to Canadian dollars at the period end exchange rate. At
September 30, 2008 the Canadian dollar amortized cost of the senior notes
was approximately $188,267,000 and the fair value of these notes was
$184,846,000.
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 September 30, 2008 the
Canadian dollar amortized cost of the senior notes was approximately
$57,235,000 and the fair value of these notes was approximately
$52,884,000.
(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 September 30, 2008 a current
deferred financial asset of $14,164,000, a current deferred financial
credit of $22,398,000, a non-current deferred financial asset of
$ 2,040,000 and a non-current deferred financial credit of $74,986,000
are recorded on the consolidated balance sheet.
The deferred financial credit relating to crude oil instruments of
$22,398,000 at September 30, 2008 consists of the fair value of the
financial instruments, representing a loss position of $5,100,000 plus
the related deferred premiums of $17,298,000. The deferred financial
asset relating to natural gas instruments of $13,986,000 at September 30,
2008 represents a gain position of $20,611,000 less the related deferred
premiums of $6,625,000.
The following table summarizes the fair value as at September 30, 2008
and change in fair value for the period ended September 30, 2008 of the
Fund's derivative financial instruments. The fair values indicated below
are determined using observable market data including price quotations in
active markets.
Cross
Currency Foreign
Interest Interest Exchange Electricity
($ thousands) Rate Swaps Rate Swaps Swaps Swaps
-------------------------------------------------------------------------
Deferred financial
(credits)/assets, at
December 31, 2007 $ (226) $ (89,439) $ (425) $ 450
Change in fair value
(credits)/asset (2,488)(3) 17,167(4) 2,465(5) (272)(6)
-------------------------------------------------------------------------
Deferred financial
(credits)/assets,
end of period $ (2,714) $ (72,272) $ 2,040 $ 178
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance sheet
classification:
Current (liability)/
asset $ - $ - $ - $ 178
Non-current
(liability)/asset $ (2,714) $ (72,272) $ 2,040 $ -
-------------------------------------------------------------------------
Commodity Derivative
Instruments
-------------------------
($ thousands) Oil Gas Total
-------------------------------------------------------------
Deferred financial
(credits)/assets, at
December 31, 2007 $(56,783)(1) $ 8,083(2) $(138,340)
Change in fair value
(credits)/asset 34,385(7) 5,903(7) 57,160
-------------------------------------------------------------
Deferred financial
(credits)/assets,
end of period $ (22,398) $ 13,986 $ (81,180)
-------------------------------------------------------------
-------------------------------------------------------------
Balance sheet
classification:
Current (liability)/
asset $ (22,398) $ 13,986 $ (8,234)
Non-current
(liability)/asset $ - $ - $ (72,946)
-------------------------------------------------------------
(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 $13,616) and interest
expense (gain of $3,551).
(5) Recorded in foreign exchange expense.
(6) Recorded in operating expense.
(7) Recorded in commodity derivative instruments (see below).
The following table summarizes the income statement effects of commodity
derivative instruments:
Three months ended Nine months ended
September 30, September 30,
($ thousands) 2008 2007 2008 2007
-------------------------------------------------------------------------
(Gain)/loss due to change
in fair value $ (280,687) $ 3,799 $ (40,288) $ 18,229
Net realized cash
losses/(gain) 60,035 (7,384) 135,030 (14,162)
-------------------------------------------------------------------------
Commodity derivative
instruments (gain)/loss $ (220,652) $ (3,585) $ 94,742 $ 4,067
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 October 28, 2008 are summarized below:
Crude Oil:
WTI US$/bbl
----------------------------------------
Fixed
Daily Price
Volumes Sold Purchased Sold and
bbls/day Call Put Put Swaps
-------------------------------------------------------------------------
Term
October 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(2) 400 - - - $78.53
Swap 1,500 - - - $92.00
Swap(2) 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 500 - $92.00 $79.00 -
Swap 500 - - - $100.05
Put 1400 - $122.00 - -
Put(1) 500 - $116.00 - -
Put(1) 1,000 - $120.00 - -
-------------------------------------------------------------------------
(1) Financial contracts entered into during the third quarter of 2008.
(2) Acquired through the acquisition of Focus.
Natural Gas:
AECO CDN$/Mcf
---------------------------------------------------------
Fixed
Daily Price
Volumes Purchased Sold Purchased Sold and
MMcf/day Call Call Put Put Swaps
-------------------------------------------------------------------------
Term
October 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(2) 14.2 - - - - $6.70
Swap(2) 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 - -
Call(1) 5.7 $9.50 - - - -
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 4.7 - $12.45 $8.97 $7.39 -
Put Spread 4.7 - - $8.97 $7.39 -
Put Spread 4.7 - - $8.97 $7.39 -
Swap 2.8 - - - - $9.42
Swap 2.8 - - - - $9.28
Swap 2.8 - - - - $9.34
Put 4.7 - - $11.34 - -
Put 4.7 - - $11.61 - -
Put(1) 4.7 - - $9.50 - -
April 1, 2009 -
October 31, 2009
Swap 3.8 - - - - $7.86
Put Spread 2.8 - - $9.23 $7.65 -
Put Spread 2.8 - - $9.50 $7.91 -
Put Spread 5.6 - - $9.60 $7.91 -
Put(1) 9.5 - - $8.44 - -
2008 - 2010
Physical
(escalated
pricing) 2.0 - - - - $2.59
-------------------------------------------------------------------------
(1) Financial contracts entered into during the third quarter of 2008.
(2) Acquired through the acquisition of Focus.
The following sensitivities show the impact to after-tax net income of
the respective changes in forward crude oil and natural gas prices as at
September 30, 2008 on the Fund's outstanding commodity derivative
contracts at that time with all other variables held constant:
Increase/(decrease)
to after-tax net income
---------------------------
25% decrease 25% increase
in forward in forward
($ thousands) prices prices
-------------------------------------------------------------------------
Crude oil derivative contracts $ 53,452 $ (57,242)
Natural gas derivative contracts $ 10,135 $ (14,657)
-------------------------------------------------------------------------
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 October 28, 2008 are summarized
below:
Volumes Price
Term MWh CDN$/MWh
-------------------------------------------------------------------------
October 1, 2008 - December 31, 2009 4.0 $ 74.50
October 1, 2008 - December 31, 2010(1) 4.0 $ 77.50
-------------------------------------------------------------------------
(1) Financial contracts entered into during the third 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 of
the respective changes in the period end and applicable forward foreign
exchange rates as at September 30, 2008, with all other variables held
constant:
Increase/(decrease)
to after-tax net income
--------------------------
20% decrease 20% increase
in $CDN in $CDN
relative relative
($ thousands) to $US to $US
-------------------------------------------------------------------------
Translation of US$54 million senior notes $ (8,041) $ 8,041
Translation of US$175 million senior notes (26,452) 26,452
-------------------------------------------------------------------------
Total $ (34,493) $ 34,493
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Increase/(decrease)
to after-tax net income
--------------------------
20% decrease 20% increase
in $CDN in $CDN
relative relative
($ thousands) to $US to $US
-------------------------------------------------------------------------
Foreign exchange swaps $ 8,025 $ (8,025)
Cross currency interest rate swap(1) 25,518 (25,518)
-------------------------------------------------------------------------
Total $ 33,543 $ (33,543)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $120,000,000 of notional debt at
rates varying from 3.70% to 4.61% that mature between June 2011 and July
2013.
If interest rates change by 1%, either lower or higher, on our variable
rate debt outstanding at September 30, 2008 with all other variables held
constant, the Fund's after-tax net income for a quarter would change by
$748,000.
The following sensitivities show the impact to after-tax net income of
the respective changes in the applicable forward interest rates as at
September 30, 2008, with all other variables held constant:
Increase/(decrease)
to after-tax net income
--------------------------
20% decrease 20% increase
forward forward
interest interest
($ thousands) rates rates
-------------------------------------------------------------------------
Interest rate swaps $ (381) $ 381
Cross currency interest rate swap(1) $ 2,028 $ (2,028)
-------------------------------------------------------------------------
(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 September 30, 2008
approximately 85% 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 September 30, 2008 approximately $8,120,000 or 4% 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 September 30, 2008 is
$4,300,000, which includes a $500,000 provision made during the third
quarter. 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 September 30, 2008 the debt to cash flow ratio was 0.4x including the
12 months of trailing cash flow from Focus (September 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. Enerplus' five-year history of debt to cash flow is illustrated
below:
Q3/2008 Q2/2008 Q1/2008 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
Debt-to-Cash
Flow Ratio 0.4x 0.9x 1.0x 0.8x 0.8x 0.8x 1.1x 0.6x
At September 30, 2008 Enerplus had additional borrowing capacity of
$1,122,688,000 under its $1,400,000,000 bank credit facility. The Fund
may have 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 $545,000,000 on
development capital activities. A portion of this capital spending is
considered discretionary. There are limitations to changing the capital
spending plans during a year as 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 additional funds are available to reduce debt, invest in
capital development programs 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. 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 may be 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.
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 during
the quarter. The net proceeds of $502.0 million were used to repay debt,
reinforcing Enerplus' borrowing capacity and enhancing the ability to
fund future capital spending and acquisition activity.
Liability Maturity Analysis
---------------------------
The following tables detail the principal maturity analysis for the
Fund's non-derivative financial liabilities at September 30, 2008:
Payments Due by Period Total
($ thousands) ------------------------------------ Committed
Total 2008 2009 2010 2011 2012 after 2013
-------------------------------------------------------------------------
Accounts
Payable $267,304(1) $267,304 $ - $ - $ - $ - $ -
Distribu-
tions
payable
to unit-
holders 77,643(2) 77,643 - - - - -
Bank credit
facility 277,312 - - 277,312 - - -
Senior
unsecured
notes 325,565(3) - - 53,666 65,113 65,113 141,673
-------------------------------------------------------------------------
Total
commit-
ments $947,824 $344,947 $ - $330,978 $65,113 $65,113 $141,673
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Accounts payable are generally settled between 30 and 90 days from
the balance sheet date.
(2) Distributions payable to unitholders are paid on the 20th day of the
month following the balance sheet date.
(3) Includes the economic impact of derivative instruments directly
related to the senior unsecured notes (CCIRS and foreign exchange
swap).
It is Enerplus' intention to renew the bank credit facilities before or
as they come due. Similarly, Enerplus expects that the senior unsecured
notes will be replaced with replacement notes or bank debt as they become
due. Enerplus cannot currently predict with any certainty the terms or
rates at which such bank credit facilities and senior unsecured notes
will be renewed, but such terms and rates may be less favorable than as
currently exist. Over the long-term, Enerplus expects to balance short-
term credit requirements with bank credit and to look to the term debt
markets for longer-term credit support.
10. Commitments
During the quarter we acquired additional office space which results in
the following total commitments for our office leases:
Minimum Annual Commitment Each Year Total
----------------------------------- Committed
($ thousands) Total 2009 2010 2011 2012 2013 after 2013
-------------------------------------------------------------------------
Office leases $69,493 $8,722 $12,266 $12,316 $12,400 $12,400 $11,389
-------------------------------------------------------------------------
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, a copy of which is
available on Enerplus' SEDAR profile at www.sedar.com, and which also forms
part of Enerplus' Form 40-F for the year ended December 31, 2007 filed with
the SEC, a copy of which is available at www.sec.gov.
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", "guidance",
"objective", "ongoing", "may", "will", "project", "should", "believe",
"plans", "intends" and similar expressions are intended to identify
forward-looking information or statements. In particular, but without limiting
the foregoing, this MD&A contains forward-looking information and statements
pertaining to the following: the amount, timing and tax treatment of cash
distributions to unitholders; payout ratios; tax treatment of income trusts
such as the Fund; the structure of the Fund and its subsidiaries; the Fund's
income taxes, tax liabilities and tax pools; the volume and product mix of the
Fund's oil and gas production; oil and natural gas prices and the Fund's risk
management programs; the amount of asset retirement obligations; future
liquidity and financial capacity and resources; cost and expense estimates;
results from operations and financial ratios; cash flow sensitivities; royalty
rates and their impact on the Fund's operations and results; future growth
including development, exploration, and acquisition and development activities
and related expenditures, including with respect to both our conventional and
oil sands activities.
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 or, where applicable, assumed industry conditions;
availability of debt and/or equity sources to fund the Fund's capital and
operating requirements as needed; the continuance of existing and, in certain
circumstances, proposed tax and royalty regimes; the accuracy of the estimates
of the Fund's reserve volumes; and certain commodity price and other cost
assumptions. The Fund believes the material factors, expectations and
assumptions reflected in the forward-looking information and statements are
reasonable at this time 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;
unanticipated operating results or production declines; changes in tax or
environmental laws or royalty rates; increased debt levels or debt service
requirements; inaccurate estimation of the Fund's oil and gas reserves
volumes; limited, unfavourable or no access to debt or equity capital markets;
increased costs and expenses; the impact of competitors; reliance on industry
partners; and certain other risks detailed from time to time in the Fund's
public disclosure documents including, without limitation, those risks
identified in this MD&A, our MD&A for the year ended December 31, 2007 and in
the Fund's Annual Information Form for the year ended December 31, 2007,
copies of which are available on the Fund's SEDAR profile at www.sedar.com and
which also form part of the Fund's Form 40-F for the year ended December 31,
2007 filed with the SEC, a copy of which is available at www.sec.gov.
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.
This report 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 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 it will be commercially viable to produce any portion of the
contingent resources or 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 report. However, there are a number of
inherent risks and contingencies associated with the development of the
project, including commodity price fluctuations, project costs, receipt of
regulatory approvals and those other risks and contingencies described above
and under "Risk Factors" in the Fund's Annual Information Form dated March 13,
2008, a copy of which is available on Enerplus' SEDAR profile at
www.sedar.com, and which also forms part of Enerplus' Form 40-F for the year
ended December 31, 2007 filed with the SEC, a copy of which is available at
www.sec.gov.
%CIK: 0001126874
Emergency Number
