Enerplus announces 2008 year end results and reserves information
TSX: ERF.UN
NYSE: ERF
CALGARY, Feb. 26 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our financial and operating results for the year ended December
31, 2008. Given the global economic down turn that occurred during the course
of the year, it proved to be a challenging year on many fronts. We were
successful, however, in executing on a number of our key strategic objectives
during 2008. This has resulted in Enerplus being in a relatively strong
financial position in a depressed market, exiting the year with over a billion
dollars of available credit capacity. We believe this affords us a significant
advantage to capitalize on potential acquisition opportunities as we move
forward in 2009.
As previously announced, we have reduced capital spending plans for 2009
relative to 2008 and have also reduced our distributions to unitholders to
preserve our financial strength. Given the current economic environment, we
expect cost structures to improve and are working aggressively to reduce costs
throughout our organization. We will continue to evaluate our currently
planned projects for 2009 relative to both expected reductions in cost
structures and direction of commodity prices.
As we move forward in 2009 we will be looking to increase our ownership
in the resource plays we have targeted for greater, more profitable growth for
2009 and beyond. We expect that the successful execution of our strategies
will be demonstrated over time through improved operational metrics including
improved recycle ratios and improved finding and development costs. Ultimately
our key objective is to enhance the total return to our unitholders.
STRATEGIC EXECUTION:
- During the first half of 2008, Enerplus successfully completed the
acquisition and integration of the assets of Focus Energy Trust, the
single largest transaction in our history valued at $1.7 billion.
- We sold our 15% interest in the Joslyn oil sands lease for $502
million. These proceeds were used to reduce our outstanding bank
debt.
- We continued to advance on our Kirby oil sands project with the
filing of our regulatory application for Phase I in late September.
We also increased the contingent resource estimate by 70% to over 400
million barrels of bitumen.
- Crude oil and natural gas prices declined dramatically in the fourth
quarter of 2008 as the global economic environment deteriorated. In
response, we have reduced our 2009 capital spending plans and
distributions to unitholders. We believe these actions will preserve
our balance sheet strength and position us to take advantage of
potential acquisition opportunities.
STRATEGIC POSITIONING FOR THE FUTURE:
- We believe that Enerplus currently has one of the strongest balance
sheets in the oil and gas sector. With over $1 billion of unused
credit capacity we believe this is a tremendous competitive
advantage in the current economic environment.
- Enerplus has a proven track record of completing strategic
transactions that improve our business. We are focused on acquiring
high quality assets in growth areas such as tight gas and tight oil
through acquisitions in priority investing development capital in
our existing asset base. We are also directing 25% of our 2009
capital program toward growth projects in these areas to provide
even greater value growth opportunities in the future.
- We are focused on preserving our financial flexibility. By reducing
both our capital spending and distributions relative to our cash
flows, we are positioning to minimize any increases in our debt
except as may be necessary in our acquisition strategies.
- As we enter 2009, our emphasis is on production optimization and
cost reductions to improve capital efficiencies and performance. We
have a meaningful inventory of natural gas and oil projects, but in
the current commodity price environment, we will look to retain our
drilling inventory until such time as prices and cost structures
improve.
- We are also undertaking a review of our asset base to identify those
conventional properties which do not fit into our longer-term
strategic plan of growing our resource play asset base. It is part
of our strategy to rationalize these non-core assets at the
appropriate time.
- We believe that our asset base is well suited to an income-oriented
business model and believe that there will continue to be a growing
demand for yield-oriented investments. We continue to evaluate
alternatives to our income trust structure with the expectation that
we will most likely convert to a dividend paying corporation. With
the current forward commodity price and our plans regarding
production, costs and capital spending, we do not expect a
significant change to our overall tax costs until 2013 even if we
were to convert to a corporation during 2010.
FINANCIAL HIGHLIGHTS:
- Cash flow from operating activities totaled $1,263 million in 2008,
an increase of 45% over 2007 levels.
- Cash distributions to unitholders totaled $5.06 per trust unit
essentially unchanged from the amount paid in 2007, resulting in a
payout ratio of 62% versus 74% in 2007.
- Distributions and development capital spending totaled 109% of cash
flow, compared to 120% in 2007.
- We maintained a strong balance sheet with a net debt to trailing 12
month cash flow ratio of 0.5x.
OPERATIONAL HIGHLIGHTS:
- Production averaged 95,687 BOE/day in 2008, in-line with our third
quarter guidance of 96,000 BOE/day.
- Average December production volumes were 96,400 BOE/day (98,000
BOE/day after adjusting for unexpected downtime at two non-operated
facilities, both of which were resolved by year-end). The adjusted
exit rate was only slightly behind our exit rate guidance of 98,500
BOE/day.
- Development capital spending was $578 million, 6% higher than our
guidance of $545 million principally as a result of accelerating
capital spending on certain projects.
- We drilled a record 643 net wells with a 99% success rate.
- General and Administrative ("G&A") expenses were $1.88/BOE, 6% lower
than our guidance of $2.00/BOE and 17% lower than $2.26/BOE in 2007.
- Operating costs were $9.50/BOE for 2008, in-line with our guidance
but representing an increase of 4% year-over-year.
- We invested $106 million to pursue our resource-play growth strategy
including $55 million on exploration drilling, land and seismic, and
$51 million on oil sands.
- We continued to focus on the health and safety of our workers and
recorded better performance than the Canadian Association of
Petroleum Producers' industry average.
RESERVES:
- We replaced 78% of 2008 production through reserve additions from
development capital spending and net acquisitions on a proved plus
probable basis.
- Proved reserves increased 10% to 319 MMBOE, while probable reserves
decreased 24% to 114 MMBOE primarily due to the sale of the Joslyn
oil sands interest. Our total proved plus probable reserves decreased
by 2% to 432.4 MMBOE.
- Proved plus probable finding, development and acquisition costs
("FD&A") on our conventional oil and gas activities were $29.17/BOE
for the year including future development capital.
- Our conventional recycle ratio for 2008 was 1.4x.
- Our Reserve Life Index ("RLI") continues to be one of the longest in
the sector at 12.1 years on a proved plus probable basis and 9.4
years on a proved basis.
SELECTED FINANCIAL AND OPERATING HIGHLIGHTS
Readers are referred to "Information Regarding Disclosure in this News
Release and Oil and Gas Reserves, Resources and Operational Information",
"Notice to U.S. Readers" and "Forward-Looking Information and Statements" at
the end of this news release for information regarding the presentation of the
financial, reserves, resources and operational information in this news
release and information regarding the inclusion of certain forward-looking
information and statements in this news release. For information on the use of
the term "BOE" see "Information Regarding Disclosure in this News Release and
Oil and Gas Reserves, Resources and Operational Information" at the conclusion
of this news release.
SELECTED FINANCIAL RESULTS
Three months ended Twelve months ended
December 31, December 31,
(in Canadian dollars) 2008 2007 2008 2007
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Financial (000's)
Cash Flow from
Operating Activities $ 258,536 $ 205,084 $ 1,262,782 $ 868,548
Cash Distributions
to Unitholders(1) 167,017 163,447 786,138 646,835
Cash Withheld for
Acquisitions and
Capital Expenditures 91,519 41,637 476,644 221,713
Net Income 189,495 98,701 888,892 339,691
Debt Outstanding
(net of cash) 657,421 724,975 657,421 724,975
Development Capital
Spending 200,254 106,120 577,739 387,165
Acquisitions 1,443 5,095 1,772,826 274,244
Divestments 162 4,003 504,859 9,572
Actual Cash
Distributions
to Unitholders
per Trust Unit $ 1.23 $ 1.26 $ 5.06 $ 5.04
Financial per
Weighted Average
Trust Unit(2)
Cash Flow from
Operating
Activities $ 1.56 $ 1.58 $ 7.86 $ 6.80
Cash Withheld for
Acquisitions and
Capital
Expenditures 0.55 0.32 2.97 1.74
Net Income 1.15 0.76 5.54 2.66
Payout Ratio(3) 65% 80% 62% 74%
Selected Financial
Results per BOE(4)
Oil & Gas Sales(5) $ 46.54 $ 52.33 $ 65.79 $ 50.48
Royalties (8.61) (9.83) (12.27) (9.49)
Commodity Derivative
Instruments 3.54 (0.08) (2.94) 0.45
Operating Costs (9.46) (8.53) (9.51) (9.11)
General and
Administrative (1.71) (1.94) (1.68) (1.98)
Interest and Other
Income and
Foreign Exchange (2.73) (1.70) (1.59) (1.43)
Taxes 0.92 (1.70) (0.65) (0.77)
Asset retirement
obligations settled (0.53) (0.75) (0.52) (0.54)
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Cash Flow from
Operating
Activities before
changes in
non-cash working
capital $ 27.96 $ 27.80 $ 36.63 $ 27.61
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Weighted Average
Number of
Trust Units
Outstanding
Including
Equivalent
Exchangeable
Limited
Partnership
Units (thousands) 165,373 129,658 160,589 127,691
Debt/Trailing
12 Month Cash
Flow Ratio(6) 0.5x 0.8x 0.5x 0.8x
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SELECTED OPERATING RESULTS
Three months ended Twelve months ended
December 31, December 31,
2008 2007 2008 2007
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Average Daily
Production
Natural gas (Mcf/day) 346,439 257,415 338,869 262,254
Crude oil (bbls/day) 35,434 34,221 34,581 34,506
NGLs (bbls/day) 4,529 3,836 4,627 4,104
Total (BOE/day) 97,702 80,959 95,687 82,319
% Natural gas 59% 53% 59% 53%
Average Selling
Price(5)
Natural gas (per Mcf) $ 6.92 $ 5.91 $ 8.17 $ 6.45
Crude oil (per bbl) 55.16 72.21 91.31 65.11
NGLs (per bbl) 43.55 58.12 68.93 51.35
CDN$/US$ exchange
rate 0.82 1.02 0.94 0.93
Net Wells drilled 174 76 643 252
Success Rate(7) 99% 100% 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 during 2008.
(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 for
2008.
(7) Based on wells drilled and cased.
Trust Unit Trading Summary
For the twelve months ended TSX - ERF.un NYSE - ERF
December 31, 2008 (CDN$) (US$)
-------------------------------------------------------------------------
High $ 49.85 $ 50.63
Low $ 21.53 $ 17.07
Close $ 23.96 $ 19.58
2008 Cash Distributions
Per Trust Unit
Payment Month CDN$ US$
-------------------------------------------------------------------------
First Quarter Total $ 1.26 $ 1.23
Second Quarter Total $ 1.26 $ 1.25
Third Quarter Total $ 1.31 $ 1.26
October $ 0.47 $ 0.39
November 0.38 0.29
December 0.38 0.31
Fourth Quarter Total $ 1.23 $ 0.99
Total Year-to-Date $ 5.06 $ 4.73
OPERATIONS
2008 was a very active year for Enerplus as we closed and integrated the
single largest acquisition in our history and executed our largest capital
development program to date. Our activities essentially delivered our
production targets for annual average volumes, exit rate volumes, operating
costs and G&A costs. However, we were disappointed with our capital
efficiencies and our reserve additions were impacted by negative revisions.
Production
Daily production for 2008 averaged 95,687 BOE/day representing a new
record and in-line with our guidance of 96,000 BOE/day. Our average daily
volumes were approximately 16% higher than 2007 as a result of the Focus
Energy Trust ("Focus") acquisition which closed on February 13, 2008 and added
approximately 18,000 BOE/day of annualized production.
We exited 2008 with production volumes of approximately 96,400 BOE/day,
roughly 2% lower than our guidance of 98,500 BOE/day due to unexpected
downtime at two non-operated facilities. Approximately 1,100 BOE/day was shut
in at our Tommy Lakes property during December due to a labour strike at a
processing facility and we lost approximately 500 BOE/day due to unplanned
downtime at our Bantry facility. Both the strike and the Bantry turnaround
were resolved by year-end. After adjusting for these events, our exit rate was
approximately 98,000 BOE/day.
Development Activities
Our capital spending program during 2008 totaled $578 million,
approximately $33 million above our third quarter guidance of $545 million. We
spent an additional $22 million due to accelerated activity associated with
good weather conditions and rig availability at Tommy Lakes, Bantry and
Shackleton as well as an accelerated seismic program at our Kirby oil sands
project. An additional $11 million was incurred due to higher than expected
service and drilling costs and higher maintenance costs on various properties.
This additional spending is not expected to have a material impact on our 2009
guidance.
Our conventional capital development program in 2008 was equally weighted
to both oil and natural gas projects across our portfolio. In total, we
drilled 643 net wells with a 99% success rate and brought on approximately
19,500 BOE/day of initial production at an average on-stream cost of
$27,000/BOE/day, excluding oil sands spending. Approximately 80% of the
capital was spent in our five core resource plays with a majority of the
drilling activity targeted to shallow gas (520 wells). We increased our
drilling activity in our tight gas resource plays and shifted our U.S. Bakken
activity from drilling wells to completing refracs on existing wells. Overall
our capital efficiencies decreased from 2007 due to lower performance,
continued cost escalation which only began to moderate in the latter half of
the year and a higher percentage of infrastructure spending.
We continued to invest in growth projects during 2008 as approximately
18% (or $106 million) of our capital program was invested in these activities
including oil sands. This growth spending does not typically add production,
reserves or cash flow in the near term as we are investing in land, seismic
and exploration activities that help capture new opportunities for the future.
We are encouraged by the progress we are making on a number of new growth
plays which are in the early stages. We expect this type of spending to grow
as a percentage of our capital spending plans going forward.
In 2008 we invested $55 million in exploration drilling and new land and
seismic primarily in the Montney regions of Alberta and British Columbia and
the Bakken region of southeast Saskatchewan. Spending on our oil sands assets
increased from $39 million in 2007 to $51 million in 2008.
2008 Production and Capital
Average Drilling
Daily Activity Initial Capital Capital
Production (Net Production Spending Efficiency
Play Types (BOE/day) Wells) (BOE/day) ($MM) ($/BOE/day)
-------------------------------------------------------------------------
Shallow Gas
& Coalbed
Methane 23,666 520 5,660 $ 159 $ 28,100
Crude Oil
Waterfloods 16,282 40 3,000 84 28,000
Tight Gas 15,070 20 5,100 81 15,900
Bakken/Tight Oil 10,831 11 3,200 99 30,940
Other
Conventional
Oil & Gas 29,838 52 2,500 104 41,600
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Total
Conventional 95,687 643 19,460 $ 527 $ 27,100
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-------------------------------------------------------------------------
Oil Sands 0 n/a n/a 51 n/a
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Total Company 95,687 643 19,460 $ 578 $ 29,700
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Resource Plays
Shallow Natural Gas and CBM
---------------------------
Shallow natural gas and coal bed methane ("CBM") represented 25% of our
average daily production volumes in 2008, an increase of 61% over 2007,
reflecting the additional working interests acquired in the Shackleton field
from Focus. Given the inventory of higher quality locations from the Focus
acquisition and strong natural gas prices for most of the year, we invested
$159 million, drilling 520 net shallow gas wells in 2008 with most of our
spending at Shackleton in Saskatchewan and Bantry, Verger and Medicine Hat in
Alberta.
Our capital efficiency of $28,100/BOE/day was higher than in 2007 due to
the early start of our 2009 program to ensure we have our wells tied in before
break-up and increased infrastructure costs associated with pipeline repairs
and compressor upgrades.
With softening natural gas prices, our projected spending levels for 2009
have been reduced to approximately $75 million. We plan to drill approximately
226 net wells and will continue to focus on infill drilling at Shackleton,
Bantry and Verger where our most attractive opportunities exist. We anticipate
that over 80% of our total conventional wells in 2009 will be shallow gas
wells targeting the Milk River and Medicine Hat formations.
Crude Oil Waterfloods
---------------------
Crude oil waterfloods represented approximately 17% of our 2008 average
daily production from about 12 major properties located across the Western
Canadian Sedimentary Basin. We operate over 80% of our waterfloods and
invested $84 million in this resource play in 2008. Capital spending was
largely focused at Giltedge, Pembina, Virden and Silver Heights where we
drilled 40 net wells. Capital efficiency in this resource play was impacted by
the ongoing maintenance costs associated with these properties as a percentage
of total capital and a higher percentage of investment in infrastructure
projects to upgrade facilities which will support longer-term development. Our
capital efficiency of $28,000/BOE/day was better than the average efficiency
for this resource play in 2006 and 2007.
We expect to decrease our 2009 capital spending significantly in our
waterflood assets to approximately $45 million due to the marginal economics
of crude oil projects at current price levels. However we plan to continue
identifying development prospects in our most attractive plays to be well
positioned to restart these programs when oil prices rebound and/or cost
structures improve. The current allocated funds will be used for ongoing
production optimization projects which have the most attractive economics as
well as the completion and tie in of wells that were drilled in the fourth
quarter of 2008. Due to the ongoing maintenance requirements and lower level
of capital investment, capital efficiencies in this area are not expected to
improve in 2009.
Tight Gas
---------
Our tight gas resource play is a growing component of our asset base and
almost doubled in size from 2007 mainly due to the acquisition of the Tommy
Lakes property in British Columbia. This play now represents 15% of our total
corporate production. We more than doubled our capital spending in 2008 to $81
million and increased the number of net wells drilled from 6 to 20
year-over-year. Approximately 40% of our capital was spent at Tommy Lakes to
complete and tie-in 17 wells in early 2008. Due to favourable weather
conditions, we were able to accelerate our 2009 capital spending in this area
with approximately $14 million spent in 2008 for our 2008/09 winter program.
The remaining investment in this resource play in 2008 was primarily at our
Ansell and Elmworth properties in Alberta.
Our 2008 capital efficiency of $15,900/BOE/day benefited from capital
spent by Focus during the 2007/2008 winter drilling program prior to our
acquisition in February. Going forward, advances in our use of horizontal and
completion technologies and/or deflationary pressures may improve our results.
Our spending levels for 2009 are expected to remain relatively constant
compared to 2008 at $78 million. Our plans include ongoing development at
Tommy Lakes with a 14 well program including a few step-out wells aimed at
expanding the play and the piloting of a horizontal well. We also expect to
continue to add to our tight gas land positions in other areas and begin
delineating the new lands purchased in 2008.
Bakken/Tight Oil
----------------
Our Bakken/tight oil resource play represented roughly 11% of our 2008
average daily production, with virtually all of this production coming from
the Sleeping Giant project in Montana. In 2008, we continued to invest in this
project, spending approximately $70 million. We also expanded our Bakken
interests with the purchase of approximately 30,000 acres of undeveloped land
in southeast Saskatchewan. In total we invested $99 million in this resource
play in 2008.
We continued our third well per section development drilling program at
Sleeping Giant in 2008 and drilled 11 net wells and refrac'd 16 net wells.
Capital efficiencies in the U.S. during 2008 were $21,500/BOE/day. When we
include the purchase of Bakken lands in Canada, our capital efficiency
declined to $30,940/BOE/day. In 2008 we also initiated a full optimization
program and tested a variety of techniques to improve production. These
efforts added approximately $8 million to our operating costs which also
resulted in approximately 600 BOE/day of increased production. We expect to
reduce our optimization activities in 2009 and should see an improvement in
operating costs as the year progresses.
In 2009, we have allocated $42 million to Bakken/tight oil the majority
of which will be invested at Sleeping Giant. We plan on concentrating our
spending on refracs (24 planned) and modest drilling subject to commodity
price and/or cost improvements. There are approximately 15 third well per
section drilling locations, approximately 40 fourth well per section locations
and 120 refrac wells remaining in our inventory at Sleeping Giant. We are also
participating in a CO2 pilot project on an existing Enerplus producing well
with two other industry partners. Injection commenced in January 2009 and we
expect to be able to provide an update on these activities later in the year.
Outside of Sleeping Giant, we are also pursuing investments in other tight oil
resource plays in both the U.S. and Canada.
Other Conventional Oil & Gas
----------------------------
Other conventional oil and gas properties comprised approximately 32% of
our average daily production and 18% of capital spending in 2008. This
includes a diversified portfolio of both crude oil and natural gas projects
across western Canada of which we operate approximately 55% of the production
and 70% of the capital spending. Capital investment on these assets was
slightly lower year-over-year at $104 million but was reduced from 33% to 20%
of our conventional spending as we continued to focus on our core resource
plays in 2008.
Our 2008 capital efficiency was negatively impacted by lower than
expected performance at Colgate, Shorncliff, Sylvan Lake and a number of
non-operated properties as well as higher infrastructure investment. As well,
the timing of capital spending late in 2008 has increased capital efficiencies
as the associated production will not come on stream until 2009. As a result,
capital efficiencies averaged $41,600/BOE/day.
As we continue to concentrate our capital spending in our core resource
play areas, coupled with the decrease in commodity prices, we expect that in
2009 our investment in this category will decrease significantly to
approximately $35 million, representing a reduction of 66% year-over-year. We
will monitor economic conditions throughout the year and will be prepared to
adjust our allocation of capital among the various play types as required.
Oil Sands
---------
We invested $51 million in our oil sands portfolio in 2008, $41 million
of which was spent on our Kirby SAGD project. Approximately $10 million was
spent on the Joslyn project prior to the sale of this asset in July.
Kirby
Kirby is located in the heart of the Athabasca fairway close to other
major SAGD projects currently on production and extends over 43,360 gross
acres (67 sections of land) in a highly prospective area where we see a number
of potential oil sands pay zones. Enerplus holds a 100% working interest in
the property. The current plan would see the property developed in phases,
with Phase 1 having production capacity of 10,000 bbls/day of bitumen and
Phase 2 having an incremental production capacity of 20,000 - 30,000 bbls/day.
In 2008 we completed our first winter delineation drilling program at the
Kirby project with great success. A total of 58 delineation wells were drilled
including two source water wells and a water disposal well. The results of
this program were significant in that our independent reserves engineers
reported an increase of 170 million barrels to our contingent resource
estimate, an increase of 70% over the 244 million barrels estimated at the
time of purchase. We also confirmed that we have an adequate source of saline
water (non-potable water) for the Kirby Phase 1 project and that we have a
deep reservoir zone capable of handling our disposal water for the life of the
project.
Set forth below is the "best estimate" of contingent resources
attributable to our Kirby lease as at December 31, 2008 provided by GLJ
Petroleum Consultants Ltd., independent petroleum engineers.
Northern Area Wabiskaw D (Project area) 118 million barrels
Northern Area McMurray 191 million barrels
Central and Southern Areas 105 million barrels
-------------------
Total Kirby Contingent Resource Estimate 414 million barrels
-------------------
-------------------
For additional information relating to contingent resource estimates, see
"Information Regarding Disclosure in this News Release and Oil and Gas
Reserves, Resources and Operational Information" at the conclusion of this
news release. As well, for additional information regarding our Kirby Oil
Sands project, see our Annual Information Form for the year ended December 31,
2008, a copy of which will be available on or about March 16th, 2009 on our
SEDAR profile at www.sedar.com and which will also form part of our Form 40-F
for the year ended December 31, 2008 to be filed with the SEC, a copy of which
will be available at www.sec.gov.
With our experienced team and a successful winter drilling program, we
were able to prepare and submit the development application for Phase 1 to the
regulatory authorities in September.
Despite the advancements made at Kirby, our 2009 capital program has been
reduced significantly due to the fall in crude oil prices. We will be working
with regulators and our stakeholders in an effort to obtain regulatory
approval by late 2009. Once we have regulatory approval, our Board of
Directors will determine whether to sanction proceeding with the project at
that time. Given the downturn in commodity prices, we have elected to defer
any additional delineation activity this year, but plan to complete a three
dimensional seismic program over 20 sections of our northern lease area. This
will position us for future delineation drilling should we move forward with
Phase 2 of Kirby. We also plan to complete a more detailed geological review
of all potential oil sands zones in our lease which we believe should result
in additional contingent resources being identified.
2009 PRODUCTION AND CAPITAL SPENDING PLANS
As previously announced in December 2008, Enerplus is planning a
conservative approach to 2009 with reductions in capital spending and
distributions in light of current commodity prices and capital market
uncertainty. We intend to preserve our financial strength and maintain
flexibility so that we are in a position to take advantage of opportunities to
add quality assets in what we expect will prove to be an attractive
acquisition market.
As a result of reduced capital spending, we anticipate that our annual
daily production volumes will average 91,000 BOE/day in 2009, a decline of
approximately 5% from 2008. We expect to exit 2009 with production of
approximately 88,000 BOE/day.
We currently plan to spend $300 million, a decrease of 48% from our 2008
development capital spending levels. Our plans include $240 million of
spending on our Canadian conventional assets, $35 million in the U.S. and $25
million on oil sands. Our program is directed toward high value optimization
and development projects, maintaining the integrity of our existing
infrastructure and investment in new development areas given our desire to add
opportunities in emerging resource plays.
Approximately 56% of our conventional spending will be directed at
natural gas resource plays with the remainder on oil. Our natural gas program
will be concentrated on shallow gas and tight gas projects which provide an
attractive return with natural gas prices at or better than $5.00/Mcf. Our oil
program is directed primarily at our U.S. Bakken assets and optimization
projects with attractive returns with oil prices at or better than
US$40.00/bbl. Included in our plans is approximately $50 million of spending
on growth-oriented projects in the Montney gas play in northeastern B.C. and
northwestern Alberta, the Bakken oil play in the Williston Basin and a few
other select resource plays. We anticipate drilling several pilot wells to
test reservoir quality and productivity and accumulate additional prospective
lands in key areas. We will also continue to look for acquisition and joint
venture opportunities as a way to advance and accelerate our growth in
resource plays that target tight gas and tight oil.
This capital spending forecast also includes an estimate of cost savings
that we are expecting as a result of the slowdown in industry activity and
does not reflect any acquisition or divestment activity that may occur as a
normal part of our business. We will review our 2009 capital program and
distributions on an on-going basis throughout the year in the context of
prevailing economic conditions and make adjustments as deemed necessary. In
addition, there is a risk that certain wells could become uneconomic to
produce if current market conditions fail to improve thereby impacting our
production volumes. We expect that up to one third of our capital spending
will occur in the first quarter of 2009 as a result of winter access areas and
the continuation of our ongoing program from 2008.
2009 2009 2009
Estimated Estimated Estimated
Average Drilling Capital
Daily Production Activity Spending
Play Types (BOE/day) (Net Wells) ($MM)
-------------------------------------------------------------------------
Shallow Gas & CBM 22,700 226 $ 75
Crude Oil
Waterfloods 16,200 12 45
Tight Gas 14,100 24 78
Bakken/Tight Oil 9,900 4 42
Other Conventional
Oil & Gas 28,100 9 35
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Total Conventional 91,000 275 $ 275
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Oil Sands 0 0 25
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Total Company 91,000 275 $ 300
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ACQUISITIONS & DIVESTMENTS
In 2008 we leveraged our strategic and execution capabilities to execute
two of the most significant transactions in our history. On February 13, 2008
Enerplus acquired Focus Energy Trust for $1.7 billion through an exchange of
trust units and the assumption of debt adding approximately 84 MMBOE of proved
plus probable conventional oil and natural gas reserves and approximately
20,000 BOE/day of production (18,000 BOE/day annualized from the closing date
of February 13, 2008), of which approximately 90% was natural gas. On July 31,
2008, we completed the sale of our 15% working interest in the Joslyn oil
sands lease for net cash proceeds of approximately $502 million. We sold 63.5
million barrels of proved plus probable reserves at a cost of $14.36 per
barrel including future development capital.
We believe that weak commodity prices and the current downturn in the
economy will create acquisition opportunities. Given our financial strength,
we believe we are in an excellent position to capitalize on these
opportunities to add high quality, growth-oriented assets that will improve
our overall portfolio.
2008 Acquisition & Divestment Summary
Cost of
Proved Proved
plus plus Cost per
Cost/ Probable Estimated Probable Daily
Conventional Proceeds Reserves Production Reserves Barrel
Oil & Gas ($MM) (MBOE) (BOE/day) ($/BOE) ($/BOE/day)
-------------------------------------------------------------------------
Acquisitions,
net of
divestments(*) $1,770.0 84,237 20,668 $ 21.01 $ 85,640
-------------------------------------------------------------------------
Oil Sands
Divest-
ments(xx) $ 502.0 63,498 - $ 14.36 -
-------------------------------------------------------------------------
(*) After adjustment for working capital and excluding future
development capital.
(xx) Including future development capital
RESERVES
Enerplus replaced approximately 78% of our produced reserves in 2008,
essentially keeping our total proved plus probable reserves consistent
year-over-year. Through the Focus acquisition and our development activities,
we added over 90 MMBOE of proved plus probable reserves however the sale of
Joslyn and our production more than offset these additions. Our proved
reserves as a percent of total reserves increased by 8% (from 66% at December
31, 2007 to 74% in 2008) given the higher percentage of proved reserves
attributable to the Focus assets whereas the majority of the reserves
associated with the Joslyn lease were in the probable category.
Overall the results from our development program were disappointing as
fewer reserves were added than expected and we experienced negative revisions
and increased capital costs in some areas. These revisions negatively impacted
our finding and development costs ("F&D") as well as our finding, development
and acquisition costs ("FD&A"). Our conventional FD&A costs per BOE including
future development capital ("FDC") were $29.17 with a recycle ratio of 1.4x
driven primarily by the Focus acquisition (see "Recycle Ratio" below for
additional information on this metric). Our total finding and development
costs on our oil sands assets including FDC were $13.71 per BOE reflecting the
impact of the Joslyn sale and the spending on oil sands which added contingent
resources but do not at this stage of development qualify as reserves.
The following information highlights some of our key reserve findings
- We added approximately 20 MMBOE of proved plus probable reserves
through our conventional development program including:
- 3.4 MMBOE of proved plus probable reserves added as a result
of price forecast revisions by our external independent
reserve evaluators as higher long-term prices extended the
life and expected reserves in some areas even though the near-
term price outlook was lower than in 2007.
- 6 MMBOE of proved plus probable reserves were added on the
Focus assets, primarily at Shackleton and other minor
properties.
- We added 3 MMBOE of proved plus probable reserves at Sleeping
Giant. Since acquiring this property in 2005, reserves have
increased by 48% through the addition of 17.4 MMBOE of proved
plus probable reserves including the replacement of 13.3 MMBOE
of produced reserves.
- We experienced negative reserve revisions of 13.6 MMBOE;
- 5.6 MMBOE of which were due to performance issues associated
with our Verger, Hanna Garden and Medicine Hat South shallow
gas properties as well as with our Mitsue non-operated oil
property.
- Approximately 5.0 MMBOE of reserves were eliminated from our
least attractive shallow gas undeveloped locations, the
majority of which were at our Medicine Hat North and Verger
shallow gas properties. Lower than expected results combined
with a reduced capital budget have resulted in a reduction in
future spending plans on these properties. Given the current
commodity price environment, we are directing our shallow gas
spending to other areas that have higher economic returns.
- 2.5 million BOE of reserves were eliminated at our Mount
Benjamin property as the operator is not planning on drilling
in the current commodity price environment.
- Approximately $144 million of future development capital was added to
our reserve report to reflect higher costs. Close to half of this
amount was associated with increased development costs relating to
the Shackleton property. We also experienced an increase in
maintenance capital associated with our Mitsue property.
- Given the sale of Joslyn, our Reserve life index and our percentage
of reserves tied to resource plays fell to 12.1 years and 74%
respectively. We believe that our RLI remains one of the longest in
our sector and we expect to continue to increase our percentage of
resource oriented reserves through our acquisitions and divestments.
Proved
Proved plus
Proved Developed Proved Proved Probable
Developed Non- Undeve- Plus Reserve
Producing Producing loped Proved Probable Probable Life
Reserves Reserves Reserves Reserves Reserves Reserves Index
Play Types (MMBOE) (MMBOE) (MMBOE) (MMBOE) (MMBOE) (MMBOE) (years)
-------------------------------------------------------------------------
Crude Oil
Waterfloods 67.1 0.0 6.9 74.0 21.7 95.7 16.2
Shallow
Gas & CBM 62.4 0.3 23.7 86.4 35.6 122.0 12.6
Tight Gas 35.7 2.0 6.7 44.4 17.0 61.4 10.5
Bakken/
Tight Oil 27.3 1.4 2.1 30.8 9.8 40.6 11.0
Other
Conventional
Oil & Gas 74.3 0.9 7.7 82.9 29.8 112.7 10.6
-------------------------------------------------------------------------
Total
Company 266.8 4.6 47.1 318.5 113.9 432.4 12.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Amounts shown in table may not add due to rounding.
Reserve Reporting and Determination Methodologies
All of our reserves, including our U.S. reserves, were evaluated using
Canadian National Instrument 51-101 ("NI 51-101") standards. Two external,
independent third party engineering firms were used to evaluate and review our
reserves this year. Sproule Associates Limited, our historical independent
engineering evaluators, evaluated our Canadian conventional reserves.
Netherland, Sewell & Associates, Inc. ("NSA") of Dallas, Texas evaluated the
reserves attributed to our assets in the United States. Sproule evaluated
93% of the total proved plus probable value (discounted at 10%) of our
Canadian conventional year-end reserves and audited the remaining 7% of the
reserves which were internally evaluated by Enerplus. NSA evaluated 100% of
the reserves in the U.S. and utilized Sproule's forecast price and cost
assumptions as of December 31, 2008 in their evaluations to maintain
consistency among our reserve reporting. In addition to Sproule and NSA, GLJ
Petroleum Consultants Ltd. evaluated the resources on our Kirby oil sands
project as described above.
For information regarding the presentation of our oil and gas reserves,
please see "Information Regarding Disclosure in this News Release and Oil and
Gas Reserves, Resources and Operational Information" and "Notice to U.S.
Investors" at the conclusion of this news release.
Reserves Summary
The following table sets out our company interest volumes by production
type and reserve category under a forecast price scenario. Under different
price scenarios, these reserves could vary as a change in price can affect the
economic limit and reserves associated with a property.
2008 Reserve Summary - Company Interest Volumes (Forecast Prices)
OIL AND GAS NATURAL RESERVES
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
Oil Oil Bitumen Oil Liquids Gas Total
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
developed
producing
Canada 64,043 26,979 - 91,022 11,416 813,021 237,942
United
States 23,159 - - 23,159 80 33,928 28,894
-------------------------------------------------------------------------
Total 87,202 26,979 - 114,181 11,496 846,949 266,836
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved
developed
non-producing
Canada 243 - - 243 360 15,355 3,162
United
States 1,216 - - 1,216 4 1,532 1,475
-------------------------------------------------------------------------
Total 1,459 - - 1,459 364 16,887 4,637
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved
undeveloped
Canada 4,139 6,160 - 10,299 1,163 197,490 44,377
United
States 1,753 - - 1,753 29 5,208 2,650
-------------------------------------------------------------------------
Total 5,892 6,160 - 12,052 1,192 202,698 47,027
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total
Proved
Canada 68,425 33,139 - 101,564 12,939 1,025,866 285,481
United
States 26,128 - - 26,128 113 40,668 33,019
-------------------------------------------------------------------------
Total 94,553 33,139 - 127,692 13,052 1,066,534 318,500
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable
Canada 19,274 12,790 - 32,064 4,714 397,651 103,053
United
States 6,867 - - 6,867 51 23,483 10,832
-------------------------------------------------------------------------
Total 26,141 12,790 - 38,931 4,765 421,134 113,885
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total
Proved
plus
Probable
Canada 87,699 45,929 - 133,628 17,653 1,423,517 388,534
United
States 32,995 - - 32,995 164 64,151 43,851
-------------------------------------------------------------------------
Total 120,694 45,929 - 166,623 17,817 1,487,668 432,385
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reserve Reconciliation
The following tables outline the changes in Enerplus' proved, probable and
proved plus probable reserves, on a company interest basis, from December 31,
2007 to December 31, 2008.
Proved Reserves
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
Oil Oil Bitumen Oil Liquids Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2007 67,386 31,215 8,568 107,169 11,673 829,122 257,029
-------------------------------------------------------------------------
Acquisitions 3,585 - - 3,585 2,714 337,623 62,570
Divestments - - (8,568) (8,568) - - (8,568)
Discoveries 114 - - 114 6 635 226
Extensions &
Improved
Recovery 2,922 1,899 - 4,821 331 24,953 9,311
Economic
Factors 604 200 - 804 94 7,961 2,225
Technical
Revisions 1 2,879 - 2,880 (186) (55,062) (6,484)
Production (6,187) (3,054) - (9,241) (1,693) (119,366) (30,828)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2008 68,425 33,139 - 101,564 12,939 1,025,866 285,481
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
UNITED Oil Oil Bitumen Oil Liquids Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2007 26,637 - - 26,637 112 36,955 32,908
-------------------------------------------------------------------------
Acquisitions - - - - - - -
Divestments - - - - - - -
Discoveries - - - - - - -
Extensions &
Improved
Recovery 2,429 - - 2,429 16 3,940 3,102
Economic
Factors - - - - - - -
Technical
Revisions 465 - - 465 (2) 4,433 1,202
Production (3,403) - - (3,403) (13) (4,660) (4,193)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2008 26,128 - - 26,128 113 40,668 33,019
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
TOTAL Oil Oil Bitumen Oil Liquids Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2007 94,023 31,215 8,568 133,806 11,785 866,077 289,937
-------------------------------------------------------------------------
Acquisitions 3,585 - - 3,585 2,714 337,623 62,570
Divestments - - (8,568) (8,568) - - (8,568)
Discoveries 114 - - 114 6 635 226
Extensions &
Improved
Recovery 5,351 1,899 - 7,250 347 28,893 12,413
Economic
Factors 604 200 - 804 94 7,961 2,225
Technical
Revisions 466 2,879 - 3,345 (188) (50,629) (5,282)
Production (9,590) (3,054) - (12,644) (1,706) (124,026) (35,021)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2008 94,553 33,139 - 127,692 13,052 1,066,534 318,500
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable Reserves
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
Oil Oil Bitumen Oil Liquids Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Probable
Reserves
at Dec. 31,
2007 17,837 10,948 54,930 83,715 3,797 308,276 138,891
-------------------------------------------------------------------------
Acquisitions 944 - - 944 831 119,352 21,667
Divestments - - (54,930)(54,930) - - (54,930)
Discoveries 37 - - 37 1 212 73
Extensions &
Improved
Recovery 1,072 486 - 1,558 168 7,976 3,055
Economic
Factors 303 171 - 474 32 4,070 1,184
Technical
Revisions (919) 1,185 - 266 (115) (42,235) (6,887)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves
at Dec. 31,
2008 19,274 12,790 - 32,064 4,714 397,651 103,053
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
UNITED Oil Oil Bitumen Oil Liquids Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Probable
Reserves
at Dec. 31,
2007 6,719 - - 6,719 30 27,938 11,406
-------------------------------------------------------------------------
Acquisitions - - - - - - -
Divestments - - - - - - -
Discoveries - - - - - - -
Extensions &
Improved
Recovery 521 - - 521 11 1,952 857
Economic
Factors - - - - - - -
Technical
Revisions (373) - - (373) 10 (6,407) (1,431)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves
at Dec. 31,
2008 6,867 - - 6,867 51 23,483 10,832
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
TOTAL Oil Oil Bitumen Oil Liquids Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable
Reserves
at Dec. 31,
2007 24,556 10,948 54,930 90,434 3,827 336,214 150,297
-------------------------------------------------------------------------
Acquisitions 944 - - 944 831 119,352 21,667
Divestments - - (54,930)(54,930) - - (54,930)
Discoveries 37 - - 37 1 212 73
Extensions &
Improved
Recovery 1,593 486 - 2,079 179 9,928 3,912
Economic
Factors 303 171 - 474 32 4,070 1,184
Technical
Revisions (1,292) 1,185 - (107) (105) (48,642) (8,318)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves
at Dec. 31,
2008 26,141 12,790 - 38,931 4,765 421,134 113,885
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved Plus Probable Reserves
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
Oil Oil Bitumen Oil Liquids Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves
at Dec. 31,
2007 85,223 42,163 63,498 190,884 15,470 1,137,398 395,920
-------------------------------------------------------------------------
Acquisitions 4,529 - - 4,529 3,545 456,975 84,237
Divestments - - (63,498)(63,498) - - (63,498)
Discoveries 151 - - 151 7 847 299
Extensions &
Improved
Recovery 3,994 2,385 - 6,379 499 32,929 12,366
Economic
Factors 907 371 - 1,278 126 12,031 3,409
Technical
Revisions (918) 4,064 - 3,146 (301) (97,297) (13,371)
Production (6,187) (3,054) - (9,241) (1,693) (119,366) (30,828)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2008 87,699 45,929 - 133,628 17,653 1,423,517 388,534
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
UNITED Oil Oil Bitumen Oil Liquids Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves
at Dec. 31,
2007 33,356 - - 33,356 142 64,893 44,314
-------------------------------------------------------------------------
Acquisitions - - - - - - -
Divestments - - - - - - -
Discoveries - - - - - - -
Extensions &
Improved
Recovery 2,950 - - 2,950 27 5,892 3,959
Economic
Factors - - - - - - -
Technical
Revisions 92 - - 92 8 (1,974) (229)
Production (3,403) - - (3,403) (13) (4,660) (4,193)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2008 32,995 - - 32,995 164 64,151 43,851
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural
TOTAL Oil Oil Bitumen Oil Liquids Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves
at Dec. 31,
2007 118,579 42,163 63,498 224,240 15,612 1,202,291 440,234
-------------------------------------------------------------------------
Acquisitions 4,529 - - 4,529 3,545 456,975 84,237
Divestments - - (63,498)(63,498) - - (63,498)
Discoveries 151 - - 151 7 847 299
Extensions &
Improved
Recovery 6,944 2,385 - 9,329 526 38,821 16,325
Economic
Factors 907 371 - 1,278 126 12,031 3,409
Technical
Revisions (826) 4,064 - 3,238 (293) (99,271) (13,600)
Production (9,590) (3,054) - (12,644) (1,706) (124,026) (35,021)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2008 120,694 45,929 - 166,623 17,817 1,487,668 432,385
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET PRESENT VALUE OF FUTURE PRODUCTION REVENUE
The following tables provide an estimate of the net present value of
Enerplus' future production revenue before provision for interest and general
and administrative expenses and after deduction of royalties and estimated
future capital expenditures, both before and after income taxes. It should not
be assumed that the present value of estimated future cash flows shown below
is representative of the fair market value of the reserves.
The estimated net present value of all future net revenues at December
31, 2008 was based upon forecast crude oil and natural gas pricing assumptions
prepared by Sproule as of December 31, 2008. These prices were applied to the
reserves evaluated by Sproule and NSA. The base reference prices and exchange
rates used by Sproule are detailed below:
Sproule December 31, 2008 - Forecast Price Assumptions
-------------------------------------------------------------------------
Natural
Gas
30 day
Hardisty Henry spot
WTI Light Heavy Hub @
crude crude(1) 12(degrees) Price AECO Exchange
oil Edmonton API US$/ CDN$/ Rate
US$/bbl CDN$/bbl CDN$/bbl MMbtu MMbtu US$/CDN$
-------------------------------------------------------------------------
2009 53.73 65.35 47.05 6.30 6.82 0.80
2010 63.41 72.78 54.58 7.32 7.56 0.85
2011 69.53 79.95 59.96 7.56 7.84 0.85
2012 79.59 86.57 67.53 8.49 8.38 0.90
2013 92.01 94.97 74.08 9.74 9.20 0.95
-------------------------------------------------------------------------
Thereafter (xx) (xx) (xx) (xx) (xx) 0.95
-------------------------------------------------------------------------
(1) Edmonton refinery postings for 40 degree API, 0.4% sulphur content
crude
(xx) Escalation varies until 2019 and increases at an annual rate of 2%
thereafter
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (Before Tax) At December 31, 2008
Conventional Reserves ($ Millions,
discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing $10,366 $6,731 $5,044 $4,069
Proved developed non-producing 173 120 89 70
Proved undeveloped 1,177 704 438 272
-------------------------------------------------------------------------
Total Proved $11,716 $7,555 $5,571 $4,411
Probable 5,269 2,362 1,352 890
-------------------------------------------------------------------------
Total Proved Plus Probable
Conventional Reserves $16,985 $9,917 $6,923 $5,301
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (After Tax)
At December 31, 2008
Conventional Reserves ($ Millions,
discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing $8,573 $5,748 $4,403 $3,610
Proved developed non-producing 127 90 67 53
Proved undeveloped 952 550 332 196
-------------------------------------------------------------------------
Total Proved $9,652 $6,388 $4,802 $3,859
Probable 3,896 1,755 1,008 666
-------------------------------------------------------------------------
Total Proved Plus Probable
Conventional Reserves $13,548 $8,143 $5,810 $4,525
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET ASSET VALUE
Enerplus' estimated net asset value is measured with reference to the
estimated net present value of all future net revenue from our reserves,
before taxes, as estimated by our independent reserve engineers (Sproule and
NSA) plus land values, adjusted for working capital and long-term debt at
year-end. This calculation can vary significantly depending on the oil and
natural gas price assumptions used by the independent reserve engineers. In
addition, this calculation ignores "going concern" value and assumes only the
reserves identified in the reserve reports with no further acquisitions or
incremental development, despite our 23 year history of replacing production
through acquisitions and development.
In addition, we have included in our net asset value calculation
provisions for our oil sands portfolio. Given the significant decrease in oil
prices and the lack of comparable transactions of oil sands assets, we are
showing our costs (acquisition costs and any capital investments made to date)
in the net asset value table and have not attempted to determine a current
fair market value for our oil sands assets at this time.
Forecast Prices and Costs at December 31, 2008
Conventional Oil and Gas
($ millions except trust
unit amounts, discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Present value of proved
plus probable reserves
(before tax)
-------------------------------------------------------------------------
Total, present value of
proved plus probable reserves $16,985 $9,917 $6,923 $5,301
Undeveloped acreage(1) 85 85 85 85
Asset retirement obligations (343) (195) (74) (43)
Long-term debt (net of cash) (657) (657) (657) (657)
Net Working Capital excluding
deferred financial asset,
distributions to unitholders,
deferred credits, and
future income tax (106) (106) (106) (106)
-------------------------------------------------------------------------
Net Asset Value of
Conventional Assets $15,964 $9,044 $6,171 $4,580
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per Trust Unit
- Conventional Assets(2)(3) $96.41 $54.62 $37.27 $27.66
-------------------------------------------------------------------------
Oil Sands (at cost)
Kirby Oil Sands Lease(4) $246 $246 $246 $246
Laricina Equity Investment(5) 25 25 25 25
Undeveloped Oil Sands acreage(6) 11 11 11 11
-------------------------------------------------------------------------
Net Asset Value of
Oil Sands Assets $282 $282 $282 $282
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per Trust Unit
- Oil Sands $1.70 $1.70 $1.70 $1.70
Total Net Asset Value
per Trust Unit(2) $98.11 $56.32 $38.97 $29.36
-------------------------------------------------------------------------
(1) Conventional undeveloped acreage valued at $100 per acre except
Alberta which was valued at $50 per acre
(2) Asset retirement obligations ("ARO") do not equal the amount on the
balance sheet ($207.4 million) as the balance sheet amount uses a 6%
discount rate and a portion of the ARO costs are already reflected in
the present value of reserves computed by the independent engineers
(3) Based on 165,590,000 trust units outstanding at December 31, 2008
(4) Kirby valuation represents $203.1 million purchase price plus capital
spending of $42.9 million since acquisition
(5) Laricina equity investment represents the carrying value of our 4.3
million shares
(6) Undeveloped oil sands acreage valued at cost of land acquisitions and
development capital spent on those lands
RESERVE LIFE INDEX ("RLI")
Enerplus continues to maintain one of the longest reserve life indices in
the sector. In 2008 our proved plus probable RLI decreased primarily due to
the sale of the Joslyn oil sands interest and the removal of proved and
probable reserves associated with that lease. At this time, we have only
contingent resources and no reserves associated with the Kirby oil sand
project and therefore our RLI solely represents our conventional oil and gas
assets. Our proved reserve life index declined slightly in 2008 as we did not
replace all of the reserves produced during the year.
Conventional Reserves
(as at December 31) 2008 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
Proved 9.4 10.0 9.8 9.6 10.1 10.6
Proved plus Probable 12.1 12.8 12.2 12.0 12.4 13.3
-------------------------------------------------------------------------
Reserve life index is calculated as year end reserves divided by following
year production estimates contained in the independent reserve engineering
reports.
FINDING AND DEVELOPMENT COSTS ("F&D") AND FINDING, DEVELOPMENT AND
ACQUISITION COSTS ("FD&A")
F&D and FD&A costs have historically been calculated both including and
excluding future development capital. F&D and FD&A costs include future
development capital as this provides a more representative view of the full
cost of reserve additions as it accounts for future costs to bring the
reserves to market. Under the historic method, F&D and FD&A costs are
understated as reserves are included without taking into account the future
capital expenditures required to fully develop the reserve base. We have
included both the NI 51-101 method which includes future development capital
and the historic method for comparison purposes. The aggregate of the
exploration and development costs incurred in the most recent financial year
and the change during that year in estimated future development costs
generally will not reflect total finding and development costs related to
reserves additions for that year.
Our F&D and FD&A results were significantly influenced by our acquisition
and divestment activity during the year as well as a number of other factors
detailed above. When reviewing these numbers in light of these factors, care
must be taken before drawing conclusions as to the effectiveness of current
spending and the full-cycle economics associated with the recent and ongoing
capital investment program.
Our total spending on our conventional asset base delivered a FD&A cost
of $29.17/BOE on a proved plus probable basis including future development
capital ("FDC"). Our three-year conventional proved plus probable FD&A was
$27.13/BOE including changes in future development capital.
Through our conventional capital development program, we added 20.0
million BOE of proved plus probable reserves. We also experienced negative
technical revisions of 13.6 million proved plus probable BOE. Therefore on a
net basis, our capital development program added only 6.4 million BOE of
proved plus probable reserves resulting in F&D costs of $82.34/BOE on our
conventional oil and gas assets.
Our oil sands activity consisted of the disposition of the Joslyn oil
sands mining lease and capital development at our Kirby SAGD lease. We sold
63.5 million barrels of reserves (87% probable) associated with the Joslyn
lease and while the spending on our Kirby oil sands property did not add
production or reserves in 2008, it has advanced the Phase I project. As
development of the Kirby lease moves forward, we would expect to move
contingent resources into the probable reserve category. Key events triggering
this move would be regulatory approval of the Phase I project and affirmative
sanctioning by our Board of Directors. Our proved plus probable FD&A cost on
our oil sands assets was $13.71/BOE including FDC.
F&D and FD&A Costs (Including
Future Development Capital)
($ millions except for
per BOE amounts) 2008 2007 2006
-------------------------------------------------------------------------
Proved Reserves
Conventional Oil & Gas
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $526.5 $348.3 $452.1
Net change in Future
Development Capital $(27.9) $39.3 $22.3
Gross Company Reserve
additions (MMBOE) 9.6 17.9 16.1
F&D costs ($/BOE) $51.94 $21.65 $29.47
Three year average
F&D cost ($/BOE)(1) $31.21 $20.62 $15.54
Finding, Development
& Acquisition Costs
Capital Expenditures
and net acquisitions $2,296.5 $409.8 $502.0
Net change in Future
Developments Capital $252.5 $48.5 $8.0
Gross Company Reserve
additions (MMBOE) 72.2 20.4 18.6
FD&A costs ($/BOE) $35.30 $22.47 $27.42
Three year average FD&A
costs ($/BOE)(1) $31.63 $22.93 $19.80
Oil Sands
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $51.2 $38.9 $39.1
Net change in Future
Development Capital $- $(1.7) $(10.8)
Gross Company Reserve
additions (MMBOE) 0.0 (0.2) (0.1)
F&D costs ($/BOE) n/a $(186.00) $(283.00)
Three year average F&D
cost ($/BOE)(1) $(389.00) $15.58 $12.17
Finding, Development &
Acquisition Costs
Capital Expenditures
and net acquisitions $(450.8) $242.0 $19.4
Net change in Future
Development Capital $(29.3) $(1.7) $(13.6)
Gross Company Reserve
additions (MMBOE) (8.6) (0.2) (0.7)
FD&A costs ($/BOE) $55.83 $(1,201.50) $(8.29)
Three year average FD&A
costs ($/BOE)(1) $24.63 $37.66 $10.44
Proved Plus Probable Reserves
($ millions except for
per BOE amounts) 2008 2007 2006
Conventional Oil & Gas
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $526.5 $348.3 $452.1
Net change in Future
Development Capital $0.5 $(30.7) $50.7
Gross Company Reserve
additions (MMBOE) 6.4 15.9 18.3
F&D costs ($/BOE) $82.34 $19.97 $27.48
Three year average F&D
cost ($/BOE)(1) $33.19 $18.85 $20.22
Finding, Development &
Acquisition Costs
Capital Expenditures
and net acquisitions $2,296.5 $409.8 $502.0
Net change in Future
Development Capital $348.8 $(12.0) $54.4
Gross Company Reserve
additions (MMBOE) 90.7 20.1 21.9
FD&A costs ($/BOE) $29.17 $19.79 $25.41
Three year average FD&A
costs ($/BOE)(1) $27.13 $19.57 $18.10
Oil Sands
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $51.2 $38.9 $39.1
Net change in Future
Development Capital $- $105.0 $34.3
Gross Company Reserve
additions (MMBOE) 0.0 6.8 6.9
F&D costs ($/BOE) n/a $21.16 $10.64
Three year average F&D
cost ($/BOE)(1) $19.60 $14.86 $6.91
Finding, Development &
Acquisition Costs
Capital Expenditures
and net acquisitions $(450.8) $242.0 $19.4
Net change in Future
Development Capital $(420.1) $105.0 $15.6
Gross Company Reserve
additions (MMBOE) (63.5) 6.8 3.6
FD&A costs ($/BOE)(1) $13.71 $51.03 $9.72
Three year average FD&A
costs ($/BOE)(1) $9.21 $28.39 $6.63
-------------------------------------------------------------------------
(1) Calculated over a three year period.
F&D and FD&A Costs
(Excluding Future
Development Capital)
($ millions except for
per BOE amounts) 2008 2007 2006
-------------------------------------------------------------------------
Proved Reserves
Conventional Oil & Gas
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $526.5 $348.3 $452.1
Gross Company Reserve
additions (MMBOE) 9.6 17.9 16.1
F&D Cost ($/BOE) $54.84 $19.46 $28.08
Three year average F&D
costs ($/BOE)(1) $30.43 $18.09 $13.17
Finding, Development &
Acquisition Costs
Capital Expenditures and
net acquisitions $2,296.5 $409.8 $502.0
Gross Company Reserve
additions (MMBOE) 72.2 20.4 18.6
FD&A costs ($/BOE) $31.81 $20.09 $26.99
Three year average FD&A
costs ($/BOE)(1) $28.85 $20.33 $17.55
Oil Sands
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $51.2 $38.9 $39.1
Gross Company Reserve
additions (MMBOE) 0.0 (0.2) (0.1)
F&D Cost ($/BOE) n/a $(194.50) $(391.00)
Three year average F&D
costs ($/BOE)(1) $(430.67) $12.09 $8.57
Finding, Development &
Acquisition Costs
Capital Expenditures and
net acquisitions $(450.8) $242.0 $19.4
Gross Company Reserve
additions (MMBOE) (8.6) (0.2) (0.7)
FD&A costs ($/BOE) $52.42 $(1,210.00) $(27.71)
Three year average FD&A
costs ($/BOE)(1) $19.94 $34.26 $6.92
Proved Plus Probable Reserves
($ millions except
for per BOE amounts) 2008 2007 2006
Conventional Oil & Gas
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $526.5 $348.3 $452.1
Gross Company Reserve
additions (MMBOE) 6.4 15.9 18.3
F&D Cost ($/BOE) $82.27 $21.91 $24.70
Three year average F&D
costs ($/BOE)(1) $32.68 $17.16 $16.66
Finding, Development &
Acquisition Costs
Capital Expenditures and
net acquisitions $2,296.5 $409.8 $502.0
Gross Company Reserve
additions (MMBOE) 90.7 20.1 21.9
FD&A costs ($/BOE) $25.32 $20.39 $22.92
Three year average FD&A
costs ($/BOE)(1) $24.18 $17.36 $15.55
Oil Sands
-------------------------------------------------------------------------
Finding & Development Costs
Capital Expenditures $51.2 $38.9 $39.1
Gross Company Reserve
additions (MMBOE) 0.0 6.8 6.9
F&D Cost ($/BOE) n/a $5.72 $5.67
Three year average F&D
costs ($/BOE)(1) $9.43 $5.82 $1.34
Finding, Development &
Acquisition Costs
Capital Expenditures and
net acquisitions $(450.8) $242.0 $19.4
Gross Company Reserve
additions (MMBOE) (63.5) 6.8 3.6
FD&A costs ($/BOE) $7.10 $35.59 $5.39
Three year average FD&A
costs ($/BOE)(1) $3.57 $18.65 $1.07
-------------------------------------------------------------------------
(1) Calculated over a three year period.
RECYCLE RATIO
Recycle ratio is calculated as operating income (revenues less royalties
and operating costs) divided by FD&A including FDC. It is indicative of the
value created for each dollar invested and accounts for the quality of
reserves, operating costs and attractiveness of acquisitions and internal
development capital. We have shown only conventional recycle ratios as most of
our oil sands portfolio is in the early stages of development and consequently
currently has no operating income or proved plus probable reserves.
Proved Plus Probable Reserves 2008 2007 2006
-------------------------------------------------------------------------
Conventional Recycle Ratio 1.4x 1.6x 1.2x
Conventional 3-Year Average 1.4x 1.5x 1.4x
-------------------------------------------------------------------------
Based on 2008 netback of $41.07
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated
February 25, 2009 and is to be read in conjunction with the audited
consolidated financial statements as at and for the years ended December 31,
2008 and 2007. All amounts are stated in Canadian dollars unless otherwise
specified. All references to GAAP refer to Canadian generally accepted
accounting principles. All note references relate to the notes included with
the consolidated financial statements. In accordance with Canadian practice
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. In addition to disclosing reserves under
the requirements of NI 51-101, we also disclose our reserves on a company
interest basis which is not a term defined under NI 51-101. This information
may not be comparable to similar measures presented by other issuers. Where
applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading.
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.
2008 OVERVIEW
We began 2008 with the largest acquisition in our 23 year history. Focus
Energy Trust ("Focus") was acquired on February 13, 2008 for approximately
$1.7 billion and added approximately 18,000 BOE/day of average daily
production to our 2008 operating results. Commodity prices started the year
off strong and continued to rise throughout the first half of the year,
ultimately peaking in July. Higher commodity prices combined with additional
production volumes from Focus resulted in our cash flow from operating
activities totaling $1,262.8 million, representing a 45% increase from 2007.
On July 31, 2008, as commodity prices began to decline, we reduced our
exposure to oil sands and successfully disposed of our interest in the Joslyn
oil sands lease ("Joslyn") for net proceeds of $502.0 million. The proceeds
were used to pay down debt and, as a result, we believe that we have one of
the strongest balance sheets in the sector with a trailing twelve month
debt-to-cash flow ratio of 0.5x at December 31, 2008. We believe we are in a
strong position given the current market conditions and expect to enhance our
asset base with opportunistic acquisitions.
In addition to our successful acquisition and disposition activities, we
completed the largest development capital spending program in our history with
total spending of approximately $577.7 million, resulting in the drilling of
643 net wells with a 99% success rate.
The sharp decline in commodity prices in the fourth quarter of 2008 has
focused our priorities on preserving our balance sheet strength and, as a
result, we have decreased our 2009 development capital program along with our
monthly distributions. We intend to manage our capital spending and
distributions to unitholders at a level which will minimize increases in our
debt levels outside of any acquisition activity. We have decided to limit
spending on our current properties as we expect the acquisition market will
provide the best opportunity to add quality reserves at a reasonable cost in
today's credit constrained environment. As a result of our reduced development
capital spending, we expect annual production to average 91,000 BOE/day with
an exit production rate of 88,000 BOE/day in 2009.
RESULTS OF OPERATIONS
Production
Production during 2008 averaged 95,687 BOE/day, essentially in line with
our guidance of 96,000 BOE/day and 16% higher than 82,319 BOE/day in 2007. The
increase compared to 2007 was primarily due to the additional production
volumes from the Focus assets which were purchased on February 13, 2008.
Although our annual average production approximated our guidance we did
encounter challenges with production throughout the year. We experienced
unplanned downtime at several non-operated facilities along with setbacks
executing our capital program due to weather and tie in delays while we
assessed alternative well completion techniques.
Average production during the year was weighted 59% to natural gas and
41% to liquids on a BOE basis. Average production volumes for the years ended
December 31, 2008 and 2007 are outlined below:
Daily Production Volumes 2008 2007 % Change
-------------------------------------------------------------------------
Natural gas (Mcf/day) 338,869 262,254 29%
Crude oil (bbls/day) 34,581 34,506 -%
Natural gas liquids (bbls/day) 4,627 4,104 13%
Total daily sales (BOE/day) 95,687 82,319 16%
-------------------------------------------------------------------------
During the month of December we experienced production interruptions of
approximately 1,600 BOE/day on two of our properties. We experienced an
interruption of 1,100 BOE/day related to a labour strike at a non-operated
facility which processes our Tommy Lakes production and another interruption
of 500 BOE/day related to unscheduled downtime at Bantry. As a result, our
December average daily production was approximately 96,400 BOE/day. Both of
these issues were resolved and production was restored resulting in an
adjusted exit rate of approximately 98,000 BOE/day which was 500 BOE/day less
than our guidance of 98,500 BOE/day.
Considering our reduced development capital program in 2009, we expect
2009 annual production volumes to average 91,000 BOE/day, weighted 58% to
natural gas and 42% to liquids. We expect to exit 2009 with production of
approximately 88,000 BOE/day. This guidance does not contemplate any potential
acquisitions or dispositions.
Pricing
The prices received for our natural gas and crude oil production directly
impact our earnings, cash flow and financial condition. The following table
compares our average selling prices for 2008 with those of 2007. It also
compares the benchmark price indices for the same periods.
Average Selling Price(1) 2008 2007 % Change
-------------------------------------------------------------------------
Natural gas (per Mcf) $ 8.17 $ 6.45 27%
Crude oil (per bbl) $ 91.31 $ 65.11 40%
Natural gas liquids (per bbl) $ 68.93 $ 51.35 34%
Per BOE $ 65.79 $ 50.48 30%
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Average Benchmark Pricing 2008 2007 % Change
-------------------------------------------------------------------------
AECO natural gas - monthly index
(CDN$/Mcf) $ 8.13 $ 6.61 23%
AECO natural gas - daily index (CDN$/Mcf) $ 8.14 $ 6.45 26%
NYMEX natural gas - monthly NX3 index
(US$/Mcf) $ 8.93 $ 6.92 29%
NYMEX natural gas - monthly NX3 index:
CDN$ equivalent (CDN$/Mcf) $ 9.50 $ 7.44 28%
WTI crude oil (US$/bbl) $ 99.65 $ 72.34 38%
WTI crude oil: CDN$ equivalent (CDN$/bbl) $ 106.01 $ 77.78 36%
CDN$/US$ exchange rate 0.94 0.93 1%
-------------------------------------------------------------------------
Natural Gas
Natural gas prices in Alberta were strong through the first half of 2008,
opening at $6.97/Mcf at AECO and rising steadily to a high of $11.82/Mcf by
the end of June. The strength in natural gas prices was partly fueled by the
crude oil market which hit record levels by mid-year. Also, the key consuming
regions of the U.S. experienced cold weather from late January to March 2008
which decreased inventories to the lowest levels since 2004. Early forecasts
for an active hurricane season and the expectation for supply disruptions led
to further price strength at the start of summer combined with demand in Asia
and Europe for liquefied natural gas ("LNG") which diverted the majority of
LNG supply away from North America, ultimately helped keep prices high.
By mid-year the market started to adjust to the impact of the increased
U.S. shale gas production that had been brought on-stream throughout the year
and gas inventories started to rise despite a warmer than average summer. The
impact of the global economic crisis began to take its toll on demand as
supply additions continued to overwhelm the shrinking demand for gas. Prices
declined to a low of $5.79/Mcf at AECO at the end of September and closed the
year at $6.34/Mcf.
During 2008 we sold approximately 84% of our natural gas on the AECO
index split evenly between the daily and monthly indices and the remaining 16%
against the monthly NYMEX index. During 2008 we sold our natural gas for an
average price of $8.17/Mcf (net of transportation costs), an increase of 27%
from $6.45/Mcf realized in 2007. This increase is comparable to the price
increases realized in the AECO daily and monthly indices and the NYMEX monthly
index.
Crude Oil
Crude prices were strong through the first two quarters of 2008 reaching
a peak of US$147.27/bbl during July. Prices then dropped significantly,
approximately 77% through the second half of the year. The global economic
crisis and reduced access to credit began to weaken gasoline and distillate
demand. Inventories began to grow and the general bearish mood in the market,
which was supported by continued weak economic data, pushed prices down
reaching a low for the year in mid-December at US$33.87/bbl.
Our crude oil production in 2008 was weighted 76% light/medium and 24%
heavy. The average price received for our crude oil (net of transportation
costs) was $91.31/bbl during 2008, a 40% increase over 2007. The West Texas
Intermediate ("WTI") crude oil benchmark price, after adjusting for the change
in the U.S. dollar exchange rate, increased 36% year-over-year. With gasoline
demand falling and heavy oil refining capacity increasing, the demand for
heavy oil increased. This fundamental change created a narrowing of the heavy
differentials which benefited our heavy crude pricing in comparison to the
benchmark.
Foreign Exchange
During the first half of the year the Canadian dollar fluctuated around
par relative to the U.S. dollar, but by the third quarter it started to weaken
along with crude oil prices and by the fourth quarter it dropped dramatically
reaching a low CDN$/US$ exchange rate of 0.77. As most of our crude oil and a
portion of our natural gas sales are priced in reference to U.S. dollar
denominated benchmarks, this movement in the exchange rate during the latter
part of the year increased the Canadian dollar prices we realized.
Price Risk Management
We continue to adjust our price risk management program with
consideration 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.
Our existing commodity contracts are designed to protect a portion of our
natural gas sales through October 2010 and a portion of our crude oil sales
through December 2009. We have also hedged a portion of our electricity
consumption through December 2010 to protect against rising electricity costs
in the Alberta power market. See Note 12 for a detailed list of our current
price risk management positions.
The following is a summary of the financial contracts in place at
February 18, 2009 expressed as a percentage of our forecasted net production
volumes:
Natural Gas Crude Oil
(CDN$/Mcf) (US$/bbl)
-------------------------------------------- ----------
January 1, April 1, November 1, April 1, January 1,
2009 - 2009 - 2009 - 2010 - 2009 -
March October March October December
31, 2009 31, 2009 31, 2010 31, 2010 31, 2009
-------------------------------------------------------------------------
Purchased Puts
(floor prices) $ 9.20 $ 8.30 $ 8.99 $ - $98.08
% 21% 18% 8% - 24%
Sold Puts (limiting
downside protection) $ 6.93 $ 7.85 $ - $ - $66.17
% 14% 4% - - 10%
Swaps (fixed price) $ 9.35 $ 7.41 $ 7.33 $ 7.33 $100.05
% 3% 11% 9% 9% 2%
Sold Calls (capped
price) $11.60 $ - $12.13 $ - $92.98
% 10% - 2% - 11%
------------------------------------------------------------------------
Based on weighted average price (before premiums), estimated average
annual production of 91,000 BOE/day, net of royalties and assuming a 18%
royalty rate.
Accounting for Price Risk Management
For the first three quarters of 2008 commodity prices were generally
above our swap and sold call positions, resulting in cash losses of $135.0
million on our natural gas and crude oil contracts for the period ending
September 30, 2008. In the fourth quarter of 2008 commodity prices declined
significantly to levels below our swap and purchased put positions resulting
in cash gains of $31.8 million on our natural gas and crude oil contracts. In
aggregate we recorded net cash losses of $20.1 million on our natural gas
contracts and $83.1 million on our crude oil contracts in 2008. In comparison,
during 2007 our commodity price risk management program resulted in cash gains
of $23.6 million on our natural gas contracts and cash losses of $10.0 million
on our crude oil contracts.
At December 31, 2008 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represented a gain of $24.3 million
and $96.6 million respectively. These gains are recorded as current deferred
financial assets on our balance sheet. In comparison, at December 31, 2007 the
fair value of our natural gas derivative instruments, net of premiums,
represented a gain of $9.7 million which was recorded on our balance sheet as
a deferred financial asset and the fair value of our crude oil derivative
instruments, net of premiums, represented a loss of $52.5 million which was
recorded on our balance sheet as a deferred financial credit. The change in
the fair value of our financial contracts during the year, after adjusting for
the Focus derivative instruments, resulted in unrealized gains of $16.2
million for natural gas and $153.4 million for crude oil. As the forward
markets for natural gas and crude oil fluctuate, new contracts are executed
and existing contracts are realized, the changes in fair value will be
reflected as a non-cash charge or non-cash gain in earnings. See Note 12 for
details.
The following table summarizes the effects of our financial contracts on
income for the years ended December 31, 2008 and 2007.
Risk Management Costs
($ millions, except per
unit amounts) 2008 2007
-------------------------------------------------------------------------
Cash (losses)/gains:
Natural gas $ (20.1) $(0.16)/Mcf $ 23.6 $ 0.25/Mcf
Crude oil (83.1) $(6.57)/bbl (10.0) $(0.79)/bbl
---------- ----------
Total cash (losses)/gains $ (103.2) $(2.94)/BOE $ 13.6 $ 0.45/BOE
Non-cash gains/(losses)
on financial contracts:
Change in fair value
- natural gas $ 16.2 $ 0.13/Mcf $ (3.0) $(0.03)/Mcf
Change in fair value
- crude oil 153.4 $ 12.12/bbl (63.4) $(5.03)/bbl
---------- ----------
Total non-cash
gains/(losses) $ 169.6 $ 4.84/BOE $ (66.4) $(2.21)/BOE
---------- ----------
Total gains/(losses) $ 66.4 $ 1.90/BOE $ (52.8) $(1.76)/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Flow Sensitivity
The sensitivities below reflect all commodity contracts as listed in Note
12 and are based on forward markets as at February 18, 2009. To the extent the
market price of crude oil and natural gas change significantly from current
levels, the sensitivities will no longer be relevant as the effect of our
commodity contracts will change.
Effect on 2009
Cash Flow per
Sensitivity Table Trust Unit(1)
-------------------------------------------------------------------------
Change of $0.50 per Mcf in the price of AECO natural gas $0.20
Change of US$5.00 per barrel in the price of WTI crude oil $0.32
Change of 1,000 BOE/day in production $0.06
Change of $0.01 in the US$/CDN$ exchange rate $0.08
Change of 1% in interest rate $0.04
-------------------------------------------------------------------------
(1) Assumes constant working capital and 165,590,000 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 in 2008 were $2,304.2 million
($2,331.9 million, net of $27.7 million of transportation costs), an increase
of 52% or $787.1 million compared to $1,517.1 million ($1,539.2 million, net
of $22.1 million of transportation costs) during 2007. Higher commodity prices
and production resulting primarily from our Focus acquisition helped to
increase revenues significantly over 2007 levels.
Analysis of Sales Natural
Revenue(1) ($ millions) Crude oil NGLs Gas Total
-------------------------------------------------------------------------
2007 Sales Revenue $ 820.1 $ 76.9 $ 620.1 $ 1,517.1
Price variance(1) 331.6 29.7 221.2 582.5
Volume variance 4.0 10.1 190.5 204.6
-------------------------------------------------------------------------
2008 Sales Revenue $ 1,155.7 $ 116.7 $ 1,031.8 $ 2,304.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Other Income
Other income during 2008 was $8.5 million compared to $15.0 million in
2007. During 2008 we realized a gain of $8.3 million on the sale of marketable
securities and business interruption insurance proceeds of $8.9 million
related to the Giltedge fire. In addition we recorded a write down of $10.0
million related to one of our equity investments in a private company. In 2007
we had 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. Total royalties paid during 2008 increased to $429.9
million compared to $285.1 million in 2007 due to increased commodity prices
and production volumes. As a percentage of oil and gas sales, net of
transportation costs, royalties remained at approximately 19%.
On January 1, 2009 a new royalty regime came into effect in the province
of Alberta where approximately 60% of our production is located. This new
regime has provisions for escalating royalty rates depending on production and
product price levels. The fundamental design of this regime (which increases
royalty rates as commodity prices increase) has removed some of the price
upside producers had previously factored into their risk assessments for
capital investment. The Alberta government further modified the new regime
with programs to encourage the drilling of medium and deeper wells but with
our reduced development capital spending plans we expect no material impact in
2009 from these modifications. Assuming current forward commodity prices and
our production profile, we expect our average royalty rate to decrease
slightly in 2009. The following is a summary of our estimated corporate
average royalty rates under various commodity price scenarios.
2009 Royalty Rate
Light Crude Oil
(Cdn $/bbl)(1) $40.00 $50.00 $60.00 $70.00 $80.00 $100.00 $120.00
-------------------------------------------------------------------------
AECO Natural
Gas ($/Mcf) $ 4.00 $ 5.00 $ 6.00 $ 7.00 $ 8.00 $ 10.00 $ 12.00
-------------------------------------------------------------------------
Corporate
royalty rate 15.6% 17.2% 18.7% 20.2% 21.5% 24.0% 25.9%
Incremental
Annual
Royalties(2)
($ Millions) $(28.6) $(18.0) $(0.1) +$25.0 +$53.3 +$ 123.8 +$ 203.1
-------------------------------------------------------------------------
(1) Canadian dollar denominated prices before quality differentials and
transportation
(2) Compared to 2008 corporate average rate of 19%
Operating Expenses
Operating expenses during 2008 were $9.50/BOE or $332.6 million which was
in-line with our guidance and 4% higher than 2007 operating costs of $9.12/BOE
or $274.2 million. Although we expected the acquisition of Focus to decrease
operating costs on a BOE basis, rising costs due to high industry activity for
most of 2008 resulted in higher than expected charges for repairs and
maintenance, chemicals, labour and supplies. In addition we increased our
service rig activity related to our U.S. optimization program.
For 2009 we expect operating costs to average $10.65/BOE, representing an
increase of 12% per BOE compared to 2008. Approximately half of this increase
is due to lower production while the remainder is due to increased power and
regulatory costs as well as optimization efforts on our Canadian properties.
General and Administrative Expenses ("G&A")
G&A expenses were $1.88/BOE or $65.7 million during 2008, approximately
6% lower than our guidance of $2.00/BOE and 17% lower than $2.26/BOE in 2007.
G&A expenses were lower than our guidance primarily due to lower than
anticipated compensation charges. All our compensation plans impact cash G&A
with the exception of our trust unit rights incentive plan which is non-cash.
Our 2008 G&A expenses included non-cash charges for our trust unit rights
incentive plan of $7.0 million or $0.20/BOE compared to $8.4 million or
$0.28/BOE for 2007. These amounts relate solely to our trust unit rights
incentive plan and are based on the fair value which is determined on the
grant date using a binomial lattice option-pricing model. These values may not
represent the amount realized by employees. See Note 10 for further details.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and Administrative Costs ($ millions) 2008 2007
-------------------------------------------------------------------------
Cash $58.7 $59.5
Trust unit rights incentive plan (non-cash) 7.0 8.4
-------------------------------------------------------------------------
Total G&A $65.7 $67.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2008 2007
-------------------------------------------------------------------------
Cash $1.68 $1.98
Trust unit rights incentive plan (non-cash) 0.20 0.28
-------------------------------------------------------------------------
Total G&A $1.88 $2.26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Our 2008 cash G&A costs were significantly impacted by the drop in our
trust unit price during the year. Our compensation plans are directly tied to
the movement in our trust unit price. During 2008 our trust unit price
decreased 40% from $39.87 to $23.96 which significantly reduced the projected
payouts on our plans and our 2008 G&A per BOE measure. In 2009 we expect cash
G&A costs to be $2.25/BOE which is more consistent with 2007 levels adjusted
for increased technical staff added and additional office space acquired
during 2008. We expect total G&A costs in 2009 to be $2.45/BOE including
non-cash G&A costs of approximately $0.20/BOE.
Interest Expense
Interest expense includes interest on long-term debt, the premium
amortization on our US$175 million senior unsecured notes, unrealized gains
and losses resulting from the change in fair value of our interest rate swaps
as well as the interest component on our cross currency interest rate swap
("CCIRS"). See Note 8 for further details.
Interest on long-term debt during 2008 totaled $42.6 million, a $0.7
million increase from $41.9 million in 2007. This increase is due to higher
average indebtedness offset by lower interest rates year-over-year. As a
result of the Focus acquisition in February 2008, $330.9 million of additional
debt was assumed when average interest rate was approximately 4.5%. In July
2008 we used the proceeds of $502.0 million from the disposition of Joslyn to
reduce debt outstanding. The Bank of Canada interest rates declined through
2008 from 4.25% to 1.50% at the end of the year. During 2008 our weighted
average interest rate was 3.8% compared to 4.8% in 2007.
For the year ended December 31, 2008 we recorded unrealized gains of
$18.4 million compared to $8.3 million in 2007. The changes in the fair value
of our interest rate swaps and CCIRS that result from movements in forward
market interest rates cause non-cash interest to fluctuate between periods.
The following table summarizes the cash and non-cash interest expense:
Interest Expense ($ millions) 2008 2007
-------------------------------------------------------------------------
Interest on long-term debt $42.6 $41.9
Unrealized gain (18.4) (8.3)
-------------------------------------------------------------------------
Total Interest Expense $24.2 $33.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At December 31, 2008 approximately 28% of our debt was based on fixed
interest rates while 72% had floating interest rates. In comparison, at
December 31, 2007 approximately 18% of our debt was based on fixed interest
rates and 82% was floating.
Capital Expenditures
During 2008 we spent $577.7 million on development capital, which was
$190.5 million or 49% greater than 2007. The increased capital spending in
2008 was due to our expanded asset base resulting from the Focus acquisition
as well as increased spending on shallow gas, deep gas and Bakken oil projects
given higher commodity prices for the majority of the year. Included in our
development capital spending was $54.8 million of exploratory drilling seismic
and undeveloped land acquisitions mainly within the Montney and Bakken plays
which we expect to provide future development opportunities. We achieved a 99%
success rate drilling 643 net wells during 2008.
Our 2008 development capital was approximately $33.0 million above our
guidance of $545.0 million, mainly due to $22.0 million of accelerated
activity in the Tommy Lakes, Bantry and Shackleton areas. The remaining $11.0
million related to cost overages on various properties including pipeline
maintenance at Golden and drilling costs at Pembina and Virden. We expect the
impact on production and overall capital spending for 2009 to be minimal.
Corporate acquisitions for 2008 totaled approximately $1.7 billion and
relate to the Focus acquisition which closed February 13, 2008 (refer to Note
5 for further details). Property dispositions were $504.8 million during 2008
compared to $9.6 million in 2007. Our 2008 divestments relate mainly to the
Joslyn disposition which closed in July 2008 for net proceeds of $502.0
million. Our 2007 divestments included $5.6 million of property interests in
the Thorhild area and the sale of undeveloped land in North Dakota for
approximately $3.6 million.
Property acquisitions were $15.3 million during 2008 compared to $274.2
million in 2007. The majority of our 2007 acquisitions related to the purchase
of our Kirby Oil Sands Project ("Kirby") for total consideration of $203.1
million and the purchase of gross-overriding royalty interests in the Jonah
area for approximately $61.0 million.
Capital Expenditures ($ millions) 2008 2007
-------------------------------------------------------------------------
Development expenditures $ 442.4 $ 321.3
Plant and facilities 135.3 65.9
-------------------------------------------------------------------------
Development Capital 577.7 387.2
Office 10.6 6.5
-------------------------------------------------------------------------
Sub-total 588.3 393.7
Property acquisitions(1) 15.3 274.2
Corporate acquisitions 1,757.5 -
-------------------------------------------------------------------------
Capital Expenditures 2,361.1 667.9
-------------------------------------------------------------------------
Property dispositions(1) (504.8) (9.6)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 1,856.3 $ 658.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Capital Expenditures financed with cash
flow $ 476.7 $ 221.7
Total Capital Expenditures financed with debt
and equity 1,379.6 443.2
Total non-cash consideration for property
dispositions - (6.6)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 1,856.3 $ 658.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
The following is a summary by play type of our development capital
expenditures during 2008 and 2007, as well as our current expectations for
2009.
Play type ($ millions) 2009 Estimate 2008 2007
-------------------------------------------------------------------------
Shallow Gas and CBM $ 74.3 $159.1 $ 39.3
Crude Oil Waterfloods 45.4 84.0 54.2
Tight Gas 78.4 81.0 34.7
Bakken/Tight Oil 41.8 99.0 106.2
Other Conventional Oil and Gas 35.1 103.4 113.9
Oil Sands 25.0 51.2 38.9
-------------------------------------------------------------------------
Total $300.0 $577.7 $387.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We expect development capital expenditures in 2009 to be approximately
$300 million including oil sands development capital of approximately $25
million and $50 million on initial resource investments (land and seismic)
neither of which are expected to impact 2009 production.
Oil Sands
Our current oil sands portfolio includes the 100% owned and operated
Kirby steam assisted gravity drainage ("SAGD") project and a 12% minority
equity ownership interest in Laricina Energy Ltd., a private oil sands company
focused on SAGD development in the Athabasca oil sands.
Our Kirby project has not commenced commercial production. As a result,
all associated costs inclusive of acquisition expenditures are capitalized and
excluded from our depletion calculation. During 2008 we capitalized costs of
$40.6 million associated with the Kirby project including costs of our
regulatory application, which we filed on September 26, 2008. At December 31,
2008 capitalized costs life-to-date for our oil sands development were $257.6
million compared to $321.8 million at December 31, 2007. Included in the 2007
amount was our Joslyn interest which we sold on July 31, 2008.
As a result of current low crude oil prices we have reduced our 2009
capital spending on the Kirby project to $25.0 million consisting primarily of
engineering and regulatory costs associated with advancing Phase I and seismic
costs aimed at expanding the overall resource base associated with this lease.
Kirby has a reserve life of over 25 years and we believe over the longer term
oil prices will recover to justify proceeding with development. Our regulatory
application is currently under review and we expect to receive regulatory
approval by the end of 2009. Our board of directors will re-evaluate whether
to continue to proceed with or delay the Kirby project at that time.
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 2008 DDA&A was $640.4
million or $18.29/BOE compared to $463.7 million or $15.43/BOE in 2007. The
increase is a result of higher PP&E and production from the Focus acquisition.
No impairment of the Fund's PP&E values existed at December 31, 2008
using year-end reserves and management's estimates of future prices. Our
future price estimates are more fully discussed in Note 3.
Goodwill
The goodwill balance of $634.0 million arose as a result of previous
corporate acquisitions and represents the excess of the total purchase price
over the fair value of the net identifiable assets and liabilities acquired.
Accounting standards require the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. No goodwill impairment exists as of December 31, 2008.
Asset Retirement Obligations
We have estimated our future asset retirement obligations based on our
net ownership interest in wells and facilities, along with the estimated cost
and timing to abandon and reclaim wells and facilities in the future. Our
asset retirement obligation was $207.4 million at December 31, 2008 compared
to $165.7 million at December 31, 2007. The majority of the $41.7 million
increase was due to the addition of abandonment obligations associated with
the Focus acquisition. The remainder of the increase was due to additional
costs from development capital activity and accretion expense offset by
retirement costs incurred. See Note 4 for further details.
The following chart shows the amortization of the asset retirement cost
and accretion of the asset retirement obligation compared to asset retirement
obligations settled.
($ millions) 2008 2007
-------------------------------------------------------------------------
Amortization of the asset retirement cost $20.0 $11.4
Accretion of the asset retirement obligation 11.9 6.7
-------------------------------------------------------------------------
Total Amortization and Accretion $31.9 $18.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement Obligations Settled $18.3 $16.3
-------------------------------------------------------------------------
Actual asset retirement costs are incurred at different times compared to
the recording of amortization and accretion charges. Actual asset retirement
costs will be incurred over the next 66 years with the majority between 2039
and 2048. 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
Canadian Government's tax changes
In 2008, the Canadian Federal government introduced draft tax legislation
that allowed for the conversion of a specified investment flow-through
("SIFT") entity into corporate form on a tax deferred basis, defined the
provincial tax component of the SIFT tax, and accelerated the recognition of
the "Safe Harbour" limit. None of the above were enacted prior to the
prorogation of Parliament in December 2008. Therefore, all bills containing
the draft legislation have lapsed.
Subsequent to the year end, the Federal government has introduced draft
tax legislation which includes the above mentioned measures as part of
Canada's Economic Action Plan. When or if this draft tax legislation becomes
substantially enacted, Enerplus will be able to recognize the tax benefit
associated with the lower provincial tax component of the SIFT tax.
Future Income Taxes
Future income taxes arise from differences between the accounting and tax
basis of assets and liabilities. A portion of the future income tax liability
recorded on the balance sheet will be recovered through earnings before 2011.
The balance will be realized when future income tax assets and liabilities are
realized or settled.
The future income tax recovery for 2008 was $51.2 million compared to
$1.0 million in 2007. The change was due to the following:
- The enactment of the SIFT tax which resulted in a future income tax
expense of $78.1 million in 2007;
- The enactment of corporate income tax rate reductions which resulted
in a future income tax recovery of $22.6 million in 2007 as compared
to $2.7 million in 2008;
- The sale of Joslyn in 2008 resulted in a future income tax recovery
of $58.9 million relating to the non-taxable portion of the realized
gain, along with the recognition of tax losses previously
unrecognized; and
- The incremental future tax expense of $51.8 million in 2008 related
to the increase in the net income attributed to the fund.
After consideration of the above items the future tax provisions were
comparable between periods.
Current Income Taxes
In our current structure payments are made between the operating entities
and the Fund, which ultimately transfers both income and future income tax
liability to our unitholders. As a result minimal cash income taxes are
generally paid by our Canadian operating entities. However, effective January
1, 2011 we will be subject to the SIFT tax should we remain a trust.
A Canadian income tax liability of $24.3 million was triggered on the
acquisition of Focus in 2008. This liability was included in Focus' assumed
working capital at the time of acquisition. We have accrued for the recovery
of these taxes in 2008 which constitutes the majority of the Canadian income
tax recovery.
During 2008 our U.S. operations incurred current taxes in the amount of
$47.8 million compared to $23.0 million in 2007. The increase is due to higher
net income combined with a modest decrease in drilling and completion
expenditures for the year.
The amount of current taxes recorded throughout the year on our U.S.
operations is dependent upon the timing of both capital expenditures and
repatriation of funds to Canada. Our U.S. taxes as a percentage of cash flow,
assuming constant working capital, were 18% in 2008 compared to our guidance
of 20% as a result of lower commodity prices in the fourth quarter. We expect
current income and withholding taxes to average approximately 15% of cash flow
from U.S. operations in 2009 based on our current development capital program
and assuming all funds are repatriated to Canada.
Tax Pools
We estimate our tax pools at December 31, 2008 to be as follows:
Operating
Pool Type ($ millions) Trust entities Total
-------------------------------------------------------------------------
COGPE $ 470 $ 165 $ 635
CDE - 670 670
UCC - 680 680
CEE - 125 125
Tax losses and other 15 380 395
Foreign tax pools - 210 210
-------------------------------------------------------------------------
Total $ 485 $2,230 $2,715
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Income
Net income in 2008 was $888.9 million or $5.54 per trust unit compared to
$339.7 million or $2.66 per trust unit in 2007. The $549.2 million increase in
net income was primarily due to a $787.0 million increase in oil and gas sales
(net of transportation costs), $119.3 million increase in commodity derivative
instrument gains and a $48.3 million increase in future tax recovery,
partially offset by increased DDA&A charges of $176.7 million, increased
royalty expense of $144.8 million and increased operating costs of $58.4
million.
Cash Flow from Operating Activities
Cash flow from operating activities in 2008 was $1,262.8 million or $7.86
per trust unit compared to $868.5 million or $6.80 per trust unit in 2007. The
increase is primarily due to increased commodity prices in the first three
quarters of 2008 and higher production volumes.
Selected Financial Results
Year ended December 31, Year ended December 31,
2008 2007
Per BOE of Operating Non-Cash Operating Non-Cash
production Cash & Other Cash & Other
(6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production per
day 95,687 82,319
-------------------------------------------------------------------------
Weighted
average sales
price (2) $ 65.79 $ - $ 65.79 $ 50.48 $ - $ 50.48
Royalties (12.27) - (12.27) (9.49) - (9.49)
Commodity
derivative
instruments (2.94) 4.84 1.90 0.45 (2.21) (1.76)
Operating costs (9.51) 0.01 (9.50) (9.11) (0.01) (9.12)
General and
administrative (1.68) (0.20) (1.88) (1.98) (0.28) (2.26)
Interest
expense, net
of interest
income (0.91) 0.51 (0.40) (1.37) 0.28 (1.09)
Foreign exchange
gain / (loss) (0.68) (0.05) (0.73) (0.06) 0.30 0.24
Current income
tax (0.65) - (0.65) (0.77) - (0.77)
Restoration and
abandonment
cash costs (0.52) 0.52 - (0.54) 0.54 -
Depletion,
depreciation,
amortization
and accretion - (18.29) (18.29) - (15.43) (15.43)
Future income
tax (expense)
/ recovery - 1.46 1.46 - 0.04 0.04
Other Income - (0.05) (0.05) - 0.47 0.47
-------------------------------------------------------------------------
Total per BOE $36.63 $(11.25) $ 25.38 $ 27.61 $(16.30) $ 11.31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash Flow from Operating Activities before changes in non-cash
operating working capital.
(2) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Selected Annual Canadian and U.S. Financial Results
The following table provides a geographical analysis of key operating and
financial results for 2008 and 2007.
Year ended December 31, 2008 Year ended December 31, 2007
(CDN$
millions,
except per
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Average Daily
Production
Volumes
Natural gas
(Mcf/day) 326,138 12,731 338,869 251,561 10,693 262,254
Crude oil
(bbls/day) 25,248 9,333 34,581 24,590 9,916 34,506
Natural gas
liquids
(bbls/day) 4,627 - 4,627 4,104 - 4,104
Total daily
sales
(BOE/day) 84,232 11,455 95,687 70,621 11,698 82,319
Pricing (1)
Natural gas
(per Mcf) $ 8.14 $ 8.93 $ 8.17 $ 6.45 $ 6.55 $ 6.45
Crude oil
(per bbl) $ 90.28 $ 94.09 $ 91.31 $ 62.27 $ 72.17 $ 65.11
Natural gas
liquids
(per bbl) $ 68.93 $ - $ 68.93 $ 51.35 $ - $ 51.35
Capital
Expenditures
Development
capital and
office $ 518.2 $ 70.1 $ 588.3 $ 287.3 $ 106.4 $ 393.7
Acquisitions
of oil and
gas
properties $ 15.2 $ 0.1 $ 15.3 $ 213.3 $ 60.9 $ 274.2
Corporate
Acquisi-
tions $1,757.5 $ - $1,757.5
Dispositions
of oil and
gas
properties $ (504.9) $ 0.1 $ (504.8) $ (6.0) $ (3.6) $ (9.6)
Revenues
Oil and gas
sales (1) $1,941.2 $ 363.0 $2,304.2 $1,230.4 $ 286.7 $1,517.1
Royalties $ (351.9) $(78.0)(2) $(429.9) $ (226.4) $(58.7)(2) $(285.1)
Commodity
derivative
instru-
ments gain/
(loss) $ 66.4 $ - $ 66.4 $ (52.8) $ - $ (52.8)
Expenses
Operating $ 314.5 $ 18.1 $ 332.6 $ 264.4 $ 9.8 $ 274.2
General and
adminis-
trative $ 58.6 $ 7.1 $ 65.7 $ 62.6 $ 5.3 $ 67.9
Depletion,
depreciation,
amortization
and
accretion $ 550.0 $ 90.4 $ 640.4 $ 359.8 $ 103.9 $ 463.7
Current
income taxes
(recovery)/
expense $ (25.1) $ 47.8 $ 22.7 $ - $ 23.0 $ 23.0
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) Royalties include U.S. state production tax.
Three Year Summary of Key Measures
Overall, increased production volumes from our Focus acquisition and
increased commodity prices have resulted in higher oil and gas sales, net
income and cash flow from operating activities during 2008 compared to 2007.
The rise in crude oil prices during 2006, 2007 and the first three quarters of
2008 contributed to higher overall sales, however gas sales moderated in 2007
as a result of lower natural gas prices. The following table provides a
summary of net income, cash flow and other key measures.
($ millions, except per unit amounts) 2008 2007 2006
-------------------------------------------------------------------------
Oil and gas sales(1) $2,304.2 $1,517.1 $1,572.7
Net income 888.9 339.7 544.8
Per unit (Basic)(2) 5.54 2.66 4.48
Per unit (Diluted) 5.53 2.66 4.47
Cash flow from operating activities 1,262.8 868.5 863.7
Per unit (Basic) (2) 7.86 6.80 7.10
Cash distributions 786.1 646.8 614.3
Per unit (Basic) (2) 4.90 5.07 5.05
Payout ratio 62% 74% 71%
Total assets 6,230.1 4,303.1 4,203.8
Long-term debt, net of cash 657.4 725.0 679.7
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) Based on weighted average trust units outstanding. Cash distributions
to unitholders per unit will not correspond to actual distributions
as a result of using the annual weighted average trust units
outstanding.
Liquidity and Capital Resources
Capital Markets and Enerplus' Credit Exposure
The recent turmoil in the financial markets has 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 the summer
of 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 December 31, 2008 we have drawn $380.9
million or approximately 27% of our $1.4 billion facility and have a trailing
debt-to-cash flow ratio of 0.5x. Our borrowing cost is currently 55.0 basis
points over bankers' acceptance rates.
At December 31, 2008 Enerplus was 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 favour of Enerplus, however
the likelihood of substantiating and receiving damages is unknown. We have not
experienced any funding issues under the facility to date.
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. A credit review process is in
place 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
year ended December 31, 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 proceedings 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 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 generally 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. At December 31, 2008 we had $128.1 million in
mark-to-market assets offset by $26.4 million of mark-to-market liabilities
consisting of net asset positions of $77.2 million with major Canadian
institutions and $24.5 million with U.S. institutions.
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 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 fully
drawn bank facilities. We do not anticipate any significant issues in the
collection of our joint interest receivables at this time. 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, and as a result
we have increased our bad debt provision by $1.0 million.
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, capital spending plans and
capital market conditions. 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.
The sharp decrease in crude oil and natural gas prices has resulted in a
decrease in our overall cash flows. This commodity price downturn, combined
with the ongoing uncertainty and reduced access to the debt and equity
markets, has reinforced our belief in the importance of maintaining strong
financial flexibility. To that end, we have reduced our monthly cash
distributions three times during the last five months to the current level of
$0.18 per unit effective February 20, 2009. We intend to manage our
distribution levels and capital spending in order to minimize increases in our
debt levels and preserve our balance sheet strength for future acquisitions.
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.
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.
Our 2009 development capital spending is expected to be $300 million
which represents a 48% decrease from 2008 spending of $577.7 million. In 2009
we expect to spend $50 million on initial resource investments such as land
acquisitions and seismic to position us for development opportunities in the
future, which is not expected to add production in 2009. As a result we expect
our production to decrease to an annual average of 91,000 BOE/day and an exit
rate of 88,000 BOE/day in 2009. At this level of capital spending it will be
difficult to replace our production without reliance on acquisitions to
supplement our reserves.
Enerplus currently has approximately $9.5 billion of safe harbour growth
capacity within the context of the Canadian 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.
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 2008 cash distributions
of $786.1 million were funded entirely through cash flow of $1,262.8 million.
Our payout ratio, which is calculated as cash distributions divided by cash
flow, was 62% for 2008 compared to 74% in 2007. See "Non-GAAP Measures" in
this MD&A.
In aggregate, our 2008 cash distributions of $786.1 million and our
development capital and office expenditures of $588.3 million totaled $1,374.4
million, or approximately 109% of our cash flow of $1,262.8 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. We anticipate that our reduced capital spending
plans for 2009 along with our reductions in monthly cash distributions will
help minimize any increases in debt levels and preserve our balance sheet.
There will 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. Despite our 2008 cash
flow being less than the aggregate of our cash distributions and development
capital, we continue to have conservative debt levels with a trailing twelve
month debt-to-cash flow ratio of 0.5x at December 31, 2008 and an annualized
fourth quarter 2008 debt-to-cash flow ratio of 0.7x.
For the year ended December 31, 2008 our net income exceeded our cash
distributions by $102.8 million whereas in 2007 our cash distributions
exceeded our net income by $307.1 million. Non-cash items, such as changes in
the fair value of our derivative instruments and future income taxes, cause
net income to fluctuate between periods but do not impact cash flow from
operations. In addition, other non-cash charges such as DDA&A are not a good
proxy for the cost of maintaining our productive capacity as they are based on
the historical costs of our PP&E and not the fair market value of replacing
those assets within the context of the current environment.
It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. As a result we do not
distinguish maintenance capital separately from development capital spending.
The level of investment in a given period may not be sufficient to replace
productive capacity given the natural declines associated with oil and natural
gas assets. In these instances a portion of the cash distributions paid to
unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income.
($ millions, except per unit amounts) 2008 2007 2006
-------------------------------------------------------------------------
Cash flow from operating activities $1,262.8 $ 868.5 $ 863.7
Cash Distributions 786.1 646.8 614.3
-------------------------------------------------------------------------
Excess of cash flow over cash
distributions $ 476.7 $ 221.7 $ 249.4
Net income $ 888.9 $ 339.7 $ 544.8
Excess/(shortfall) of net income over
cash distributions $ 102.8 $ (307.1) $ (69.5)
Cash distributions per weighted average
trust unit $ 4.90 $ 5.07 $ 5.05
Payout ratio (1) 62% 74% 71%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow from operating
activities.
Asset Retirement Costs
Actual asset retirement costs incurred in the period are deducted for the
purposes of calculating cash flow. Differences between actual asset retirement
costs incurred and the amortization and accretion of the asset retirement
obligation are discussed in the Asset Retirement Obligations section of this
MD&A and Note 4.
Long-Term Debt
Long-term debt at December 31, 2008 was $664.3 million, a decrease of
$62.4 million from $726.7 million at December 31, 2007. Long-term debt at
December 31, 2008 was comprised of $380.9 million of bank indebtedness and
$283.4 million of senior unsecured notes. Our bank indebtedness decreased by
$116.5 million year-over-year mainly due to proceeds received from the Joslyn
disposition of $502.0 million which was partially offset by additional debt of
$330.9 million acquired in the Focus acquisition. Our senior unsecured notes
are comprised of our US$175 million senior notes and our US$54 million senior
notes. The change in period end foreign exchange rate resulted in an increase
in the carrying value of our senior notes to $283.4 million compared to $229.3
million at December 31, 2007.
Our working capital, excluding cash, at December 31, 2008 increased
$147.2 million compared to December 31, 2007 primarily due to an increase in
our deferred financial assets relating to our financial derivative contracts.
Excluding deferred financial assets and credits, our working capital decreased
by $16.4 million compared to the prior year. This is primarily due to an
increase in future income taxes payable offset slightly by a decrease in
distributions payable and an increase in accounts receivable.
We continue to maintain a conservative balance sheet as demonstrated
below with over $1.0 billion in unused credit capacity under our current
facility:
Year Year
ended ended
Dec. 31, Dec. 31,
Financial Leverage and Coverage 2008 2007
-------------------------------------------------------------------------
Long-term debt to trailing 12 month cash flow 0.5 x 0.8 x
Long-term debt to annualized fourth quarter cash flow 0.7 x 0.9 x
Cash flow to interest expense (12 month trailing) 46.5 x 25.8 x
Long-term debt to long-term debt plus equity 13% 22%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
At December 31, 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
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 December 31,
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, 2008 for a detailed description of these
covenants.
Principal payments on Enerplus' senior unsecured notes are required
commencing in 2010 and are more fully discussed below under "Commitments" and
Note 13.
We continue to have adequate liquidity to fund planned development
capital spending for 2009 through a combination of cash flow retained by the
business and debt, if needed.
Commitments
We have contracted to transport 143 MMcf/day of natural gas on the
TransCanada system in Alberta, 70 MMcf/day on TransGas in Saskatchewan, 48
MMcf/day in B.C.via Spectra, as well as 9 MMcf/day on the Alliance pipeline to
the U.S. Midwest.
Our gas supply dedicated to aggregator sales contracts will decline in
2009 to approximately 6% of gas production (22.0 MMcf/day), down from more
than 20% in 2008. The early truncation of the ProGas and Cargill aggregator
pools leaves Pan-Alberta as the only remaining aggregator. Under these
arrangements, we receive a price based on the average netback price of the
pool, net of transportation costs incurred by the aggregator, for the life of
the reserves.
In addition, we also have a contract to transport a minimum of 2,480
bbls/day of crude oil from field locations to suitable marketing sales points
within western Canada.
Our Canadian and U.S. office leases expire in 2014 and 2011 respectively.
Annual costs of these lease commitments include rent and operating fees. The
Fund's commitments, contingencies and guarantees are more fully described in
Note 13.
As at December 31, 2008 Enerplus has the following minimum annual
commitments including long-term debt:
Total
Committ-
Minimum Annual Commitment Each Year ed
---------------------------------------------- after
($ millions) Total 2009 2010 2011 2012 2013 2013
-------------------------------------------------------------------------
Bank credit
facility(1) $380.9 $ - $380.9 $ - $ - $ - $ -
Senior unsecured
notes(1)(2) 323.2 - 53.7 64.6 64.6 64.6 75.7
Pipeline
commitments 62.7 18.8 11.8 9.1 6.7 5.4 10.9
Processing
commitments 25.6 7.6 7.7 7.3 3.0 - -
Office leases 69.6 8.7 11.7 12.5 12.6 12.6 11.5
-------------------------------------------------------------------------
Total
commitments(3) $862.0 $ 35.1 $465.8 $ 93.5 $ 86.9 $ 82.6 $ 98.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Interest payments have not been included since future debt levels and
interest rates are not known at this time.
(2) Includes the economic impact of derivative instruments directly
related to the senior unsecured notes (CCIRS and foreign exchange
swap - see Note 12).
(3) Crown and surface royalties, lease rentals, mineral taxes, and
abandonment and reclamation costs (hydrocarbon production rights)
have not been included as amounts paid depend on future ownership,
production, prices and the legislative environment.
Accumulated Deficit
We have historically paid cash distributions in excess of accumulated
earnings as cash distributions are based on the actual cash flow generated in
the period, whereas accumulated earnings are based on net income which
includes non-cash items such as DDA&A charges, derivative instrument
mark-to-market gains and losses, unit based compensation charges and future
income tax provisions.
Trust Unit Information
We had 165,590,000 trust units outstanding at December 31, 2008 compared
to 129,813,000 trust units outstanding at December 31, 2007.
Included in the December 31, 2008 outstanding units were 30,150,000 units
issued on February 13, 2008 to acquire Focus. In addition 9,087,000
exchangeable partnership units were assumed on the Focus acquisition which
became exchangeable into Enerplus trust units at the ratio of 0.425 of a trust
unit for each partnership unit. During 2008 1,849,000 partnership units were
converted into 786,000 trust units, leaving 7,238,000 partnership units
outstanding at December 31, 2008 representing the equivalent of 3,076,000
trust units.
In addition 1,881,000 trust units (2007 - 1,307,000) 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 $70.5 million (2007 - $56.8 million) of additional equity to the
Fund. For further details see Note 10.
The weighted average basic number of trust units outstanding during 2008
was 160,589,000 compared to 127,691,000 trust units during 2007. At February
20, 2009 we had 165,707,000 trust units outstanding including the equivalent
limited partnership units.
Income Taxes
The following is a general discussion of the Canadian and U.S. tax
consequences of holding Enerplus trust units as capital property. The summary
is not exhaustive in nature and is not intended to provide legal or tax
advice. Investors or potential unitholders should consult their own legal or
tax advisors as to their particular tax consequences.
Canadian Unitholders
We qualify as a mutual fund trust under the Income Tax Act (Canada) and
accordingly, trust units of Enerplus are qualified investments for RRSPs,
RRIFs, RESPs, DPSPs and TFSAs. Each year we have historically transferred all
of our taxable income to the unitholders by way of distributions.
In computing income, unitholders are required to include the taxable
portion of distributions received in that year. An investor's adjusted cost
base ("ACB") in a trust unit equals the purchase price of the trust unit less
any non-taxable cash distributions received from the date of acquisition. To
the extent a unitholder's ACB is reduced below zero, such amount will be
deemed to be a capital gain to the unitholder and the unitholder's ACB will be
brought to $nil.
We paid $4.89 per trust unit in cash distributions to unitholders on
record during 2008. For Canadian tax purposes, approximately 2% of these
distributions, or $0.08 per trust unit was a tax deferred return of capital,
approximately 98% or $4.81 per trust unit was taxable to unitholders as other
income, and there was no eligible dividend income.
For 2009, we estimate that 95% of cash distributions will be taxable and
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.
U.S. Unitholders
U.S. unitholders who received cash distributions were subject to at least
a 15% Canadian withholding tax. The withholding tax is applied to both the
taxable portion of the distribution as computed under Canadian tax law and the
non-taxable portion of the distribution. U.S. taxpayers may be eligible for a
foreign tax credit with respect to Canadian withholding taxes paid.
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. The
15% preferred rate of tax on "Qualified Dividends" is currently scheduled to
expire in 2010. We are unable to determine whether or to what extent the
preferred rate of tax on "Qualified Dividends" may be extended.
We paid US$4.77 per trust unit to U.S. residents during the 2008 calendar
year of which 8% or US$0.38 per trust unit was a tax deferred return of
capital and 92% or US$4.39 per unit was a taxable qualified dividend.
For 2009, we estimate that 90% of cash distributions will be taxable to
most U.S. investors and 10% will be a tax deferred return of capital. Actual
taxable amounts may vary depending on actual distributions which are dependent
upon production, commodity prices and cash flow experienced throughout the
year.
Quarterly Financial Information
In general, crude oil and natural gas sales increased from 2007 to mid
2008 due to increased production and increased commodity prices. Oil and gas
sales decreased during the second half of 2008 as a result of the sharp
decline in commodity prices.
Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating costs and
changes in future tax provisions due to the SIFT tax and corporate rate
reductions. Furthermore, changes in the fair value of our commodity derivative
instruments and other financial instruments cause net income to continually
fluctuate between quarters.
Quarterly Financial
Information Oil and Net Income
(CDN$ millions, except Gas Net Per Trust Unit
per trust unit amounts) Sales(1) Income Basic Diluted
-------------------------------------------------------------------------
2008
Fourth Quarter $ 418.3 $ 189.5 $ 1.15 $ 1.15
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 $ 2,304.2 $ 888.9 $ 5.54 $ 5.53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Summary Fourth Quarter Information
In comparing the fourth quarter of 2008 with the same period in 2007:
- Average daily production increased 21% to 97,702 BOE/day primarily
due to the acquisition of Focus.
- The average selling price per BOE decreased 11% to $46.54 due to a
significant drop in crude oil prices in the fourth quarter of 2008.
- Cash flow increased to $258.5 million in 2008 compared to
$205.1 million in 2007 due to increased production offset by lower
crude oil prices.
- Net income increased 92% from the fourth quarter of 2007 to
$189.5 million due to increased commodity derivative instrument
gains and increased production.
- The payout ratio decreased 19% compared to the fourth quarter of
2007 as a result of higher cash flow during the fourth quarter of
2008.
- Cash distributions per unit were reduced during the fourth quarter
of 2008 which resulted in a 20% decrease from the fourth quarter of
2007.
- Operating expenses, including non-cash amounts, increased by 10% to
$9.44/BOE from $8.57/BOE during the fourth quarter of 2007 due to
increased service rig activity and repairs and maintenance.
- G&A expenses, including non-cash amounts, decreased 14% on a BOE
basis to $1.89/BOE from $2.21/BOE in the fourth quarter of 2007 due
to lower compensation costs.
- Development capital spending increased 89% compared to the fourth
quarter of 2007 due to a larger capital development program that
included the Focus properties, along with accelerated capital
spending at several locations.
The following tables provide an analysis of key financial and operating
results for the three months ended December 31, 2008 and 2007.
Three Months Three Months
Ended Ended
December 31, December 31,
(CDN$ millions, except per unit amounts) 2008 2007
-------------------------------------------------------------------------
Financial (000's)
Net Income $ 189.5 $ 98.7
Cash Flow from Operating Activities $ 258.5 $ 205.1
Cash Distributions to Unitholders(1) $ 167.0 $ 163.4
Financial per Unit(2)
Net Income $ 1.15 $ 0.76
Cash Flow from Operating Activities $ 1.56 $ 1.58
Cash Distributions to Unitholders(1) $ 1.01 $ 1.26
Payout Ratio(3) 65% 80%
Average Daily Production 97,702 80,959
Selected Financial Results per BOE(4)
Oil and Gas Sales(5) $ 46.54 $ 52.33
Royalties (8.61) (9.83)
Commodity Derivative Instruments 3.54 (0.08)
Operating Costs (9.46) (8.53)
General and Administrative (1.71) (1.94)
Interest and Foreign Exchange (2.73) (1.70)
Taxes 0.92 (1.70)
Restoration and Abandonment (0.53) (0.75)
-------------------------------------------------------------------------
Cash Flow from Operating Activities
before changes in non-cash working capital $ 27.96 $ 27.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted Average Number of Units
Outstanding (thousands) 165,373 129,658
Development Capital 200.3 106.1
Net Wells Drilled 174 76
Success Rate 99% 100%
Average Benchmark Pricing
AECO natural gas - monthly index (CDN$/Mcf) $ 6.79 $ 6.00
AECO natural gas - daily index (CDN$/Mcf) $ 6.68 $ 6.14
NYMEX natural gas - monthly NX3 index
(US$/Mcf) $ 6.77 $ 7.03
NYMEX natural gas - monthly NX3 index: CDN$
equivalent (CDN$/Mcf) $ 8.26 $ 6.89
WTI crude oil (US$/bbl) $ 58.73 $ 90.68
WTI crude oil: CDN$ equivalent (CDN$/bbl) $ 71.62 $ 88.90
CDN$/US$ exchange rate 0.82 1.02
-------------------------------------------------------------------------
(1) Calculated based on distributions paid or payable. Cash distributions
to unitholders per unit may not correspond to actual distributions of
$1.01 per trust unit as a result of using the annual weighted average
trust units outstanding.
(2) Based on weighted average trust units outstanding.
(3) Based on cash distributions divided by cash flow from operating
activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Selected Quarterly Canadian and U.S. Financial Results
(CDN$ Three months ended Three months ended
millions, December 31, 2008 December 31, 2007
except per
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Average Daily
Production Volumes
Natural gas
(Mcf/day) 333,046 13,393 346,439 245,219 12,196 257,415
Crude oil
(bbls/day) 26,122 9,312 35,434 24,248 9,973 34,221
Natural gas
liquids
(bbls/day) 4,529 - 4,529 3,836 - 3,836
Total daily
sales
(BOE/day) 86,158 11,544 97,702 68,953 12,006 80,959
Pricing(1)
Natural gas
(per Mcf) $ 7.01 $ 4.81 $ 6.92 $ 5.91 $ 5.98 $ 5.91
Crude oil
(per bbl) $ 54.85 $ 56.02 $ 55.16 $ 68.94 $ 80.16 $ 72.21
Natural gas
liquids
(per bbl) $ 43.55 $ - $ 43.55 $ 58.12 $ - $ 58.12
Capital
Expenditures
Development
capital and
office $ 186.7 $ 18.1 $ 204.8 $ 94.3 $ 13.7 $ 108.0
Acquisitions
of oil
and gas
properties $ 1.3 $ 0.1 $ 1.4 $ 5.0 $ 0.1 $ 5.1
Dispositions
of oil
and gas
properties $ (0.2) $ - $ (0.2) $ (0.4) $ (3.6) $ (4.0)
Revenues
Oil and gas
sales(1) $ 364.4 $ 53.9 $ 418.3 $ 309.5 $ 80.3 $ 389.8
Royalties $ (65.8) $(11.6)(2) $ (77.4) $ (56.1) $(17.1)(2) $ (73.2)
Commodity
derivative
instru-
ments gain/
(loss) $ 161.2 $ - $ 161.2 $ (48.8) $ - $ (48.8)
Expenses
Operating $ 80.0 $ 4.8 $ 84.8 $ 61.0 $ 2.8 $ 63.8
General and
adminis-
trative $ 13.9 $ 3.1 $ 17.0 $ 16.5 $ (0.1) $ 16.4
Depletion,
depreciation,
amortization
and
accretion $ 142.9 $ 24.1 $ 167.0 $ 89.9 $ 21.8 $ 111.7
Current
income
taxes $ (8.2) $ (0.1) $ (8.3) $ - $ 12.6 $ 12.6
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) Royalties include U.S. state production tax.
Critical Accounting Policies
The financial statements have been prepared in accordance with GAAP. A
summary of significant accounting policies is presented in Note 1. A
reconciliation of differences between Canadian and United States GAAP is
presented in Note 15. Most accounting policies are mandated under GAAP
however, in accounting for oil and gas activities, we have a choice between
the full cost and the successful efforts methods of accounting.
We apply the full cost method of accounting for oil and natural gas
activities. Under the full cost method of accounting, all costs of acquiring,
exploring and developing oil and natural gas properties are capitalized,
including unsuccessful drilling costs and administrative costs associated with
acquisitions and development. Under the successful efforts method of
accounting, all exploration costs, except costs associated with drilling
successful exploration wells, are expensed in the period in which they are
incurred. The difference between these two methodologies is not expected to be
significant to the Fund's net income or net income per unit as the majority of
the Fund's drilling activity is not exploratory in nature and is more focused
on low risk development drilling that has traditionally achieved high success
rates.
Under the full cost method of accounting, an impairment test is applied
to the overall carrying value of property, plant and equipment, on a country
by country cost centre basis with the reserves valued using estimated future
commodity prices at period end. Under the successful efforts method of
accounting, the costs are aggregated on a property-by-property basis. The
carrying value of each property is subject to an impairment test. Each method
of accounting may generate a different carrying value of property, plant and
equipment and a different net income depending on the circumstances at period
end. Net costs related to operating and administrative activities during the
development of large capital projects are capitalized until commercial
production has commenced and are tested for impairment separately under full
cost accounting.
Critical Accounting Estimates
The preparation of financial statements in accordance with GAAP requires
management to make certain judgments and estimates. Due to the timing of when
activities occur compared to the reporting of those activities, management
must estimate and accrue operating results and capital spending. Changes in
these judgments and estimates could have a material impact on our financial
results and financial condition.
Reserves
The process of estimating reserves is critical to several accounting
estimates. It requires significant judgments based on available geological,
geophysical, engineering and economic data. These estimates may change
substantially as data from ongoing development and production activities
becomes available, and as economic conditions impacting oil and gas prices,
operating costs and royalty burdens change. Reserve estimates impact net
income through depletion, the determination of asset retirement obligations
and the application of an impairment test. Revisions or changes in the reserve
estimates can have either a positive or a negative impact on net income and
the asset retirement obligation.
Asset Retirement Obligation
Management calculates the asset retirement obligation based on estimated
costs to abandon and reclaim its net ownership interest in all wells and
facilities and the estimated timing of the costs to be incurred in future
periods. The fair value estimate is capitalized to PP&E as part of the cost of
the related asset and amortized over its useful life.
Business Combinations
Management makes various assumptions in determining the fair values of
any acquired company's assets and liabilities in a business combination. The
most significant assumptions and judgments made relate to the estimation of
the fair value of the oil and gas properties. To determine the fair value of
these properties, we estimate (a) oil and gas reserves in accordance with NI
51-101 reserve standards, and (b) future prices of oil and gas.
Commodity Prices
Management's estimates of future crude oil and natural gas prices are
critical as these prices are used to determine the carrying amount of PP&E,
assess impairment in our cost centers, and determine the change in fair value
of financial contracts. Management's estimates of prices are based on the
price forecast from our reserve engineers and the current forward market.
Trust Unit Rights
Management calculates the fair value of rights granted under our trust
unit rights incentive plan using a binomial lattice option-pricing model. This
process involves the use of significant estimates and assumptions which may
change over time. The values calculated under the option-pricing model may not
reflect the actual value realized by trust unit rights holders, especially in
times of decreasing commodity prices and trust unit values.
Derivative Financial Instruments
We utilize derivative financial instruments to manage our exposure to
market risks relating to commodity prices, foreign currency exchange rates and
interest rates. Fair values of derivative contracts fluctuate depending on the
underlying estimate of future commodity prices, foreign currency exchange
rates, interest rates and counterparty credit risk.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
Current Year Accounting Changes
Effective January 1, 2008, the Fund adopted three new accounting
standards that were issued by the Canadian Institute of Chartered Accountants
("CICA"): Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures and Section 3863, Financial Instruments -
Presentation.
Capital Disclosures
Section 1535 establishes standards for disclosing information regarding
an entity's capital and how it is managed.
Financial Instruments - Disclosures, Financial Instruments - Presentation
Sections 3862 and 3863 establish standards for enhancing financial
statements users' understanding of the significance of financial instruments
to an entity's financial position, performance and cash flows. They require
that entities provide disclosures regarding the nature and extent of risks
arising from financial instruments to which they are exposed both during the
reporting period and at the balance sheet date, as well as how the entities
manage those risks.
These standards were adopted prospectively.
Future Accounting Changes
Goodwill and Intangible Assets
In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards concerning
goodwill are unchanged from the standards included in the previous Section
3062. The Trust is currently evaluating the impact of the adoption of this new
Section, however does not expect a material impact on its Consolidated
Financial Statements.
Convergence of Canadian GAAP with International Financial Reporting
Standards ("IFRS")
In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP being converged with IFRS by 2011 for
public reporting entities. On February 13, 2008 the AcSB confirmed that IFRS
will be required for public companies beginning January 1, 2011.
In order to meet our reporting requirements and transition to IFRS we
have established a project team comprised of individuals from Finance,
Information Systems and Business Solutions, Tax, Investor Relations and
Management. Our transition plan consists of four main phases:
- An IFRS diagnostic phase which involves an assessment of the
differences between Canadian GAAP and IFRS,
- An assessment and selection phase whereby we will determine
accounting policies for transition and our continuing IFRS accounting
policies,
- An evaluation of our information systems, business processes,
procedures and controls to support the new reporting standards, and
- Training and development.
To date we have completed our IFRS diagnostic assessment and have started
to analyze and identify accounting policy choices, which include assessing the
impact on information systems and business processes. We have also provided
training to certain business groups which are impacted. We intend to generate
financial information in accordance with IFRS during 2010 to provide
comparative information for the 2011 financial statements.
The transition from current Canadian GAAP to IFRS is a significant
undertaking that may materially affect our reported financial position and
results of operations. As we have not yet determined our accounting policies,
we are unable to quantify the impact of adopting IFRS on our financial
statements. In addition, due to anticipated changes to IFRS and International
Accounting Standards prior to our adoption of IFRS, our plan is subject to
change based on new facts and circumstances that arise after the date of this
MD&A.
RISK FACTORS AND RISK MANAGEMENT
Commodity Price Risk
Enerplus' operating results and financial condition are dependent on the
prices we receive for our crude oil and natural gas production. These prices
have fluctuated widely in response to a variety of factors including global
and domestic demand, weather conditions, the supply and price of imported oil
and liquefied natural gas, the production and storage levels of North American
natural gas, political stability, transportation facilities, the price and
availability of alternative fuels and government regulations.
We may use financial derivative instruments and other hedging mechanisms
to help limit the adverse effects of natural gas and crude oil price
volatility. However, we do not hedge all of our production and expect
there will always be a portion that remains un-hedged. Furthermore, we
may use financial derivative instruments that offer only limited
protection within selected price ranges. To the extent price exposure is
hedged, we may forego the benefits that would otherwise be experienced if
commodity prices increase, and may be exposed to risk of default by the
counterparties. Refer to the "Price Risk Management" section.
Credit Facility Risk and Credit Exposure
Recent economic conditions have negatively affected the availability of
credit and increased the risk that certain counterparties for our oil and gas
sales, financial derivatives, and our operating partners may fail to pay.
Enerplus has drawn only approximately 27% of its $1.4 billion bank credit
facility at December 31, 2008. Also approximately 70% of the commitments
under this facility are represented by major Canadian banks which are
considered to be among the most sound credit providers. When the time
comes to renew our banking facility we expect to pay higher rates and
there is no guarantee that all our banks will renew at their current
commitment levels.
There are normal credit risks with receivables associated with our
product sales, derivative contracts, insurers and joint venture partners.
We mitigate these risks through diversification and review processes that
assess and monitor our counterparties' credit worthiness on a regular
basis. If the current low commodity prices and uncertain credit markets
prevail there is a risk of increasing bad debts.
See the "Liquidity and Capital Resources" section for further information
related to our credit facility and credit exposure.
Access to Capital Markets
Historically access to capital has allowed us to fund a portion of our
acquisitions and development capital program through equity and debt and as a
result, distribute the majority of our cash flow to our unitholders. Recently,
with global capital markets in turmoil and the sharp decline in commodity
prices, we have chosen to reduce our reliance on the capital markets by
balancing the level of capital spending and distributions more closely to our
cash flow. Nonetheless, it will be difficult to pursue material acquisitions
and value creation opportunities without accessing the capital markets in the
future. We expect the debt markets will recover but the cost of debt financing
will increase and credit capacity may be tight for the next few years. The
equity capital markets are showing some signs of recovery however, equity
issues are generally at higher discounts and smaller sizes than previously
experienced. Equity market receptivity depends in large part upon the market's
expectation for oil and natural gas prices. Continued access to capital is
also dependent on our ability to maintain our track record of performance and
to demonstrate the advantages of the acquisition or development program that
we are financing at the time.
We are listed on the Toronto and New York stock exchanges and maintain an
active investor relations program.
We maintain a prudent capital structure by retaining a portion of cash
flow for capital spending and utilizing the equity markets when deemed
appropriate.
Oil and Gas Reserves and Resources Risk
The value of our trust units are based on, among other things, the
underlying value of the oil and gas reserves and resources. Geological and
operational risks along with product price forecasts can affect the quantity
and quality of reserves and resources and the cost of ultimately recovering
those reserves and resources. Lower crude oil and natural gas prices may
increase the risk of write-downs for our oil and gas property investments.
Regulatory changes to reporting practices can also result in reserve or
resource write-downs.
We strive to acquire low risk, properties with a high proportion of
proved reserves, positive operating metrics, long reserve lives and
predictable production. Similarly, we generally participate in lower-risk
development projects. If we do engage in exploration it is usually
in areas where there is potential for larger scale resource development
if successful.
Each year, independent engineers evaluate a significant portion of our
proved and probable reserves as well as the resources attributable to our
oil sands properties.
Sproule Associates Limited ("Sproule") evaluated 93% of the total proved
plus probable value (discounted at 10%) of our Canadian conventional
year-end reserves, in accordance with NI 51-101 and has reviewed the
remainder of the reserves which Enerplus evaluated internally.
Netherland, Sewell & Associates Inc. ("NSA") of Dallas, Texas, evaluated
100% of the reserves attributed to our assets in the United States and
utilized Sproule's forecast and constant price and cost assumptions as of
December 31, 2008 to maintain consistency. GLJ Petroleum Consultants Ltd.
("GLJ") evaluated the resources attributable to all our oil sands areas.
The Reserves Committee of the Board of Directors has reviewed and
approved the reserve and resource reports of the independent evaluators.
Strategy Post 2010
We continue to evaluate alternatives to our income trust structure beyond
2010 in response to the Canadian Federal Government's plan to tax income
trusts effective January 1, 2011.
We are currently hesitant to make structural changes for the next two
years unless opportunities arise, as we believe this exemption period has
value for our unitholders. Unless circumstances change within the current
capital markets or the regulatory, tax or political environment, we will most
likely convert into a dividend paying corporation however, we are keeping our
options open at this time.
We do not expect the conversion to a corporation to have a major impact
on our underlying operating strategy or business affairs. We expect such a
conversion can be achieved without creating a taxable event for most
unitholders. However, going forward, the tax treatment of our distributions or
dividends may be different for our unitholders/shareholders depending on their
jurisdiction and whether they are holding their investment in a taxable
account or tax-deferred account.
After 2010, the applicable Canadian income tax rate at the entity level
will be similar whether we remain a trust or convert to a corporation. The
most important variables that will determine the level of cash taxes incurred
in a given year will be the price of crude oil and natural gas, capital
spending and the amount of tax pools at the time of conversion.
With the current forward market for commodity prices and our current
plans with respect to production, costs and capital spending, we would not
expect a significant change to our overall tax costs until 2013 even if we
were to convert to a corporation during 2010. Even after 2013 we expect our
capital spending will help shelter taxes and would expect cash taxes to
average around 15% of cash flow, which is not dissimilar to other oil and gas
production companies.
If crude oil and natural gas prices were to strengthen beyond the levels
anticipated by the current forward market, our tax pools would be utilized
more quickly and we may experience higher than expected cash taxes.
We must emphasize it is difficult to give guidance on future taxability
as we operate within an industry that constantly changes given acquisitions,
divestments, capital spending, distributions and overall commodity prices.
Regulatory Risk
Government royalties, income tax laws, environmental laws and regulatory
requirements can have a significant financial and operational impact on us. In
the province of Alberta a new royalty regime came into effect on January 1,
2009. The Canadian Federal Government enacted a new tax on publicly traded
income trusts and limited partnerships, the SIFT tax, effective January 1,
2011. In early 2008 the Canadian government presented a long term plan to
reduce greenhouse gas emissions, with the intent of issuing draft regulations
in the fall of 2008. The draft regulations have been delayed as the federal
government considers aligning its approach in this area with that of the new
administration in the U.S. Accordingly the cost impact to our business remains
uncertain.
Our operations expose us to possible regulatory changes and greater
emphasis on regulatory requirements by both the Canadian and U.S. governments.
As an oil and gas producer, we are subject to a broad range of regulatory
requirements. Similarly, as a mutual fund trust, we have a unique structure
that is vulnerable to changes in legislation or income tax law.
Although we have no control over these regulatory risks, we continuously
monitor changes in these areas by participating in industry
organizations, conferences, exchanging information with third party
experts and employing qualified individuals to assess the impact of such
changes on our financial and operating results. In 2008 we also initiated
an extensive review of the regulatory compliance obligations across our
full business in all jurisdictions. We intend to complete this review in
2009.
Production Replacement Risk
Oil and natural gas reserves naturally deplete as they are produced over
time. Our ability to replace production depends on our success in acquiring
new reserves and resources and developing existing reserves and resources. We
have reduced our capital spending plans dramatically for 2009 and this will
make it difficult to replace our production without relying on acquisitions.
Acquisitions of oil and gas assets depend on our assessment of value at the
time of acquisition. Incorrect assessments of value may adversely affect
distributions to unitholders and the value of our trust units.
Acquisitions and our development capital program are subject to
investment guidelines, due diligence and review. Major acquisitions are
approved by the Board of Directors and where appropriate, independent
reserve engineer evaluations are obtained.
Access to Transportation Capacity
Market access for crude oil and natural gas production in Canada and the
United States is dependent on our ability to access sufficient transportation
capacity on third party pipelines to transport all production volumes. While
the third party pipelines generally expand capacity to meet market needs,
there can be differences in timing between the growth of production and the
growth of pipeline capacity. There are also occasionally operational reasons
for curtailing transportation capacity. Accordingly, there can be periods
where transportation capacity is insufficient to accommodate all of the
production from a given region, causing added expense and/or volume
curtailments for all shippers.
We continuously monitor this risk for both the short and longer term
through dialogue with the third party pipelines and other market
participants, as well as by review of supply and demand studies prepared
by third party experts. Where available and commercially appropriate
given the production profile and commodity, we attempt to mitigate this
risk by contracting for firm transportation capacity or using other means
of transportation.
Health, Safety and Environmental Risk ("HSE")
Health, safety and environmental risks influence the workforce, operating
costs and the establishment of regulatory standards.
We have established a HSE Management System designed to:
- provide staff with the training and resources needed to complete work
safely and effectively;
- incorporate hazard assessment and risk management as an integral part
of everyday business;
- monitor performance to ensure that our operations comply with legal
obligations and the standards we set for ourselves; and
- identify and manage environmental liabilities associated with our
existing asset base and potential acquisitions.
We have a site inspections program and a corrosion risk management
program designed to ensure compliance with environmental laws and
regulations. We carry insurance to cover a portion of our property
losses, liability and business interruption. HSE risks are reviewed
regularly by the HSE committee comprised of members of the Board of
Directors.
Foreign Currency Exposure
We have exposure to fluctuations in foreign currency as our senior
unsecured notes are denominated in U.S. dollars. Our U.S. operations are
directly exposed to fluctuations in the U.S. dollar when translated to our
Canadian dollar denominated financial statements.
We also have indirect exposure to fluctuations in foreign currency as our
crude oil sales and a portion of our natural gas sales are based on U.S.
dollar indices. Our oil and gas revenues are positively impacted as the
Canadian dollar weakens relative to the U.S. dollar.
We have hedged our foreign currency exposure on both our US$175 million
and US$54 million senior unsecured notes using financial swaps that
convert the U.S. denominated debt to Canadian dollar debt. In addition we
have hedged our interest obligation on our US$175 million notes.
We have not entered into any other foreign currency derivatives with
respect to oil and gas sales or our U.S. operations.
Interest Rate Exposure
We have exposure to movements in interest rates and credit markets as
changing interest rates affect our borrowing costs and the trust unit price of
yield-based investments such as our trust units.
We monitor the interest rate forward market and have fixed the interest
rate on approximately 28% of our debt through our senior unsecured notes
and interest rate swaps.
Non-Resident Ownership and Mutual Fund Trust Status
Based on information received from our transfer agent and financial
intermediaries in February 2009, an estimated 65% of our outstanding trust
units were held by non-residents. This estimate may not be accurate as it is
based on certain assumptions and data from the securities industry that does
not have a well-defined methodology to determine the residency of beneficial
holders of securities.
We currently meet the requirements of a mutual fund trust as defined in
the Income Tax Act (Canada). Our trust indenture does not have a specific
limit on the percentage of trust units that may be owned by non-
residents. At this time, we do not anticipate any legislative changes
that would affect our status as a mutual fund trust.
SUMMARY 2009 OUTLOOK
Enerplus offers investors the benefits of owning a large, diversified
portfolio of producing crude oil and natural gas properties within Canada and
the United States. As such, our business prospects are closely linked to the
opportunities and challenges associated with oil and natural gas production.
In particular, we are strongly influenced by the price of crude oil and
natural gas, both of which have been volatile in recent years. Our comments
with respect to our 2009 outlook should be taken within the context of the
current commodity price environment.
The following summarizes our 2009 guidance as provided throughout this
MD&A. We do not attempt to forecast commodity prices and, as a result, we do
not forecast future cash flow or cash distributions. Readers are encouraged to
apply their own price expectations to the following factors to arrive at an
expected cash distribution.
Summary of 2009
Expectations Target Comments
-------------------------------------------------------------------------
Average annual production 91,000 BOE/day Does not include any
further potential
acquisitions/divestments
Exit rate 2009 production 88,000 BOE/day Assumes $300 million
development capital
spending
2009 production mix 58% gas, 42%
liquids
Average royalty rate 18% Percentage of gross sales
Operating costs $10.65/BOE
G&A costs $2.45/BOE Includes non-cash charges
of $0.20/BOE (unit rights
incentive plan)
U.S. income and 15% Applied to net cash flow
withholding tax - cash generated by U.S.
costs operations and assumes
repatriation of the funds
to Canada after U.S.
development capital
spending
Average interest cost 3% Based on current fixed rate
contracts and forward
market
Payout ratio 50% - 75% We intend to manage our
distributions and capital
spending in order to
minimize increases in debt
outside of acquisitions
Development capital $300 million We intend to monitor
spending commodity prices and cost
structures and will adjust
capital spending in order
to minimize increases in
debt outside of
acquisitions
-------------------------------------------------------------------------
We believe it is important to maintain a conservative balance sheet as a
defense against commodity price changes and to be positioned to capture
acquisition opportunities. As a result, we have reduced our 2009 development
capital spending to $300 million, which is 48% lower than our 2008 spending.
We have also reduced our monthly distributions to unitholders to $0.18 per
trust unit and based on current commodity prices we do not expect to
materially increase our debt levels in 2009 outside of acquisition activities.
We will continue to focus on low-risk development opportunities and
review our risk management strategies in response to changing prices, the
current economic environment and the economics of our acquisition and
development projects.
For 2009, we estimate that 95% of cash distributions will be taxable and
5% will be a tax-deferred return of capital for our Canadian unitholders. For
our U.S. unitholders, we estimate that 90% of cash distribution will be
taxable and 10% will be a tax-deferred return of capital.
CONSOLIDATED BALANCE SHEETS
As at December 31 (CDN$ thousands) 2008 2007
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 6,922 $ 1,702
Accounts receivable 163,152 145,602
Deferred financial assets (Note 12) 121,281 10,157
Future income taxes (Note 11) - 10,807
Other current 3,783 6,373
-------------------------------------------------------------------------
295,138 174,641
Property, plant and equipment (Note 3) 5,246,998 3,872,818
Goodwill (Note 1(f)) 634,023 195,112
Deferred financial assets (Note 12) 6,857 -
Other assets 47,116 60,559
-------------------------------------------------------------------------
$ 6,230,132 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 272,818 $ 269,375
Distributions payable to unitholders 41,397 54,522
Future income taxes (Note 11) 30,198 -
Deferred financial credits (Note 12) - 52,488
-------------------------------------------------------------------------
344,413 376,385
-------------------------------------------------------------------------
Long-term debt (Note 7) 664,343 726,677
Deferred financial credits (Note 12) 26,392 90,090
Future income taxes (Note 11) 648,821 304,259
Asset retirement obligations (Note 4) 207,420 165,719
-------------------------------------------------------------------------
1,546,976 1,286,745
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 10)
Trust Units and Trust Units Equivalent
Authorized: Unlimited
Issued and Outstanding: 2008 - 165,590,240
2007 - 129,813,445 5,471,336 4,032,680
Accumulated deficit (1,181,199) (1,283,953)
Accumulated other comprehensive income
(Notes 1(i) and (j)) 48,606 (108,727)
-------------------------------------------------------------------------
(1,132,593) (1,392,680)
4,338,743 2,640,000
-------------------------------------------------------------------------
$ 6,230,132 $ 4,303,130
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
For the year ended December 31 (CDN$ thousands) 2008 2007
-------------------------------------------------------------------------
Accumulated income, beginning of year $ 2,286,927 $ 1,952,960
Adjustment for adoption of financial
instruments standards - (5,724)
-------------------------------------------------------------------------
Revised Accumulated income, beginning of year 2,286,927 1,947,236
Net income 888,892 339,691
-------------------------------------------------------------------------
Accumulated income, end of year 3,175,819 2,286,927
Accumulated cash distributions, beginning of
year (3,570,880) (2,924,045)
Cash distributions (786,138) (646,835)
-------------------------------------------------------------------------
Accumulated cash distributions, end of year (4,357,018) (3,570,880)
-------------------------------------------------------------------------
Accumulated deficit, end of year $(1,181,199) $(1,283,953)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
For the year ended December 31 (CDN$ thousands) 2008 2007
-------------------------------------------------------------------------
Balance, beginning of year $ (108,727) $ (8,979)
Transition adjustments:
Cash flow hedges - 660
Available for sale marketable securities - 14,252
Other comprehensive (loss)/income 157,333 (114,660)
-------------------------------------------------------------------------
Balance, end of year $ 48,606 $ (108,727)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
For the year ended December 31
(CDN$ thousands except per trust
unit amounts) 2008 2007
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 2,331,884 $ 1,539,153
Royalties (429,943) (285,148)
Commodity derivative instruments (Note 12) 66,434 (52,841)
Other income (Note 12) 8,464 14,991
-------------------------------------------------------------------------
1,976,839 1,216,155
-------------------------------------------------------------------------
Expenses
Operating 332,622 274,150
General and administrative 65,667 67,921
Transportation 27,650 22,098
Interest (Note 8) 24,224 33,627
Foreign exchange (Note 9) 25,852 (7,071)
Depletion, depreciation, amortization and
accretion 640,440 463,718
-------------------------------------------------------------------------
1,116,455 854,443
-------------------------------------------------------------------------
Income before taxes 860,384 361,712
Current taxes 22,722 23,011
Future income tax recovery (Note 11) (51,230) (990)
-------------------------------------------------------------------------
Net Income $ 888,892 $ 339,691
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 5.54 $ 2.66
Diluted $ 5.53 $ 2.66
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)
Basic 160,589 127,691
Diluted 160,640 127,752
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the year ended December 31
(CDN$ thousands) 2008 2007
-------------------------------------------------------------------------
Net income $ 888,892 $ 339,691
-------------------------------------------------------------------------
Other comprehensive (loss)/income, net of tax:
Unrealized gain on marketable securities 2,578 629
Realized gains on marketable securities
included in net income (Note 12 (b)) (6,158) (11,302)
Gains and losses on derivatives designated
as hedges in prior periods included in net
income 74 (733)
Change in cumulative translation adjustment 160,839 (103,254)
-------------------------------------------------------------------------
Other comprehensive (loss)/income 157,333 (114,660)
-------------------------------------------------------------------------
Comprehensive income $ 1,046,225 $ 225,031
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the year ended December 31
(CDN$ thousands) 2008 2007
-------------------------------------------------------------------------
Operating Activities
Net income $ 888,892 $ 339,691
Non-cash items add/(deduct):
Depletion, depreciation, amortization and
accretion 640,440 463,718
Change in fair value of derivative instruments
(Note 12) (240,085) 91,852
Unit based compensation (Note 10 (d)) 6,996 8,435
Foreign exchange on translation of senior
notes (Note 9) 54,792 (41,182)
Future income tax (Note 11) (51,230) (990)
Impairment of marketable securities 10,000 -
Amortization of senior notes premium (668) (631)
Reclassification adjustments from AOCI to net
income and other 92 (865)
Gain on sale of marketable securities (Note 12) (8,263) (14,055)
Asset retirement obligations settled (Note 4) (18,308) (16,280)
-------------------------------------------------------------------------
1,282,658 829,693
Decrease/(Increase) in non-cash operating
working capital (19,876) 38,855
-------------------------------------------------------------------------
Cash flow from operating activities 1,262,782 868,548
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue costs
(Note 10) 70,516 256,369
Cash distributions to unitholders (786,138) (646,835)
(Decrease)/Increase in bank credit facilities
(Note 7) (447,371) 148,827
Decrease in non-cash financing working capital (13,125) 2,799
-------------------------------------------------------------------------
Cash flow from financing activities (1,176,118) (238,840)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (588,337) (393,655)
Property acquisitions (Note 6) (15,306) (226,480)
Property dispositions (Note 6) 504,859 2,947
Proceeds on sale of marketable securities 18,320 16,467
Purchase of investments (7,150) (2,927)
Increase in non-cash investing working capital (1,618) (21,046)
-------------------------------------------------------------------------
Cash flow from investing activities (89,232) (624,694)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash 7,788 (3,436)
-------------------------------------------------------------------------
Change in cash 5,220 1,578
Cash, beginning of year 1,702 124
-------------------------------------------------------------------------
Cash, end of year $ 6,922 $ 1,702
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ 73,914 $ 17,431
Cash interest paid $ 42,695 $ 42,861
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The management of Enerplus Resources Fund ("Enerplus" or the "Fund")
prepares the consolidated financial statements in accordance with
Canadian generally accepted accounting principles ("Canadian GAAP"). A
reconciliation between Canadian GAAP and United States of America GAAP
("U.S. GAAP") is disclosed in Note 15. The preparation of financial
statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosures of
contingencies, if any, as at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimated. In particular, the
amounts recorded for depletion and depreciation of the petroleum and
natural gas properties and for asset retirement obligations are based on
estimates of reserves and future costs. By their nature, these estimates,
and those related to future cash flows used to assess impairment, are
subject to measurement uncertainty and the impact on the financial
statements of future periods could be material.
The following significant accounting policies are presented to assist the
reader in evaluating these consolidated financial statements and,
together with the following notes, should be considered an integral part
of the consolidated financial statements.
(a) Organization and Basis of Accounting
The Fund is an open-end investment trust created under the laws of the
Province of Alberta operating pursuant to the Amended and Restated Trust
Indenture between EnerMark Inc. (the Fund's wholly-owned subsidiary),
Enerplus Resources Corporation ("ERC") and Computershare Trust Company of
Canada. The beneficiaries of the Fund (the "unitholders") are holders of
the trust units issued by the Fund. As a trust under the Income Tax Act
(Canada), Enerplus is limited to holding and administering permitted
investments and making distributions to the unitholders.
The Fund's financial statements include the accounts of the Fund and its
subsidiaries on a consolidated basis. All inter-entity transactions have
been eliminated. Many of the Fund's production activities are conducted
through joint ventures and the financial statements reflect only the
Fund's proportionate interest in such activities.
(b) Revenue Recognition
Revenue associated with the sale of crude oil, natural gas and natural
gas liquids is recognized when title passes from the Fund to its
customers based on price, volumes delivered and contractual delivery
points. A portion of the properties acquired through the March 5, 2003
acquisition of PCC Energy Inc. and PCC Energy Corp. are subject to a
royalty arrangement, with a private company, that is structured as a net
profits interest. The results from operations included in the Fund's
consolidated financial statements for these properties are reduced for
this net profits interest.
(c) Property, Plant and Equipment ("PP&E")
The Fund follows the full cost method of accounting for petroleum and
natural gas properties under which all acquisition and development costs
are capitalized on a country by country cost centre basis. Such costs
include land acquisition, geological, geophysical, drilling costs for
productive and non-productive wells, facilities and directly related
overhead charges. Repairs, maintenance and operational costs that do not
extend or enhance the recoverable reserves are charged to earnings.
Proceeds from the sale of petroleum and natural gas properties are
applied against the capitalized costs. Gains and losses are not
recognized upon disposition of oil and natural gas properties unless such
a disposition would alter the rate of depletion by 20% or more. Net costs
related to operating and administrative activities during the development
of large capital projects are capitalized until commercial production has
commenced.
(d) Impairment Test
A limit is placed on the aggregate carrying value of PP&E (the
"impairment test"). The Fund performs an impairment test on a country by
country basis. An impairment loss exists when the carrying amount of the
country's PP&E exceeds the estimated undiscounted future net cash flows
associated with the country's proved reserves. If an impairment loss is
determined to exist, the costs carried on the balance sheet in excess of
the discounted future net cash flows associated with the country's proved
and probable reserves are charged to income. Net costs related to
projects in the pre-commercial phase of development are excluded from the
country by country impairment test and are tested for impairment
separately.
(e) Depletion and Depreciation
The provision for depletion and depreciation of oil and natural gas
assets is calculated on a country by country basis using the unit-of-
production method, based on the country's share of estimated proved
reserves before royalties. Reserves and production are converted to
equivalent units on the basis of 6 Mcf = 1 bbl, reflecting the
approximate relative energy content.
(f) Goodwill
The Fund, when appropriate, recognizes goodwill relating to corporate
acquisitions when the total purchase price exceeds the fair value of the
net identifiable assets and liabilities of the acquired companies. The
goodwill balance is assessed for impairment annually at year-end or as
events occur that could result in an impairment. To assess impairment,
the fair values of the Canadian and U.S. reporting units are compared to
their respective book values. If the fair value is less than the book
value, a second test is performed to determine the amount of impairment.
The amount of impairment is measured by allocating the fair value of the
reporting unit to its identifiable assets and liabilities as if they had
been acquired in a business combination for a purchase price equal to
their fair value. If goodwill determined in this manner is less than the
carrying value of goodwill, an impairment is recognized in the period in
which it occurs. Goodwill is stated at cost less impairment and is not
amortized. Goodwill is not deductible for income tax purposes.
(g) Asset Retirement Obligations
The Fund recognizes as a liability the estimated fair value of the future
retirement obligations associated with PP&E. The fair value is
capitalized and amortized over the same period as the underlying asset.
The Fund estimates the liability based on the estimated costs to abandon
and reclaim its net ownership interest in all wells and facilities and
the estimated timing of the costs to be incurred in future periods. This
estimate is evaluated on a periodic basis and any adjustment to the
estimate is prospectively applied. As time passes, the change in net
present value of the future retirement obligation is expensed through
accretion. Retirement obligations settled during the period reduce the
future retirement liability. No gains or losses on retirement activities
were realized due to settlements approximating the estimates.
(h) Income Taxes
The Fund is a taxable entity under the Income Tax Act (Canada) and is
taxable only on Canadian income that is not distributed or distributable
to the Fund's unitholders. In the Trust structure, payments made between
the Canadian operating entities and the Fund ultimately transfers both
income and future income tax liability to the unitholders. The future
income tax liability associated with Canadian assets recorded on the
balance sheet is recovered over time through these payments. As the
Canadian operating entities transfer all of their Canadian taxable income
to the Fund, no provision for current Canadian income tax has been made
by any Canadian operating entity.
Effective January 1, 2011, the Fund will be subject to a 29.5% SIFT
(specified investment flow-through) tax on Canadian income that has not
been subject to a Canadian corporate income tax in the Canadian operating
entities. Therefore, the future tax liability associated with Canadian
assets recorded on the balance sheet as at that date will be realized
over time as the temporary differences between the carrying value of
assets in the consolidated financial statements and their respective tax
bases are realized. Current Canadian income taxes will be accrued for at
that time to the extent that there is taxable income in the Trust or its
underlying operating entities.
The U.S. operating entity is subject to U.S. income taxes on its taxable
income determined under U.S. income tax rules and regulations.
Repatriation of funds from U.S. operations will also be subject to
applicable withholding taxes as required under U.S. tax law.
The Fund follows the liability method of accounting for income taxes.
Under this method, income tax liabilities and assets are recognized for
the estimated tax consequences attributable to the temporary differences
between the carrying value of the assets and liabilities on the
consolidated financial statements and their respective tax bases, using
substantively enacted income tax rates. The effect of a change in these
income tax rates on future income tax liabilities and assets is
recognized in income during the period that the change occurs.
(i) Financial Instruments
The Fund is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the normal
course of operations. A variety of derivative instruments are used by the
Fund to reduce its exposure to these risks. The Fund records its
derivative instruments on the Consolidated Balance Sheet at fair value
and recognizes any change in fair value through net income during the
period. The fair values of these derivative instruments are generally
based on an estimate of the amounts that would be received or paid to
settle these instruments at the balance sheet date.
The Fund has certain minor equity investments in entities involved in the
oil and gas industry. Investments that have a quoted price in an active
market are measured at fair value with changes in fair value recognized
in other comprehensive income. When the investment is ultimately sold any
gains or losses are recognized in net income and any unrealized gains or
losses previously recognized in other comprehensive income are reversed.
Investments that do not have a quoted price in an active market are
measured at cost unless there has been an other than temporary
impairment, in which case a charge is recognized in net income to record
the loss in value.
(j) Foreign Currency Translation
The Fund's U.S. operations are self-sustaining. Assets and liabilities of
these operations are translated into Canadian dollars at period end
exchange rates, while revenues and expenses are converted using average
rates for the period. Gains and losses from the translation into Canadian
dollars are deferred and included in the cumulative translation
adjustment ("CTA") which is part of accumulated other comprehensive
income ("AOCI").
Other monetary assets and liabilities, not related to the Fund's U.S.
operations, are translated into Canadian dollars at rates of exchange in
effect at the balance sheet date. The other assets and related
depreciation, depletion and amortization, other liabilities, revenue and
other expenses are translated into Canadian dollars at rates of exchange
in effect at the respective transaction dates. The resulting exchange
gains or losses are included in earnings.
(k) Unit Based Compensation
The Fund uses the fair value method of accounting for the trust unit
rights incentive plan. Under this method, the fair value of the rights is
determined on the date in which fair value can reasonably be determined,
generally being the grant date. This amount is charged to earnings over
the vesting period of the rights, with a corresponding increase in
contributed surplus. When rights are exercised, the proceeds, together
with the amount recorded in contributed surplus, are recorded to
unitholders' capital.
2. CHANGES IN ACCOUNTING POLICIES
Current Year Accounting Changes
Effective January 1, 2008, the Fund adopted three new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook Section 1535, Capital Disclosures, Section
3862, Financial Instruments - Disclosures and Section 3863, Financial
Instruments - Presentation.
(a) Capital Disclosures
Section 1535 establishes standards for disclosing information regarding
an entity's capital and how it is managed.
(b) Financial Instruments - Disclosures, Financial Instruments -
Presentation
Sections 3862 and 3863 establish standards for enhancing financial
statements users' understanding of the significance of financial
instruments to an entity's financial position, performance and cash
flows. They require that entities provide disclosures regarding the
nature and extent of risks arising from financial instruments to which
they are exposed both during the reporting period and at the balance
sheet date, as well as how the entities manage those risks.
These standards were adopted prospectively.
Future Accounting Changes
(a) Goodwill and Intangible Assets
In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards
concerning goodwill are unchanged from the standards included in the
previous Section 3062. The Fund is currently evaluating the impact of the
adoption of this new Section, however does not expect a material impact
on its Consolidated Financial Statements.
(b) Convergence of Canadian GAAP with International Financial Reporting
Standards ("IFRS")
In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP being converged with International
Financial Reporting Standards (IFRS) by 2011 for public reporting
entities. On February 13, 2008 the AcSB confirmed that IFRS will be
required for public companies beginning January 1, 2011.
3. PROPERTY, PLANT AND EQUIPMENT
($ thousands) 2008 2007
-------------------------------------------------------------------------
Property, plant and equipment $8,497,206 $6,429,241
Accumulated depletion, depreciation and accretion (3,250,208) (2,556,423)
-------------------------------------------------------------------------
Net property, plant and equipment $5,246,998 $3,872,818
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized general and administrative ("G&A") expenses for 2008 of
$21,766,000 (2007 - $17,185,000) are included in PP&E. The depletion and
depreciation calculation includes future capital costs of $773,371,000
(2007 - $521,650,000) as indicated in our reserve reports. Excluded from
PP&E for the depletion and depreciation calculation is $257,608,000 (2007
- $321,801,000) related to the Kirby oil sands project ("Kirby") which
has not yet commenced commercial production. The 2007 amount included
costs related to the Joslyn oil sands project which was sold in July,
2008.
An impairment test calculation was performed on a country by country
basis on the PP&E values at December 31, 2008 in which the estimated
undiscounted future net cash flows associated with the proved reserves
exceeded the carrying amount of the Fund's PP&E.
The following table outlines estimated benchmark prices and the exchange
rate used in the impairment tests for both Canadian and U.S. cost centers
at December 31, 2008:
Natural Gas
Edm Light 30 day spot
WTI Crude Oil(1) Exchange Rate Crude(1) @ AECO(1)
Year US$/bbl CDN$/US$ CDN$/bbl CDN$/Mcf
-------------------------------------------------------------------------
2009 $53.73 $0.80 $65.35 $6.82
2010 63.41 0.85 72.78 7.56
2011 69.53 0.85 79.95 7.84
2012 79.59 0.90 86.57 8.38
2013 92.01 0.95 94.97 9.20
Thereafter(*) +2% yr 0.95 +2% yr +2% yr
-------------------------------------------------------------------------
(1) Prices used in the impairment test were adjusted for commodity price
differentials specific to the Fund
(*) Escalation varies after 2013.
4. ASSET RETIREMENT OBLIGATIONS
Total future asset retirement obligations were 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 $207,420,000 at December 31, 2008 compared to
$165,719,000 at December 31, 2007 based on a total undiscounted liability
of $644,423,000 and $542,781,000 respectively. These payments are
expected to be made over the next 66 years with the majority of costs
incurred between 2039 and 2048. To calculate the present value of the
asset retirement obligations for 2008 the Fund used a weighted credit-
adjusted rate of approximately 6.1% and an inflation rate of 2.0%, (2007
- 6.1% and 2.0%). Settlements during 2008 and 2007 approximated our
estimates and as a result no gains or losses were recognized.
Following is a reconciliation of the asset retirement obligations:
($ thousands) 2008 2007
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year $165,719 $123,619
Corporate acquisition 36,784 -
Changes in estimates 4,087 46,000
Acquisition and development activity 7,394 6,441
Dispositions (110) (756)
Asset retirement obligations settled (18,308) (16,280)
Accretion expense 11,854 6,695
-------------------------------------------------------------------------
Asset retirement obligations, end of year $207,420 $165,719
-------------------------------------------------------------------------
-------------------------------------------------------------------------
5. CORPORATE 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 30,150,000
trust units issued, 9,087,000 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
$357,305,000.
The acquisition has been accounted for using the purchase method of
accounting and results from the operations of Focus from February 13,
2008 onward have been included in the Fund's consolidated financial
statements. The allocation of the consideration paid to the fair value of
the assets acquired and liabilities assumed plus future income tax cost
is summarized below:
Net Assets Acquired ($ 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
6. PROPERTY ACQUISITIONS AND DISPOSITIONS
Joslyn Oil Sands Interest
On July 31, 2008 the Fund disposed of its interest in the Joslyn oil
sands project for net cash proceeds of $502,000,000.
Kirby Oil Sands Project
On April 10, 2007 the Fund acquired a 90% interest in Kirby for total
consideration of $182,800,000, consisting of $128,050,000 in cash and the
issuance of 1,104,945 trust units at a price of $49.55 per unit
($54,750,000 of equity). On June 22, 2007 the Fund acquired the remaining
10% interest in Kirby for cash consideration of $20,276,000. The
acquisition of Kirby has been accounted for as an asset acquisition
pursuant to the guidance in the Emerging Issues Committee Abstract 124.
7. LONG-TERM DEBT
($ thousands) 2008 2007
-------------------------------------------------------------------------
Bank credit facilities (a) $380,888 $497,347
Senior notes (b)
US$175 million (issued June 19, 2002) 217,327 175,973
US$54 million (issued October 1, 2003) 66,128 53,357
-------------------------------------------------------------------------
Total long-term debt $664,343 $726,677
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus has a $1.4 billion unsecured covenant based facility ($1.0
billion at December 31, 2007) that matures November 18, 2010. The
facility is extendible each year with a bullet payment required at
maturity. At December 31, 2008 Enerplus had available credit of
$1,019,112,000. Various borrowing options are available under the
facility including prime based advances and bankers' acceptances. This
facility carries floating interest rates that are expected to range
between 55 and 110 basis points over bankers' acceptance rates, depending
on Enerplus' ratio of senior debt to earnings before interest, taxes and
non-cash items. The weighted average effective interest rate on the
facility for the year ended December 31, 2008 was 3.8% (2007 - 5.1%).
(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 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, when the CDN/US dollar exchange rate was 0.74,
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 0.98 or CDN$55,080,000.
On January 1, 2007 in conjunction with the adoption of CICA Sections 3855
and 3865, the Fund 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 December 31, 2008 the amortized cost of the
US$175,000,000 senior notes was US$177,467,000.
The bank credit facility and the senior notes (the "Combined Facilities")
are the legal obligation of EnerMark Inc. and are guaranteed by its
subsidiaries. Payments with respect to the Combined Facilities have
priority over payments to the Fund and over claims of and future
distributions to the unitholders however, unitholders have no direct
liability beyond their equity investment should cash flow be insufficient
to repay the Combined Facilities.
8. INTEREST EXPENSE
($ thousands) 2008 2007
-------------------------------------------------------------------------
Realized
Interest on long-term debt $42,626 $41,934
Unrealized
Gain on cross currency interest rate swap (27,559) (7,340)
Loss/(gain) on interest rate swaps 9,825 (447)
Amortization of the premium on senior unsecured
notes (668) (631)
Other - 111
-------------------------------------------------------------------------
Interest Expense $ 24,224 $ 33,627
-------------------------------------------------------------------------
-------------------------------------------------------------------------
9. FOREIGN EXCHANGE
($ thousands) 2008 2007
-------------------------------------------------------------------------
Realized
Foreign exchange loss $ 23,881 $ 1,909
Unrealized
Foreign exchange loss/(gain) on
translation of U.S. dollar denominated
senior notes 54,792 (41,182)
Foreign exchange (gain)/loss on cross currency
interest rate swap (45,539) 31,777
Foreign exchange (gain)/loss on foreign exchange
swaps (7,282) 425
-------------------------------------------------------------------------
Foreign exchange loss/(gain) $ 25,852 $ (7,071)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed
to foreign currency fluctuations and are translated into Canadian dollars
at the exchange rate in effect at the balance sheet date. Foreign
exchange gains and losses are included in the determination of net income
for the period.
10. UNITHOLDERS' CAPITAL
Unitholders' capital as presented on the Consolidated Balance Sheets
consists of trust unit capital, exchangeable partnership unit capital and
contributed surplus.
Unitholders' capital ($ thousands) 2008 2007
-------------------------------------------------------------------------
Trust units $ 5,328,629 $ 4,020,228
Exchangeable limited partnership units 123,107 -
Contributed surplus 19,600 12,452
-------------------------------------------------------------------------
Balance, end of year $ 5,471,336 $ 4,032,680
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Trust Units
Authorized: Unlimited number of trust units
(thousands) 2008 2007
-------------------------------------------------------------------------
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance before Contributed
Surplus, beginning of year 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 210 6,755 205 6,758
Cancelled trust units (116) (3,794) - -
Exchangeable limited
partnership units exchanged 786 31,444 - -
Trust unit rights incentive
plan (non-cash) - exercised - 3,642 - 2,288
DRIP(*), net of redemptions 1,671 63,761 1,102 50,053
Issued for acquisition of
corporate and property
interests (non-cash) 30,150 1,206,593 1,105 54,750
-------------------------------------------------------------------------
162,514 5,328,629 129,813 4,020,228
Equivalent exchangeable
partnership units 3,076 123,107 - -
-------------------------------------------------------------------------
Balance, end of year 165,590 $5,451,736 129,813 $4,020,228
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Distribution Reinvestment and Unit Purchase Plan
On February 13, 2008 the Fund issued 30,150,000 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.
On April 10, 2007 the Fund closed an equity offering of 4,250,000 trust
units at a price of $49.55 per unit for gross proceeds of $210,588,000
($199,558,000 net of issuance costs).
In conjunction with the acquisition of Kirby on April 10, 2007, the Fund
issued 1,105,000 trust units at a price of $49.55 per unit for gross
proceeds of $54,750,000.
Pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan
("DRIP"), Canadian unitholders are entitled to reinvest cash
distributions in additional trust units of the Fund. Trust units are
issued at 95% of the weighted average market price on the Toronto Stock
Exchange for the 20 trading days preceding a distribution payment date
without service charges or brokerage fees. Eligible unitholders are also
entitled to make optional cash payments to acquire additional trust
units; however, the 5% discount does not apply.
Trust units are redeemable by unitholders at approximately 85% of the
current market price. Redemptions are limited to $500,000 during any
rolling two calendar months. Redemption requests in excess of $500,000
can be paid using investments of the Fund or a non-interest bearing
instrument.
(b) Exchangeable Limited Partnership Units
In conjunction with the Focus acquisition 9,087,000 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 (3,862,000 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 period February 13, 2008 to December 31, 2008, 1,849,000
exchangeable limited partnership units were converted into 786,000 trust
units. As at December 31, 2008, the 7,238,000 outstanding exchangeable
limited partnership units represent the equivalent of 3,076,000 trust
units.
(thousands) 2008 2007
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Assumed on February 13, 2008 9,087 $154,551 - $ -
Exchanged for trust units (1,849) (31,444) - -
-------------------------------------------------------------------------
Balance, end of period 7,238 $123,107 - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Contributed Surplus
Contributed surplus ($ thousands) 2008 2007
-------------------------------------------------------------------------
Balance, beginning of year $ 12,452 $ 6,305
Trust unit rights incentive plan (non-cash) -
exercised (3,642) (2,288)
Trust unit rights incentive plan (non-cash) -
expensed 6,996 8,435
Cancelled trust units 3,794 -
-------------------------------------------------------------------------
Balance, end of year $ 19,600 $ 12,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(d) Trust Unit Rights Incentive Plan
As at December 31, 2008 a total of 4,001,000 rights issued pursuant to
the Trust Unit Rights Incentive Plan ("Rights Incentive Plan") were
outstanding at an average exercise price of $45.05. This represents 2.4%
of the total trust units outstanding, of which 2,024,000 rights, with an
average exercise price of $46.44, 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 year ended
December 31, 2008 reduced the exercise price of the outstanding rights by
$1.65 per trust unit of which a $0.59 reduction is effective January 2009
and a $0.22 reduction is effective April 2009. Plan members have the
choice to exercise rights using the original exercise price or a reduced
strike price. In certain circumstances, it may be more advantageous to
use the original exercise price as it could effectively result in higher
after tax proceeds for the plan member.
The Fund uses a binomial lattice option-pricing model to calculate the
estimated fair value of rights granted under the plan. The following
assumptions were used to arrive at the estimate of fair value:
2008 2007
-------------------------------------------------------------------------
Dividend yield 12.09% 10.37%
Volatility 27.12% 26.35%
Risk-free interest rate 2.90% 4.41%
Forfeiture rate 7.30% 6.20%
Right's exercise price reduction $1.91 $1.75
-------------------------------------------------------------------------
The fair value of the rights granted under the plan during 2008 and 2007
ranged between 9% and 12% of the underlying market price of a trust unit
on the grant date.
During the year the Fund expensed $6,996,000 or $0.04 per unit (2007 -
$8,435,000 or $0.07 per unit) of unit based compensation expense using
the fair value method. The remaining future fair value of the rights of
$4,678,000 at December 31, 2008 (2007 - $6,195,000) will be recognized in
earnings over the vesting period of the rights. Activity for the rights
issued pursuant to the Rights Incentive Plan is as follows:
2008 2007
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Rights (000's) Price(1) Rights (000's) Price(1)
-------------------------------------------------------------------------
Trust unit rights
outstanding
Beginning of year 3,404 $47.59 3,079 $48.53
Granted 1,403 42.00 816 48.71
Exercised (210) 32.22 (205) 32.90
Forfeited and expired (596) 44.94 (286) 50.74
-------------------------------------------------------------------------
End of year 4,001 $45.05 3,404 $47.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable at
the end of the year 2,024 $46.44 1,635 $44.84
-------------------------------------------------------------------------
(1) Exercise price reflects grant prices less reduction in strike price
discussed above.
The following table summarizes information with respect to outstanding
rights as at December 31, 2008. Rights vest between one and three years
and expire between four and six years.
Rights
Exercise Exercisable
Rights Outstanding at Original Price after at December
December 31, 2008 Exercise Price Expiry Date 31, 2008
(000's) Price Reductions December 31 (000's)
-------------------------------------------------------------------------
4 33.00 23.85 2009 4
2 36.00 27.23 2009 2
57 37.62 29.24 2009 57
3 40.70 32.71 2009 - 2010 3
17 37.25 29.63 2009 - 2010 17
21 38.83 31.61 2009 - 2010 21
231 40.80 33.93 2009 - 2010 231
37 45.55 39.00 2009 - 2011 37
62 44.86 38.66 2009 - 2011 62
74 49.75 43.95 2009 - 2011 74
499 56.93 51.54 2009 - 2011 499
98 56.55 51.64 2010 - 2012 74
352 54.21 49.80 2010 - 2012 254
211 56.00 52.10 2010 - 2012 166
400 52.90 49.51 2010 - 2012 283
133 48.86 45.97 2011 - 2013 55
394 50.25 47.87 2011 - 2013 138
124 45.14 43.27 2011 - 2013 43
13 38.70 37.35 2011 - 2013 4
1,142 42.05 41.21 2012 - 2014 -
73 47.19 46.78 2012 - 2014 -
35 38.76 38.76 2012 - 2014 -
19 23.58 23.58 2012 - 2014 -
-------------------------------------------------------------------------
4,001 $ 48.28 $ 45.05 2,024
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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:
(thousands) 2008 2007
-------------------------------------------------------------------------
Weighted average units 160,589 127,691
Dilutive impact of rights 51 61
-------------------------------------------------------------------------
Diluted trust units 160,640 127,752
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In 2008 we excluded 837,961 rights because their exercise price was
greater than the annual average unit market price of $38.49. In 2007 we
excluded 222,347 rights because their exercise price was greater than the
annual average unit market price of $47.11.
(f) Performance Trust Unit Plan
In 2007 the Board of Directors, upon recommendation of the Compensation
Committee, approved new Performance Trust Unit ("PTU") plans for
executives and employees. These plans will result in employees and
officers receiving cash compensation in relation to the value of a
specified number of underlying notional trust units. The number of
notional trust units awarded is variable to individuals and they vest at
the end of three years.
Upon vesting, the plan participant receives a cash payment based on the
fair value of the underlying trust units plus notional accrued
distributions. The value determined upon vesting of the PTU Plans is
dependent upon the performance of the Fund compared to its peers over the
three year period. The level of performance within the peer group then
determines a performance multiplier.
For the year ended December 31, 2008 the Fund recorded compensation costs
of $8,448,000 (2007 - $1,934,000) under the plan which are included in
general and administrative expenses.
During 2008 282,000 PTU's were granted and at December 31, 2008 there
were 410,000 performance trust units outstanding.
11. INCOME TAXES
The Fund is an inter-vivos trust for income tax purposes. As such, the
Fund's income that is not allocated to the Fund's unitholders is taxable.
The Fund intends to allocate all income to unitholders.
For 2008, the Fund had taxable income of $763,000,000 (2007 -
$632,000,000) or $4.81 per trust unit (2007 - $4.92 per trust unit).
Taxable income of the Fund is comprised of dividend, royalty, interest
and partnership income, less deductions for Canadian oil and gas property
expense ("COGPE") and trust unit issue costs.
There were no dividend income and COGPE deductions for 2008. The amounts
of COGPE and issue costs in the fund remaining as at December 31, 2008
are $466,700,000 and $17,185,000 respectively.
Canadian Government's tax on income trusts
In 2007, the Canadian Federal government enacted tax legislation which
imposed a tax at a rate equivalent to the corporate tax rate on publicly
traded trusts in Canada effective January 1, 2011.
In 2008, the Canadian Federal government introduced draft tax legislation
that would have allowed for the conversion of a SIFT into a corporation
on a Canadian tax deferred basis; defined the provincial tax component of
the SIFT tax; and accelerated the recognition of the "Safe Harbour"
limit. None of the above draft legislations were enacted prior to the
prorogation of Parliament in December 2008. Therefore, all bills
containing the draft legislation lapsed in 2008.
Subsequent to the year end, the Canadian Federal government has
introduced draft tax legislation which includes the above mentioned
measures as part of Canada's Economic Action Plan.
We continue to evaluate alternatives to our income trust structure beyond
2010. We are currently hesitant to make structural changes as we believe
that the exemption period until 2011 has value for our unitholders. While
we are keeping our options open, we will most likely convert into a
dividend paying corporation prior to the end of 2010.
The future income tax liability on the balance sheet arises as a result
of the following temporary differences:
2008
($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Excess of net book value of property,
plant and equipment over the
underlying tax bases $ 479,753 $ 200,837 $ 680,590
Asset retirement obligations (53,057) - (53,057)
Deferred financial assets and other 51,218 268 51,486
-------------------------------------------------------------------------
Future income taxes $ 477,914 $ 201,105 $ 679,019
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current future income tax liability $ 30,198 $ - $ 30,198
Long-term future income tax liability $ 447,716 $ 201,105 $ 648,821
-------------------------------------------------------------------------
2007
($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Excess of net book value of property,
plant and equipment over the
underlying tax bases $ 176,962 $ 194,393 $ 371,355
Asset retirement obligations (41,669) - (41,669)
Other (2,825) (33,409) (36,234)
-------------------------------------------------------------------------
Future income taxes $ 132,468 $ 160,984 $ 293,452
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current future income tax asset $ (10,807) $ - $ (10,807)
Long-term future income tax liability $ 143,275 $ 160,984 $ 304,259
-------------------------------------------------------------------------
The provision for income taxes varies from the amounts that would be
computed by applying the combined Canadian federal and provincial income
tax rates for the following reasons:
($ thousands) 2008 2007
-------------------------------------------------------------------------
Income before taxes $ 860,384 $ 361,712
-------------------------------------------------------------------------
Computed income tax expense at the enacted rate
of 29.94% (32.41% for 2007) $ 257,599 $ 117,231
Increase/(decrease) resulting from:
Net income attributed to the Fund (213,871) (162,016)
Recognition of previously unrecognized pools (13,405) -
Non-taxable portion of (gains)/losses (45,495) -
Amended returns and pool balances (7,464) 5,150
Change in tax rate (2,700) (22,640)
SIFT Tax - 78,110
Other (3,172) 6,186
-------------------------------------------------------------------------
$ (28,508) $ 22,021
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax recovery $ (51,230) $ (990)
Current tax $ 22,722 $ 23,011
-------------------------------------------------------------------------
The breakdown of our current and future income tax balances between our
Canadian and Foreign operations is as follows:
For the year ended
December 31, 2008 ($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Future income tax (recovery)/expense $ (52,706) $ 1,476 $ (51,230)
Current income tax (recovery)/expense (25,069) 47,791 22,722
-------------------------------------------------------------------------
For the year ended
December 31, 2007 ($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Future income tax (recovery)/expense $ (8,183) $ 7,193 $ (990)
Current income tax - 23,011 23,011
-------------------------------------------------------------------------
12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
(a) Fair Value of Financial Instruments
As a result of the adoption of the new financial instrument and hedging
accounting standards on January 1, 2007, certain financial instruments
are now measured and reported on the balance sheet at fair value which
were previously reported at amortized cost.
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, considering credit risk. 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 which are
reported at amortized cost. At December 31, 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 recorded an unrealized gain on certain
publicly traded marketable securities of $3,645,000 ($2,578,000 net of
tax) which was recorded in accumulated other comprehensive income. These
marketable securities were then sold, 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. During the first quarter of 2007 the Fund disposed of certain
marketable securities which resulted in a gain of $14,055,000
($11,302,000 net of tax) which was also reclassified from accumulated
other comprehensive income to other income on the Consolidated Statement
of Income.
As at December 31, 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 unless an other than temporary impairment exists. In
the fourth quarter of 2008 the Fund reduced the carrying value of an
investment in a private company to nil resulting in a charge of
$10,000,000 to the income statement. As at December 31, 2008 the Fund
reported investments in marketable securities of private companies at a
cost of $47,116,000 (December 31, 2007 - $45,400,000) in other assets on
the Consolidated Balance Sheet. Realized gains and losses on marketable
securities are included in other income.
iv. Accounts Payable & Distributions Payable to Unitholders
Accounts payable as well as distributions payable to unitholders are
classified as other liabilities and are reported at amortized cost. At
December 31, 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 cost. At December 31, 2008 the carrying value of the bank
credit facility approximated its 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$177,467,000 and are
translated to Canadian dollars at the period end exchange rate. At
December 31, 2008 the Canadian dollar amortized cost of the senior notes
was approximately $217,327,000 and the fair value of these notes was
$205,942,000.
US$54 million senior notes
The US$54,000,000 senior notes, which are classified as other
liabilities, are reported at their amortized cost of US$54,000,000 and
are translated into Canadian dollars at the period end exchange rate. At
December 31, 2008 the Canadian dollar amortized cost of the senior notes
was approximately $66,128,000 and the fair value of these notes was
$60,485,000.
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 December 31, 2008 a current
deferred financial asset of $121,281,000, a non-current deferred
financial asset of $6,857,000 and a non-current deferred financial credit
of $26,392,000 are recorded on the consolidated balance sheet.
The deferred financial asset relating to crude oil instruments of
$96,641,000 at December 31, 2008 represents a gain position of
$117,428,000 less the related deferred premiums of $20,787,000. The
deferred financial asset relating to natural gas instruments of
$24,292,000 at December 31, 2008 represents a gain position of
$41,953,000 less the related deferred premiums of $17,661,000.
The following table summarizes the fair value as at December 31, 2008 and
change in fair value for the period ended December 31, 2008. The fair
values indicated below are determined using observable market data
including price quotations in active markets.
Cross
Currency Foreign
Interest Interest Exchange Electricity
($ thousands) Rate Swaps Rate Swaps Swaps Swaps
-------------------------------------------------------------------------
Deferred financial
(credits)/assets,
at the beginning of
period $ (226) $ (89,439) $ (425) $ 451
Change in fair value
(credits)/asset (9,825)(3) 73,098(4) 7,282(5) (103)(6)
-------------------------------------------------------------------------
Deferred financial
(credits)/assets,
end of period $ (10,051) $ (16,341) $ 6,857 $ 348
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance sheet
classification:
Current
(liability)/asset $ - $ - $ - $ 348
Non-current
(liability)/asset $ (10,051) $ (16,341) $ 6,857 $ -
-------------------------------------------------------------------------
Commodity
Derivative
Instruments
--------------------
($ thousands) Oil Gas Total
-------------------------------------------------------------
Deferred financial
(credits)/assets,
at the beginning of
period $(56,783)(1) $ 8,083(2) $ (138,339)
Change in fair value
(credits)/asset 153,424(7) 16,209(7) 240,085
-------------------------------------------------------------
Deferred financial
(credits)/assets,
end of period $ 96,641 $ 24,292 $ 101,746
-------------------------------------------------------------
-------------------------------------------------------------
Balance sheet
classification:
Current
(liability)/asset $ 96,641 $ 24,292 $ 121,281
Non-current
(liability)/asset $ - $ - $ (19,535)
-------------------------------------------------------------
(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 $45,539) and interest
expense (gain of $27,559).
(5) Recorded in foreign exchange expense.
(6) Recorded in operating expense.
(7) Recorded in commodity derivative instruments (see below).
The following table summarizes the income statement effects of commodity
derivative instruments:
($ thousands) 2008 2007
-------------------------------------------------------------------------
Gain/(loss) due to change in fair value $ 169,631 $ (66,393)
Net realized cash (losses)/gain (103,197) 13,552
-------------------------------------------------------------------------
Commodity derivative instruments gain/(loss) $ 66,434 $ (52,841)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 February 18, 2009 are summarized below:
Crude Oil Instruments:
Enerplus has entered into the following financial option contracts to
reduce the impact of a downward movement in crude oil prices. These
contracts are classified as held-for-trading and are reported at fair
value. At December 31, 2008 the fair value of these contracts represented
an asset of $96,641,000 and the change in fair value of these contracts
during 2008 represented an unrealized gain of $153,424,000.
The following table summarizes the Fund's crude oil risk management
positions at February 18, 2009:
WTI US$/bbl
-----------------------------------------------
Daily Volumes Fixed Price
bbls/day Sold Call Purchased Put Sold Put and Swaps
-------------------------------------------------------------------------
Term
January
1, 2009 -
December
31, 2009
Put 1,400 - $122.00 - -
Put 1,000 - $120.00 - -
Put 500 - $116.00 - -
Collar 850 $100.00 $ 85.00 - -
Collar 1,000 - $ 92.00 $ 79.00 -
3-Way option 1,000 $ 85.00 $ 70.00 $ 57.50 -
3-Way option 1,000 $ 95.00 $ 79.00 $ 62.00 -
Swap 500 - - - $100.05
-------------------------------------------------------------------------
Natural Gas Instruments:
Enerplus has certain financial contracts outstanding as at February 18,
2009 on its natural gas production that are detailed below.
These contracts are classified as held-for-trading and are reported at
fair value. At December 31, 2008 the fair value of these contracts
represented an asset of $24,292,000 and the change in fair value of these
contracts during 2008 represented an unrealized gain of $16,209,000.
The following table summarizes the Fund's natural gas risk management
positions at February 18, 2009:
AECO CDN$/Mcf
Daily
Volumes Purchased Purchased Fixed Price
MMcf/day Call Sold Call Put Sold Put and Swaps
-------------------------------------------------------------------------
Term
January
1, 2009 -
March 31,
2009
Put 4.7 - - $11.34 - -
Put 4.7 - - $11.61 - -
Put 4.7 - - $ 9.50 - -
Call 5.7 $ 9.50 - - - -
Collar 3.8 - $ 9.50 $ 8.44 - -
Collar 1.9 - $ 9.50 $ 8.44 - -
Collar 4.7 - - $ 8.97 $ 7.39 -
Collar 4.7 - - $ 8.97 $ 7.39 -
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 14.2 - $12.45 $ 8.97 $ 7.39 -
Swap 2.8 - - - - $ 9.42
Swap 2.8 - - - - $ 9.28
Swap 2.8 - - - - $ 9.34
April 1,
2009 -
October
31, 2009
Put 9.5 - - $ 8.44 - -
Put(1) 14.2 - - $ 7.70 - -
Put(1) 2.8 - - $ 7.78 - -
Put(1) 4.7 - - $ 7.87 - -
Put(1) 4.7 - - $ 7.72 - -
Collar 2.8 - - $ 9.23 $ 7.65 -
Collar 2.8 - - $ 9.50 $ 7.91 -
Collar 5.7 - - $ 9.60 $ 7.91 -
Swap 3.8 - - - - $ 7.86
April 1,
2009 -
October
31, 2010
Swap(1) 23.7 - - - - $ 7.33
November 1,
2009 -
March 31,
2010
Put(1) 9.5 - - $ 8.97 - -
Put(1) 2.8 - - $ 9.07 - -
Put(1) 9.5 - - $ 9.06 - -
Call(1) 4.7 - $ 12.13 - - -
2009 - 2010
Physical 2.0 - - - - $ 2.67
-------------------------------------------------------------------------
(1) Financial contracts entered into during the fourth quarter of 2008.
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
December 31, 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 in 25% increase in
($ thousands) forward prices forward prices
-------------------------------------------------------------------------
Crude oil derivative contracts $ 19,157 $ (19,839)
Natural gas derivative contracts $ 29,565 $ (27,481)
Electricity Instruments:
The Fund has entered into electricity swaps that fix the price of
electricity. These contracts are classified as held-for-trading and are
reported at fair value. At December 31, 2008 the fair value of these
contracts represented an asset of $348,000 and the change in fair value
of these contracts during 2008 represented an unrealized loss of
$103,000.
Unrealized gains or losses resulting from changes in fair value along
with realized gains or losses on settlement of the electricity contracts
are recognized as operating costs.
The following table summarizes the Fund's electricity management
positions at February 18, 2009.
Volumes Price
Term MWh CDN$/MWh
-------------------------------------------------------------------------
January 1, 2009 - December 31, 2009 4.0 $74.50
January 1, 2009 - December 31, 2010 4.0 77.50
-------------------------------------------------------------------------
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 CDN/US foreign exchange rate
of 0.98. 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 December 31, 2008, with all other variables held
constant:
Increase/(decrease)
to after-tax net income
---------------------------
25% decrease 25% increase
in $CDN in $CDN
relative relative
($ thousands) to $US to $US
-------------------------------------------------------------------------
Translation of US$54 million senior notes $ (11,582) $ 11,582
Translation of US$175 million senior notes (38,099) 38,099
-------------------------------------------------------------------------
Total $ (49,681) $ 49,681
Increase/(decrease)
to after-tax net income
---------------------------
25% decrease 25% increase
in $CDN in $CDN
relative relative
($ thousands) to $US to $US
-------------------------------------------------------------------------
Foreign exchange swaps $ 9,513 $ (9,840)
Cross currency interest rate swap(1) 34,183 (34,186)
-------------------------------------------------------------------------
Total $ 43,696 $ (44,026)
(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 December 31, 2008 with all other variables held
constant, the Fund's after-tax net income for a quarter would change by
$927,000.
The following sensitivities show the impact to after-tax net income of
the respective changes in the applicable forward interest rates as at
December 31, 2008, with all other variables held constant:
Increase/(decrease)
to after-tax net income
---------------------------
25% decrease 25% increase
in forward in forward
interest interest
($ thousands) rates rates
-------------------------------------------------------------------------
Interest rate swaps $ (990) $ 990
Cross currency interest rate swap(1) 3,451 (3,451)
---------------------------
Total $ 2,461 $ (2,461)
(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 December 31, 2008
approximately 95% 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 December 31, 2008 approximately $7,453,000 or 5% 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 December 31, 2008 is
$5,352,000 which includes a $2,500,000 provision made during during the
year. There were no accounts written off during the year.
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 December 31, 2008 the debt to cash flow ratio was 0.5x (December 31,
2007 - 0.8x). 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 pro-forma 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:
2008 2007 2006 2005 2004
------------------------------------------
Debt-to-Cash Flow Ratio 0.5x 0.8x 0.8x 0.8x 1.1x
At December 31, 2008 Enerplus had additional borrowing capacity of
$1,019,112,000 under its $1,400,000,000 bank credit facility. Enerplus
does not have any subordinated or convertible debt outstanding at this
time.
Capital Spending Plans
----------------------
In 2009 Enerplus expects to spend approximately $300,000,000 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 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. During 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.
By paying distributions, we effectively earn a tax deduction against the
corporate taxes in our underlying subsidiaries and pass along the
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. We intend to manage our distribution levels and capital spending
in order to minimize increases in our debt levels and preserve our
balance sheet strength for future acquisitions.
Enerplus currently has an NAIC2 rating on the senior unsecured notes 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
third quarter of 2008. 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
---------------------------
It is Enerplus' intention to renew the bank credit facility before or as
it comes due. Similarly, Enerplus expects that the senior unsecured notes
will be replaced with new notes or bank debt as they become due. Enerplus
cannot currently predict with any certainty the terms or rates at which
senior unsecured notes or bank debt will be obtained but we expect such
terms and rates may be less favourable than current terms. Over the
long-term, Enerplus expects to balance short-term credit requirements
with bank debt and to look to the term debt markets for longer-term
credit support.
13. COMMITMENTS AND CONTINGENCIES
(a) Pipeline Transportation
Enerplus has contracted to transport 143 MMcf/day of natural gas on the
TransCanada system in Alberta, 70 MMcf/day on TransGas in Saskatchewan,
48 MMcf/day in B.C.via Spectra, as well as 9 MMcf/day on the Alliance
pipeline to the U.S. midwest.
In addition, Enerplus has a contract to transport a minimum of
2,480 bbls/day of crude oil from field locations to suitable marketing
sales points within western Canada.
(b) Office Lease
Enerplus has office lease commitments for both its Canadian and U.S.
operations that expire in 2014 and 2011 respectively. Annual costs of
these lease commitments include rent and operating fees.
(c) Guarantees
(i) Corporate indemnities have been provided by the Fund to all
directors and certain officers of its subsidiaries and affiliates
for various items including, but not limited to, all costs to settle
suits or actions due to their association with the Fund and its
subsidiaries and/or affiliates, subject to certain restrictions.
The Fund has purchased directors' and officers' liability insurance
to mitigate the cost of any potential future suits or actions. Each
indemnity, subject to certain exceptions, applies for so long as the
indemnified person is a director or officer of one of the Fund's
subsidiaries and/or affiliates. The maximum amount of any potential
future payment cannot be reasonably estimated.
(ii) The Fund may provide indemnifications in the normal course of
business that are often standard contractual terms to counterparties
in certain transactions such as purchase and sale agreements. The
terms of these indemnifications will vary based upon the contract,
the nature of which prevents the Fund from making a reasonable
estimate of the maximum potential amounts that may be required to be
paid. Management believes the resolution of these matters would not
have a material adverse impact on the Fund's liquidity, consolidated
financial position or results of operations.
Enerplus has the following minimum annual commitments including the
Fund's principal maturity analysis for the Fund's non-derivative
financial liabilities at December 31, 2008:
Minimum Annual Commitment Each Year
($ thousands) -----------------------------------
Total 2009 2010 2011
--------------------------------------------------------------
Accounts
Payable(1) $ 272,818 $272,818 $ - $ -
Distributions
payable to
unit-
holders(2) 41,397 41,397 - -
Bank credit
facility 380,888 - 380,888 -
Senior
unsecured
notes(3) 323,210 - 53,666 64,642
Pipeline
commitments 62,747 18,850 11,782 9,091
Processing
commitments 25,568 7,578 7,677 7,307
Office leases 69,586 8,730 11,736 12,478
--------------------------------------------------------------
Total
commitments $1,176,214 $349,373 $465,749 $93,518
--------------------------------------------------------------
--------------------------------------------------------------
Minimum Annual Commitment Each Year Total
($ thousands) ---------------------------------- Committed
2012 2013 after 2013
-----------------------------------------------------------
Accounts
Payable(1) $ - $ - $ -
Distributions
payable to
unit-
holders(2) - - -
Bank credit
facility - - -
Senior
unsecured
notes(3) 64,642 64,642 75,618
Pipeline
commitments 6,751 5,369 10,904
Processing
commitments 3,006 - -
Office leases 12,563 12,563 11,516
----------------------------------------------------------
Total
commitments $ 86,962 $82,574 $98,038
--------------------------------------------------------------
--------------------------------------------------------------
(1) Accounts payable are generally settled between 30 and 90 days from
the balance sheet date.
(2) Distributions payable to unitholders are paid on the 20th day of the
month following the balance sheet date.
(3) Includes the economic impact of derivative instruments directly
related to the senior unsecured notes (CCIRS and foreign exchange
swap - see Note 12).
In addition, the Fund is involved in claims and litigation arising in the
normal course of business. The resolution of these claims is uncertain
and there can be no assurance they will be resolved in favour of the
Fund; however, management believes the resolution of these matters would
not have a material adverse impact on the Fund's liquidity, consolidated
financial position or results of operations.
14. GEOGRAPHICAL INFORMATION
As at December 31, 2008
($ thousands) Canada U.S. Total
-------------------------------------------------------------------------
Oil and gas revenue $ 1,968,865 $ 363,019 $ 2,331,884
Capital assets 4,552,482 694,515 5,246,998
Goodwill 451,120 182,903 634,023
-------------------------------------------------------------------------
As at December 31, 2007
($ thousands) Canada U.S. Total
-------------------------------------------------------------------------
Oil and gas revenue $ 1,252,413 $ 286,740 $ 1,539,153
Capital assets 3,293,413 579,405 3,872,818
Goodwill 47,532 147,580 195,112
-------------------------------------------------------------------------
5 YEAR DETAILED STATISTICAL REVIEW
($ thousands,
except per
unit amounts) 2008 2007 2006 2005 2004
-------------------------------------------------------------------------
Financial
Oil and gas
sales(1) $2,370,668 $1,464,214 $1,569,487 $1,413,734 $ 989,266
Cash flow
from
operating
activities 1,262,782 868,548 863,696 774,633 555,060
Cash
distributions
to unitholders 786,138 646,835 614,340 498,205 423,311
Per unit 4.89 5.04 5.04 4.47 4.20
Cash withheld
for
acquisitions
and Capital
Expenditures 476,644 221,713 249,356 276,428 113,248
Development
capital
spending 577,739 387,165 491,226 368,689 206,874
Acquisitions 1,772,826 274,244 51,313 704,028 636,326
Divestments 504,859 9,572 21,127 66,511 31,742
Total net
capital
expenditures 1,856,305 658,327 526,387 1,010,549 813,636
Total assets 6,230,132 4,303,130 4,203,804 4,130,623 3,180,748
Long-term debt,
net of cash 657,421 724,975 679,650 649,825 584,991
Payout ratio(2) 62% 74% 71% 64% 76%
-------------------------------------------------------------------------
Net debt/cash
flow ratio 0.5x 0.8x 0.8x 0.8x 1.1x
-------------------------------------------------------------------------
Trust Unit Trading
Information
Toronto Stock
Exchange trading
summary
Close $23.96 $39.87 $50.68 $55.86 $43.60
Volume 127.679 96,898 82,120 62,278 52,821
New York Stock
Exchange trading
summary
Close $19.58 $40.05 $43.61 $47.98 $36.31
Volume 97.164 54.192 81,677 70,454 67,570
Weighted average
number of units
outstanding
(basic) 160,589 127,691 121,588 109,083 99,273
Number of units
outstanding at
December 31 165,590 129,813 123,151 117,539 104,124
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average
Benchmark
Pricing
AECO natural gas
(per Mcf) $8.13 $6.61 $6.99 $8.48 $6.79
NYMEX natural gas
(US$ per Mcf) 8.93 6.92 7.26 8.55 6.09
WTI crude oil
(US$ per bbl) 99.65 72.34 66.22 56.56 41.40
CDN$/US$
exchange rate 0.94 0.93 0.88 0.83 0.77
-------------------------------------------------------------------------
($ per BOE except
percentage data)
-------------------------------------------------------------------------
Oil and Gas
Economics
Net royalty
rate 19% 19% 19% 19% 21%
Weighted average
price(3) $65.79 $50.48 $50.23 $52.36 $40.90
Hedging(4) (2.94) 0.45 (1.10) (4.90) (3.50)
-------------------------------------------------------------------------
Weighted average
price(1) 62.85 50.93 49.13 47.46 37.40
Net royalty
expense 12.27 9.49 9.36 10.21 8.40
Operating
expense (4) 9.51 9.11 8.02 7.45 7.14
-------------------------------------------------------------------------
Operating netback 41.07 32.33 31.75 29.80 21.86
General and
administrative
expense(4) 1.68 1.98 1.71 1.28 1.06
Management fee - - - - -
Interest expense,
net of interest
and other
income (4) 0.91 1.37 0.95 0.51 0.68
Foreign exchange(4) 0.68 0.06 (0.02) 0.13 (0.01)
Taxes 0.65 0.77 0.70 0.31 0.24
Restoration and
abandonment
cash costs 0.52 0.54 0.37 0.27 0.25
-------------------------------------------------------------------------
Cash flow before
changes in
non-cash working
capital $36.63 $27.61 $28.04 $27.30 $19.64
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of commodity derivative instruments and transportation
(2) Calculated as cash distributions to unitholders divided by cash flow
from operating activities
(3) Net of transportation and before the effects of commodity derivative
instruments
(4) Does not include non-cash portion of expense
OPERATIONAL STATISTICS
The following information outlines Enerplus' gross average daily
production volumes for the years indicated and our Company interest
reserves based upon forecast prices and costs at December 31 each year.
2008(1) 2007(1) 2006(1) 2005(1) 2004(1)
-------------------------------------------------------------------------
Daily
Production
Oil Sands n/a n/a n/a n/a n/a
Crude Oil
(bbls/day) 35,434 34,506 36,134 29,315 25,550
NGLs (bbls/day) 4,529 4,104 4,483 4,689 4,398
Natural Gas
(Mcf/day) 346,439 262,254 270,972 274,336 271,091
-------------------------------------------------------------------------
BOE per day 97,702 82,319 85,779 79,727 75,130
Drilling Activity
(net wells) 643 252 361 393 367
Success Rate 99% 99% 99% 99% 99%
Production
Replacement 78% 90% 82% 247% 384%
Proved Reserves(2)
Oil Sands - 8,568 8,730 9,453 n/a
Crude Oil (Mbls) 127,692 125,238 125,048 129,745 104,408
NGLs (Mbbls) 13,052 11,785 12,690 13,084 12,776
Natural Gas
(MMcf) 1,066,534 866,077 920,061 965,776 971,598
-------------------------------------------------------------------------
MBOE 318,500 289,937 299,812 313,245 279,117
-------------------------------------------------------------------------
Probable
Reserves(2)
Oil Sands - 54,930 47,998 43,700 47,747
Crude Oil (Mbls) 38,931 35,504 34,421 31,567 26,783
NGLs (Mbbls) 4,765 3,827 3,777 3,539 3,292
Natural Gas
(MMcf) 421,134 336,214 344,025 342,518 295,698
-------------------------------------------------------------------------
MBOE 113,885 150,297 143,533 135,892 127,105
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves(2)
Oil Sands - 63,498 56,728 53,153 47,747
Crude Oil
(Mbls) 166,623 160,742 159,469 161,312 131,191
NGLs (Mbbls) 17,817 15,612 16,467 16,623 16,068
Natural Gas
(MMcf) 1,487,668 1,202,291 1,264,086 1,308,294 1,267,296
-------------------------------------------------------------------------
MBOE 432,385 440,234 443,345 449,137 406,222
-------------------------------------------------------------------------
Reserve
Life
Index(3)
Without Oil
Sands:
Proved (years) 9.4 10.0 9.8 9.6 10.1
Proved Plus
Probable (years) 12.1 12.8 12.2 12.0 12.4
-------------------------------------------------------------------------
With Oil Sands:
Proved (years) 9.4 10.3 10.1 9.9 10.1
Proved Plus
Probable (years) 12.1 14.8 14.0 13.5 14.0
-------------------------------------------------------------------------
(1) Reserve information reflects NI 51-101 reporting methodology.
(2) Company interest reserves consist of gross revenues (as defined in
National Instrument 51-101) plus Enerplus' royalty interests.
Company interest reserves are not a term defined in National
Instrument 51-101 and may not be comparable to reserves disclosed by
other issuers.
(3) The Reserve Life Indices (RLI) are based upon year-end proved plus
probable reserves divided by the following year's proved and proved
plus probable production volumes as determined in the independent
reserve engineering reports.
PRODUCTION AND RESERVES PER TRUST UNIT
Production and reserves per unit are one measure of sustainability
however they do not differentiate between the various commodity types
and the quality of the reserves. When adjusted for debt and
distributions it also provides an ability to compare results between our
distributing model with other more traditional oil and gas entities that
generally reinvest the majority of their cash flow into exploration and
development activities. Our 2008 metrics have been impacted by the
acquisition of Focus Energy Trust, the divestment of our Joslyn oil
sands lease and negative reserve revisions.
Production per debt-adjusted trust unit is measured in respect of the
average daily production for the year, and the weighted average number of
trust units outstanding during the year. The measurements are then debt-
adjusted by assuming additional trust units are issued at quarter-end
unit prices to replace long-term debt outstanding at each quarter-end.
The average number of trust units created over the four quarters is then
added to the weighted average number of trust units to obtain the debt-
adjusted number of trust units for the year. To distribution-adjust the
metric, we utilized the amount of cash distributions paid each month and
retired units using the quarter-end trust unit price thereby lowering the
total number of units outstanding.
In 2008, our production per debt and distribution-adjusted unit declined
by 6% due to the units issued as compared to the production added as a
result of the Focus acquisition.
Production per Debt and
Distribution-Adjusted Trust Unit 2008 2007 2006
-------------------------------------------------------------------------
Average daily production 95,687 82,319 85,779
Debt-adjusted weighted average
trust units (000's) 182,401 142,666 132,208
Production per debt-adjusted
trust unit (BOE/unit) 0.192 0.211 0.237
Production per debt and distribution
adjusted trust unit (BOE/unit) 0.368 0.392 0.390
-------------------------------------------------------------------------
Reserves per debt-adjusted trust unit are measured in respect of year-end
proved plus probable reserves and the number of units outstanding at
year-end. To eliminate the temporary timing effects of financing
decisions, we have debt-adjusted these measurements by assuming we issue
additional trust units at year-end prices to replace year-end long-term
debt. To distribution-adjust the metric, we utilized the amount of cash
distributions paid to unitholders throughout the year and retired units
using the year-end trust unit price thereby lowering the total number of
units outstanding.
During 2008 our reserves per debt and distribution-adjusted unit
declined 25% compared to the prior year. This was a significant change
compared to historic performance. Approximately 10% of the decline was
directly attributable to the methodology associated with using a lower
unit price at year end to convert debt to units. As a result,
additional notional trust units were required to replace long term debt,
which negatively affects the debt and distribution-adjusted
calculation. A further 7% of the decrease was a result of fewer net
reserve additions associated with our capital development program. Our
Focus acquisition and Joslyn disposition also reduced our debt and
distribution-adjusted reserves per unit by 5% and 3% respectively.
Focus was a strategic acquisition with significant development
opportunity. Although Joslyn decreased our reserves per debt and
distribution-adjusted unit, these reserves were lower quality bitumen
which would have required significant future capital. Furthermore, the
Joslyn disposition increased our net asset value and balance sheet
strength.
Reserves per Debt and
Distribution-Adjusted Trust Unit 2008 2007 2006
-------------------------------------------------------------------------
Year-end proved plus probable reserves 432,385 440,234 443,345
Debt-adjusted trust units outstanding
at year end (000's) 193,029 147,997 136,562
Reserves per debt-adjusted trust unit
(BOE/unit) 2.24 2.97 3.25
Reserves per debt and distribution
adjusted trust unit (BOE/unit) 4.09 5.43 5.32
-------------------------------------------------------------------------
INFORMATION REGARDING DISCLOSURE IN THIS NEWS RELEASE AND OIL AND GAS
RESERVES, RESOURCES AND OPERATIONAL INFORMATION
All amounts in this news release are stated in Canadian dollars unless
otherwise specified.
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. In accordance with Canadian practice, production volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Unless otherwise specified, all reserves
volumes in this news release (and all information derived therefrom) are based
on "company interest reserves" using forecast prices and costs. "Company
interest reserves" consist of "gross reserves" (as defined in National
Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101")
plus Enerplus' royalty interests in reserves. "Company interest reserves" are
not a measure defined in NI 51-101 and does not have a standardized meaning
under NI 51-101. Accordingly, our company interest reserves may not be
comparable to reserves presented or disclosed by other issuers. Our oil and
gas reserves statement for the year ended December 31, 2008, which will
include complete disclosure of our oil and gas reserves and other oil and gas
information in accordance with NI 51-101, will be contained within our Annual
Information Form which will be available on our about March 16, 2009 on our
website at www.enerplus.com and on our SEDAR profile at www.sedar.com.
Additionally, the Annual Information Form will form part of our Form 40-F that
will be filed with the SEC and available on www.sec.gov. Readers are also
urged to review the Management's Discussion & Analysis and financial
statements included in this news release for more complete disclosure on our
operations.
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 a 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 prevailing commodity price environment, 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, although readers should consider the described
uncertainties regarding SAGD expansion as described herein. 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 and Analysis section of this news release and under
"Risk Factors" in the Fund's Annual Information Form (and corresponding Form
40-F) dated March 13, 2008, as well as the risk factors to be contained in the
Fund's Annual Information Form (and corresponding Form 40-F) to be filed in
mid-March 2009.
NOTICE TO U.S. READERS
The oil and natural gas reserves contained in this Annual Information
Form has generally been prepared in accordance with Canadian disclosure
standards, which are not comparable in all respects of United States or other
foreign disclosure standards. For example, the United States Securities and
Exchange Commission (the "SEC") currently generally permits oil and gas
issuers, in their filings with the SEC, to disclose only proved reserves (as
defined in SEC rules). Canadian securities laws require oil and gas issuers,
in their filings with Canadian securities regulators, to disclose not only
proved reserves (which are defined differently from the SEC rules) but also
probable reserves, each as defined in NI 51-101. Accordingly, proved reserves
disclosed in this news release may not be comparable to U.S. standards, and in
this news release, Enerplus has disclosed reserves designated as "probable
reserves" and "proved plus probable reserves". Probable reserves are higher
risk and are generally believed to be less likely to be accurately estimated
or recovered than proved reserves. The SEC's guidelines currently strictly
prohibit reserves in these categories from being included in filings with the
SEC that are required to be prepared in accordance with U.S. disclosure
requirements. In addition, under Canadian disclosure requirements and industry
practice, reserves and production are reported using gross (or, as noted
above, "company interest") volumes, which are volumes prior to deduction of
royalty and similar payments. The practice in the United States is to report
reserves and production using net volumes, after deduction of applicable
royalties and similar payments. Additionally, the SEC prohibits disclosure of
oil and gas resources, whereas Canadian issuers may disclose resource volumes.
Resources are different than, and should not construed as reserves. For a
description of the definition of, and the risks and uncertainties surrounding
the disclosure of, contingent resources, see above.
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", "budget", "strategy" and similar expressions are intended
to identify forward-looking information or statements. In particular, but
without limiting the foregoing, this news release contains forward-looking
information and statements pertaining to the following: the volumes and
estimated value of the Fund's oil and gas reserves; the life of the Fund's
reserves; the volume and product mix of the Fund's oil and gas production;
future oil and natural gas prices and the Fund's commodity risk management
programs; the amount of future asset retirement obligations; future liquidity
and financial capacity and capital resources; future results from operations
and operating metrics; future costs, expenses and royalty rates; future
interest costs; future development, exploration, acquisition and development
activities (including drilling plans) and related capital expenditures,
including with respect to both our conventional and oil sands activities and
in particular the development of the Kirby lease; future acquisitions and
dispositions; asset retirement obligations, the making and timing of future
regulatory filings and applications; the value of the Fund's equity
investments; future tax treatment of income trusts and future taxes payable by
the Fund; the Fund's tax pools; the future trust or corporate structure of the
Fund and its subsidiaries; the amount, timing and tax treatment of cash
distributions to unitholders; and future payout ratios.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
the Fund including, without limitation: that the Fund will continue to conduct
its operations in a manner consistent with past operations; the general
continuance of current or, where applicable, assumed industry conditions; the
continuance of existing (and in certain circumstances, the implementation of
proposed) tax, royalty and regulatory regimes; the accuracy of the estimates
of the Fund's reserve and resource volumes; certain commodity price and other
cost assumptions; the continued availability of adequate debt and/or equity
financing and cash flow to fund its capital and operating requirements as
needed; and the extent of its liabilities. The Fund believes the material
factors, expectations and assumptions reflected in the forward-looking
information and statements are reasonable but no assurance can be given that
these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
changes in the demand for or supply of the Fund's products; unanticipated
operating results or production declines; changes in tax or environmental
laws, royalty rates or other regulatory matters; changes in development plans
the Fund or by third party operators of the Fund's properties, increased debt
levels or debt service requirements; inaccurate estimation of the Fund's oil
and gas reserve and resource volumes; limited, unfavourable or a lack of
access to capital markets; increased costs; a lack of adequate insurance
coverage; declines in the value of the Fund's equity investments; the impact
of competitors; 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 news release
and in the Fund's Annual Information Form and Form 40-F described above).
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.
Gordon J. Kerr
President & Chief Executive Officer
Enerplus Resources Fund
%CIK: 0001126874
For further information: Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com
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