Enerplus announces 2007 year end results and reserves information
TSX: ERF.UN
NYSE: ERF
CALGARY, Feb. 28 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased
to announce our financial and operating results for the year ended
December 31, 2007.
STRATEGIC EXECUTION:
- On February 13, 2008 we acquired Focus Energy Trust creating an
entity with a combined market capitalization of approximately
$7.6 billion and production of approximately 100,000 BOE/day
- In the second quarter of 2007, we completed the acquisition of an
operated oil sands steam assisted gravity drainage ("SAGD") project
with production potential of 30,000 to 40,000 bbls/day of bitumen
through the purchase of a 100% working interest in the Kirby lease
for a total purchase price of $203.1 million
- We expanded our U.S. asset base through the acquisition of a gross
overriding royalty interest in the Jonah natural gas field in Wyoming
for total consideration of approximately $61.0 million in January
2007
- We maintained a strong balance sheet with a net debt to trailing 12
month cash flow ratio of 0.8x at December 31, 2007 to support
further potential acquisitions and growth
FINANCIAL HIGHLIGHTS:
- Cash flow totaled $868.5 million during 2007, essentially flat over
2006
- Cash distributions payable to unitholders remained constant at $0.42
per trust unit for the past 28 months resulting in annual cash
distributions paid of $5.04 per trust unit
- Our payout ratio increased slightly to 74% from 71%
- On April 10, 2007 we completed an equity offering of 4.25 million
trust units in conjunction with the Kirby acquisition raising gross
proceeds of $210.6 million
- Subsequent to year-end, we increased our bank credit facility from
$1.0 billion to $1.4 billion in conjunction with the Focus
transaction
OPERATIONAL HIGHLIGHTS:
- Daily production averaged 82,319 BOE/day essentially on target with
our third quarter guidance of 82,500 BOE/day
- Development capital spending was $387.2 million
- We drilled 252 net wells with a 99% success rate
- Operating costs were $9.12/BOE for 2007, slightly below our third
quarter guidance of $9.20/BOE
- General and administrative ("G&A") expenses were $2.26/BOE, 6% lower
than our guidance of $2.40/BOE
RESERVES:
- We replaced 90% of 2007 production through reserve additions from
development capital spending and acquisitions on a proved plus
probable basis
- Proved plus probable reserves decreased slightly by 1% to 440.2 MMBOE
and proved reserves decreased 3% to 289.9 MMBOE
- Proved plus probable finding and development costs ("F&D") on our
conventional oil and gas activities were $19.97/BOE for the year and
when we include our oil sands activities, F&D costs were $20.33/BOE
(both measures include future development capital)
- Proved plus probable finding, development and acquisition ("FD&A")
costs on our conventional oil and gas activities were $19.79/BOE for
the year and when we include our oil sands activities, FD&A costs
were $27.69/BOE, primarily as a result of the Kirby acquisition which
has no reserves assigned to it at this time
- 3 year FD&A costs were $19.57/BOE on our conventional assets and
$20.69/BOE including oil sands
- We added 6.8 million barrels of proved plus probable reserves
relating to our Joslyn SAGD project
- Our reserve Life Index ("RLI") continues to be one of the longest in
the sector at 14.8 years on a proved plus probable basis and
10.3 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" and
"Notice to U.S. Readers" at the end of this news release for information
regarding the presentation of the financial and operational information in
this news release.
FINANCIAL HIGHLIGHTS
For the years ended December 31, 2007 2006
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Financial (000's)
Cash Flow from Operating Activities $ 868,548 $ 863,696
Cash Distributions to Unitholders(1) 646,835 614,340
Cash Withheld for Acquisitions
and Capital Expenditures 221,713 249,356
Net Income 339,691 544,782
Debt Outstanding (net of cash) 724,975 679,650
Development Capital Spending 387,165 491,226
Acquisitions 274,244 51,313
Divestments 9,572 21,127
Financial per Unit(2)
Cash Flow from Operating Activities $ 6.80 $ 7.10
Cash Distributions to Unitholders(1) 5.07 5.05
Cash Withheld for Acquisitions
and Capital Expenditures 1.73 2.05
Net Income 2.66 4.48
Payout Ratio(3) 74% 71%
Selected Financial Results per BOE(4)
Oil & Gas Sales(5) $ 50.48 $ 50.23
Royalties (9.49) (9.47)
Financial Contracts 0.45 (1.10)
Operating Costs (9.11) (8.02)
General and Administrative (1.98) (1.71)
Interest and Foreign Exchange (1.43) (0.93)
Taxes (0.77) (0.59)
Restoration and Abandonment (0.54) (0.37)
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Cash Flow from Operating Activities before
changes in non-cash operating working capital $ 27.61 $ 28.04
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Weighted Average Number of Trust
Units Outstanding (thousands) 127,691 121,588
Debt/Trailing 12 Month Cash Flow Ratio 0.8x 0.8x
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OPERATING HIGHLIGHTS
For the years ended December 31, 2007 2006
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Average Daily Production
Natural gas (Mcf/day) 262,254 270,972
Crude oil (bbls/day) 34,506 36,134
NGLs (bbls/day) 4,104 4,483
Total (BOE/day) 82,319 85,779
% Natural gas 53% 53%
Average Selling Price(5)
Natural gas (per Mcf) $ 6.45 $ 6.81
Crude oil (per bbl) $ 65.11 $ 61.80
NGLs (per bbl) $ 51.35 $ 50.90
Per BOE $ 50.48 $ 50.23
US$ exchange rate 0.93 0.88
Net Wells drilled 252 361
Success Rate 99% 99%
Proved Reserves (MMBOE)(6) 289.9 299.8
Probable Reserves (MMBOE)(6) 150.3 143.5
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Total Proved plus Probable Reserves (MMBOE)(6) 440.2 443.3
Conventional Finding & Development Cost/BOE(7) $ 19.97 $ 27.48
Conventional Finding, Development
& Acquisition Cost/BOE(7) $ 19.79 $ 25.41
Total Finding & Development
Cost/BOE including oil sands(7) $ 20.33 $ 22.87
Total Finding, Development & Acquisition
Cost/BOE including oil sands(7) $ 27.69 $ 23.19
Recycle Ratio (conventional)(7) 1.6x 1.2x
Proved Reserve Life Index (years)(8) 10.3 10.1
Proved plus Probable Reserve Life Index (years)(8) 14.8 14.0
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(1) Calculated based on distributions paid or payable. Cash distributions
to unitholders per unit will not correspond to actual distributions
of $5.04 per trust unit as a result of using the annual weighted
average trust units outstanding.
(2) Based on annual weighted average trust units outstanding.
(3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
from Operating Activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(6) Reserve figures are calculated based upon company interest reserves
using forecast prices and costs.
(7) Based upon proved plus probable company interest reserves including
future development capital. For additional details and information
see "Finding and Development Costs ("F&D")" and "Finding, Development
and Acquisition Costs ("FD&A")" and "Recycle Ratio" in this news
release.
(8) Based upon year-end company interest reserves and the following
year's estimated production contained in the independent reserve
reports.
Trust Unit Trading Information
TSX - ERF.un NYSE - ERF
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($CDN) ($US)
High $ 53.70 $ 50.75
Low $ 38.00 $ 38.06
Close $ 39.87 $ 40.05
Volume (000's) 96,898 54,192
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COMPLETION OF STRATEGIC ACQUISITION OF FOCUS ENERGY TRUST
On February 13, 2008, Enerplus completed the acquisition of Focus Energy
Trust ("Focus") resulting in improved asset quality, organizational strength
and efficiency and financial position for the combined entity going forward.
Focus adds approximately 21,000 BOE/day of production to Enerplus
(18,000 BOE/day annualized from closing date), weighted approximately 90% to
natural gas, coming from two principal properties - the Shackleton shallow
natural gas property in southwest Saskatchewan and the Tommy Lakes deep tight
gas property in British Columbia.
Over 90% of the Focus employees, excluding executives, have joined the
Enerplus organization providing continuity in the management of the Focus
assets. The nature and quality of the Focus assets is anticipated to also
position us for improved operating metrics. With a greater percentage of
operated properties and concentrated resource plays the merger will allow us
to concentrate our attention on large, high impact areas.
As a result of the acquisition, Enerplus is now one of the top shallow
natural gas producers in Canada and will have the ability to combine technical
and execution expertise with purchasing power over a significant asset base.
We believe the Shackleton property offers more than 1,500 future drilling
locations representing 4 to 5 years of low risk repeatable development
opportunities. We expect some cost saving synergies and increased ability to
control the pace of development in the area especially on our previously non-
operated interests. We also believe Shackleton has potential for increased
well density, additional compression, play extension through step-out drilling
on 240,000 net acres of undeveloped land and recompletion potential from
additional Milk River formation intervals. We believe the Tommy Lakes property
has more than 50 future drilling locations representing at least three years
of development potential.
The following table summarizes Focus' company interest reserves at
December 31, 2007 as evaluated by Paddock Lindstrom & Associates Ltd.
utilizing the year end price and cost forecasts of Sproule Associates Limited
("Sproule"), our Canadian conventional independent reserves evaluators. Focus'
total reserves at December 31, 2007 increased over 2006 levels by
approximately 1.1 million BOE effectively replacing 114% of produced reserves
as a result of capital development activities.
Focus Energy Trust Reserve Summary (company interest using forecast
prices and costs)
Light & Natural
Medium Total Gas Natural
Oil Oil Liquids Gas Total
(Mbbls) (Mbbls) (Mbbls) (MMcf) (MBOE)
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Total Reserves at
Dec. 31, 2006 5,248 5,248 3,267 450,966 83,676
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Proved developed
producing 3,500 3,500 1,774 196,111 37,959
Proved developed
non-producing - - 15 1,705 299
Proved undeveloped 127 127 956 142,830 24,888
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Total Proved Reserves 3,627 3,627 2,745 340,646 63,146
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Probable 939 939 834 118,948 21,598
Total Proved plus Probable
Reserves at
Dec. 31, 2007 4,566 4,566 3,579 459,594 84,744
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OPERATIONS
Production
Daily production averaged 82,319 BOE/day for 2007 approximately 4% lower
than 2006 average daily volumes. In the third quarter we adjusted our
production guidance to 82,500 BOE/day reflecting significantly lower capital
spending on development activities from 2006 levels as well as lower initial
production rates on our Bakken oil infill drilling program and higher than
expected downtime and turnaround activity during the year.
Our exit rate production was roughly 4% lower than expected at
79,800 BOE/day as compared to our guidance of 83,000 BOE/day due to the
previously announced Giltedge fire, capital project delays and additional
unexpected downtime. Approximately 2,000 BOE/day was shut in as a result of a
fire at the Giltedge oil property in late November. We expect the facility to
be back to full production by mid-2008. Property and business interruption
insurance will mitigate most of the costs resulting from the Giltedge fire.
Delayed tie-ins primarily on non-operated capital projects at year-end and
additional line breaks at our non-operated Mitsue field also impacted our exit
production by 1,200 BOE/day. While the majority of the capital for these
projects was spent in 2007, we do not expect production until early March. We
also expect production at Mitsue to be back on line by the end of March.
Development Activities
Our capital spending program during 2007 totaled $387.2 million.
Approximately two thirds of our conventional development program was invested
in crude oil projects both in the U.S. and Canada where we realized the
highest rates of return given strong crude oil prices through 2007. In total,
we drilled 252 net wells with a 99% success rate and brought on approximately
15,700 BOE/day of new initial production at an average on-stream cost of
$22,150/BOE/day, excluding oil sands spending.
We continued to invest in activities such as land, seismic and oil sands
which did not add immediate cash flow and reserves, but positioned us to add
production and reserves in the future. Approximately 20% of our capital
expenditures, or $75 million, was spent on these types of activities during
2007.
2007 Production and Capital Spending
Average Finding
Daily Drilling Initial Capital & Devel-
Product- Activity Product- Capital Efficie- opment
ion Net ion Spending ncy Cost/
Play Types BOE/day Wells BOE/day $MM $/BOE/day BOE(1)
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Crude Oil
Waterfloods 16,576 20 2,200 $ 54 $ 24,550 $ 19.78
Shallow Gas &
Coalbed
Methane 14,696 155 2,500 39 15,600 n/a
Bakken Oil 11,132 24 4,700 106 22,550 16.30
Deep Tight Gas 8,772 6 1,700 35 20,600 20.30
Other
Conventional
Oil & Gas 31,143 47 4,600 114 24,800 12.10
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Total
Conventional 82,319 252 15,700 $ 348 $ 22,150 $ 19.97
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Oil Sands - n/a - 39 - 21.16
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Total Company 82,319 252 15,700 $ 387 $ 24,650 $ 20.33
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(1) See "Finding and Development Costs ("F&D") and Finding, Development
and Acquisitions Costs ("FD&A")" in this news release for additional
information
Resource Plays
Crude Oil Waterfloods
---------------------
Crude oil waterfloods represented approximately 20% of our 2007
production and 23% of our proved plus probable reserves at year-end. Enerplus
operates over 80% of our waterfloods which are located throughout the Western
Canadian Sedimentary Basin. We invested $54 million on waterflood resource
plays in 2007, drilling 20 new wells in Virden, Joarcam, Pembina and Silver
Heights resulting in an overall finding and development cost of $19.78/BOE.
Increased optimization at our Gleneath, Giltedge, Medicine Hat Glauc C and
Mitsue properties, combined with the success of the drilling program, resulted
in capital efficiencies improving markedly year-over-year, from
$41,250/BOE/day in 2006 to $24,550/BOE/day.
We expect to see a significant increase in capital investment to
$105 million in 2008 with plans for 49 new wells, increased optimization at
our Cadogan property and two new surfactant pilots at Giltedge. Continued high
oil prices and success in key development programs has laid the ground work
for larger drilling programs at Pembina, Joarcam and Virden. We will also be
rebuilding the Giltedge facility after the fire in November 2007 and expect it
to be back to full production by mid-2008.
Shallow Natural Gas and CBM
---------------------------
Shallow natural gas and coal bed methane ("CBM") represented 18% of our
daily production volumes in 2007 and 21% of our total proved plus probable
reserves at year-end. Shallow gas and CBM spending was reduced by
approximately 60% last year as weak natural gas prices and increasing costs
eroded returns in this play type. We invested only $39 million and
concentrated our spending on our most attractive shallow gas opportunities in
the Bantry, Medicine Hat Sun Valley, Verger and Shackleton/Sceptre areas.
Reserve additions were offset by technical disappointments at Hanna Garden
which made overall finding and development costs misrepresentative on a one
year basis for the overall program. Drilling activity was significantly
reduced with only 155 net wells drilled in 2007 compared to 249 in 2006. This
high-graded program resulted in a significant improvement in capital
efficiencies year-over-year from $29,400/BOE/day in 2006 to $15,600/BOE/day.
In 2008 we expect to see a significant increase in total spending given
improvements in costs and natural gas prices, the addition of the Focus
Shackleton property and the relatively limited impact from the royalty changes
in Alberta on our shallow gas program. We are planning to drill approximately
371 net wells with total spending of $128 million. Shallow gas activities will
be focused at our properties in Shackleton where we are infill drilling to
increase well density from 4 to 8 wells per section and at Bantry and Milk
River prospects in Medicine Hat and Fox Valley where we are down spacing to
16 wells per section. Approximately 73% of our total conventional drill wells
in 2008 will be shallow gas wells.
Bakken Oil
----------
The Sleeping Giant Bakken oil resource play in Montana produced
approximately 13% of our average daily production in 2007 and represented 9%
of our proved plus probable reserves at December 31, 2007. Capital investment
activity remained high throughout 2007 with $106 million invested to complete
the initial two wells per section drilling program across the core of the
field, drill 25 third well per section wells, complete 23 refracs and expand
the resource outside of the core area. Overall results remained attractive on
the third well per section drilling given recoverable reserves of over
200,000 BOE despite lower than anticipated initial production rates that
averaged 200 BOE/day versus our original expectation of 300 BOE/day. Refracs
continued to provide both incremental oil production and reserve recovery of
approximately 50 BOE/day and 77,000 BOE, respectively. Our expansion efforts
to date outside the core Bakken area have been unsuccessful with two
uneconomic Red River wells and uneconomic extension wells northwest and
southeast of the core field area. In total we spent $14 million on expansion
efforts including associated seismic costs. We continue to evaluate these
early results and other potential outside the core Bakken area.
Our activities generated positive proved plus probable reserve additions
of 10 million BOE, offset by 5 million BOE of negative revisions. The
additions were primarily associated with our third wells per section and
refrac program, while negative revisions were related to our extension areas
and a change in recovery factor for solution gas. Since the acquisition of
this property in 2005, we have added over 12 million BOE of proved plus
probable reserves on the initial 30 million BOE acquired. Our finding and
development costs in this resource play remained attractive at $16.30 per
barrel with an on-stream cost of $22,550/BOE/day.
In 2008 we plan to complement our ongoing capital program with a focused
optimization effort and will spend approximately $47 million. Optimization
will include automating pump controls, managing fluid levels and improving our
field downtime. We expect to complete the third well per section drilling
program in the core areas of the field (approximately 6 wells) and continue
the refrac program (24 refracs). Efforts to understand and evaluate enhanced
oil recovery projects ("EOR") are also underway given our expectations as to
the potential recovery beyond primary depletion. Other activities will include
determining the viability of a fourth well per section along the lease lines,
potential EOR piloting and further work in expanding areas outside the core
Bakken play.
Deep Tight Gas
--------------
Deep tight gas represented approximately 11% of our average daily
production in 2007 and 7% of our year-end proved plus probable reserves. These
play types includes mostly non-operated multi-zone deep tight gas plays such
as Cardium, Nikannassin, Montney, Bluesky and Halfway zones as well as many
others. In 2007, we completed our first significant operated development
success with a $14 million deep gas drilling project at Ansell. We added
3.5 million BOE of new proved plus probable reserves by drilling 4 gross wells
and expanded gas gathering and compression facilities. These wells are
currently averaging 2 MMcf/day gross with an average 45% working interest. The
success at Ansell was partially offset by a 1.3 million BOE negative proved
plus probable reserve revision at our non-operated Benjamin property
associated with a proved undeveloped location as the operator elected not to
drill the well due to lower gas prices and reallocation of capital to other
projects. The majority of the $35 million we invested in 2007 continued to be
in the non-operated areas of Deep Basin, Elmworth Wapiti, Pine Creek and
Copton.
Through the Focus transaction we added the Tommy Lakes property which
will be our largest operated deep tight gas field currently producing
approximately 6,000 BOE/day. Overall spending in 2008 is currently anticipated
to increase to $53 million for Deep Gas, mainly as a result of the addition of
this property with plans to spend approximately $20 million at Tommy Lakes
(post close), and the remainder primarily in Ansell and the non-operated areas
of Deep Basin, Elmworth, Wapiti and Copton.
Other Conventional Oil & Gas
----------------------------
Other conventional oil and gas properties comprised approximately 38% of
our total average daily production and 25% of our year-end proved plus
reserves. This includes a diversified portfolio of both oil and gas projects
across western Canada which are smaller in nature and which we operate
approximately 70%. Our capital investment was reduced in this play type by 19%
year-over-year primarily due to lower capital spending in our non-operated
properties and a shift to more spending in our Bakken oil play. Despite
efforts to high grade our program, we did not see the high impact wells that
were attributable to this category in 2006 and our activities at two main
projects where we spent approximately $15 million, Kantah and Tatagwa, did not
produce the results expected. In total, we spent $114 million on capital
development activities in this category in 2007.
Going forward in 2008 we expect to spend $142 million on a variety of oil
and gas projects, both operated ($100 million) and non-operated ($42 million).
We will spend just under $20 million on operated oil optimization activities
and equipment upgrades at Bantry North and South and almost $20 million at our
oil properties in southeast Saskatchewan, primarily on horizontal drilling in
an attempt to extend the boundaries of those assets. The remainder of the
operated capital will be spent on a variety of smaller prospects in Alberta
and British Columbia.
Oil Sands
---------
We invested $39 million in our oil sands portfolio in 2007 which includes
our operated Kirby SAGD project, our non-operated SAGD and mine projects at
Joslyn and our joint venture and equity ownership with Laricina Energy Ltd.
Kirby:
------
The most significant oil sands activity in 2007 was the acquisition of
the Kirby lease, a 100% working interest, operated SAGD project for
$203 million with potential production capacity through staged development of
30,000 to 40,000 bbls/day of bitumen. The Kirby oil sands leases cover a large
land block of 43,360 gross acres (over 67 sections of land) in a highly
prospective area in the heart of the Athabasca oil sands fairway near several
other major SAGD development projects currently on production. While the Kirby
lease does not have current production or proved plus probable reserves, an
independent engineering assessment conducted by GLJ Petroleum Consultants Ltd.
("GLJ") effective December 31, 2007 indicates a "best estimate" of contingent
resources of 244 million barrels of bitumen. Our initial development plans
include a 10,000 bbl/day SAGD project starting in 2011/2012 with further
expansion capability to a total of 30,000 to 40,000 bbls/day of gross bitumen
production over time.
Our oil sands strategy is to be a best in class SAGD operator given the
fit with our business model, the availability of resource and link to the
conventional business. We believe Kirby is an attractive first project given
the reservoir quality, lack of thief zones, proximity to markets and
infrastructure, and expandability. We have added to our capabilities with a
new Vice President, Oil Sands and seasoned management and staff. Our capital
spending in 2007 totaled $2 million and we have begun work on our first winter
delineation drilling program at the Kirby lease and are targeting 70 new core
holes and testing for water sources and disposal zones on the lease. We expect
to use this new information in support of a 10,000 BOE/day SAGD project
application in late fall of 2008. Our original cost estimates of $365 million
associated with the development of the 10,000 bbl/day project will be updated
later in the year as work progresses on the regulatory application. We plan to
spend approximately $50 million in 2008 on our core hole drilling program and
the regulatory application. The following outlines our current expectations as
to the key milestones associated with the development of the Kirby lease:
- 2007/2008 - Winter drilling program, stakeholder consultation and
work on regulatory applications
- Fall 2008 - Regulatory application filed
- Fall 2009 - Regulatory approval anticipated
- Late 2011 - First steam
- Mid-2012 - First production
- 2013 - Full production of 10,000 bbls/day
Joslyn:
-------
We continued to invest in the Joslyn lease throughout 2007 spending
$18 million on the Joslyn SAGD project and $11 million on the Joslyn mining
development. Our activity included additional delineation spending, regulatory
work, SAGD facility upgrades and other costs.
Results of the 2006-07 winter drilling program continue to indicate a
growing resource on the Joslyn lease. As a result of the program, we obtained
new reserve and contingent resource estimates in a report from GLJ which
utilized results from an updated Norwest mining report. Effective December 31,
2007 GLJ added 6.8 million barrels of probable bitumen reserves and increased
contingent resource estimates net to Enerplus. A key factor in the increased
contingent resource estimates for the bitumen was a change from 12:1 total
volume to bitumen in place ratio ("TV:BIP") to 15:1 TV:BIP ratio. TV:BIP
measures the total volume of material (dirt, sand and bitumen) relative to the
volume of bitumen in place; it considers how much dirt must be removed to
access the bitumen deposit and the ore grade, or the richness of the deposit.
The higher costs associated with mining at higher TV:BIP ratios is more than
offset by higher commodity prices. While the operator is still determining the
optimal lease development plan for the lease, should the mining area expand we
would expect higher overall recoveries from the lease given the higher
recovery rate for mining versus SAGD.
The Joslyn lease currently has two key mining areas (North and South) and
a SAGD area with expansion potential. The existing SAGD project continues to
run behind expectations. The operator does not expect to drill any new well
pairs or achieve commercial production on the project until at least 2009
pending continued improvement in well performance. Production volumes at
year-end from the SAGD project were approximately 2,400 bbls/day gross,
(360 bbls/day net) to Enerplus. We expect the North mine regulatory
application to be approved in the second half of 2008. The extent of the South
mine and expansion potential for SAGD is currently being evaluated and we
expect to finalize these plans in 2008 with the operator. We are also
expecting to finalize an expanded joint operating agreement and our downstream
marketing plans in 2008. A South mine regulatory application is expected to be
made once lease development plans have been determined. As the lease
development plans have not been finalized and significant engineering work is
underway, we do not have any current estimates of the future capital
requirements associated with the lease. We expect to report capital spending
estimates once the lease development plan is complete. There are no proved or
probable reserves associated with the Joslyn mining development included in
our year-end reserves report.
Joslyn Oil Sands Reserves & Resource Estimates
(based upon Enerplus working interests, million barrels of bitumen)
The following table outlines the reserves and resources associated with
the Joslyn lease as estimated by GLJ utilizing the Norwest mining report
received late in 2007. The improved estimates at December 31, 2007 indicate
that the lease could support up to 240,000 bbls/day of gross production
(36,000 bbls/day net) including both SAGD and mining activities.
Mine Contingent Total P+P Reserves
SAGD Proved plus Resource & Contingent
Probable Reserves "Best" Estimate Resource Estimate
(GLJ) (GLJ) (GLJ)
(MMbbls) (MMbbls) (MMbbls)
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2006 Year-End 56.7 223 280
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2007 Year-End:
Full mine with
10,000 bbl/day
SAGD 11.0 359 370
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Smaller mine with
25,000 bbl/day
SAGD 63.5 252 315
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Year-over-Year
Change -45.7 to +6.8 +29 to 136 +35 to 89
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Mine estimates are contingent resource estimates using a 12:1 TV:BIP
ratio at December 31, 2006 and a 15:1 TV:BIP ratio at December 31, 2007. There
is no certainty that it will be commercially viable to produce any portion of
the resources. For information on contingent resource estimates and the risks
and uncertainties associated therewith, see "Information Regarding Disclosure
in this News Release and Oil and Gas Reserves, Resources and Operational
Information" at the conclusion of this news release.
Laricina
--------
In 2005, we formed a joint venture with Laricina Energy Ltd., a private
oil sands company focused on SAGD development in the Athabasca oil sands
fairway. As part of this joint venture, Enerplus swapped a 1% working interest
in the Joslyn lease for approximately 20% equity value in Laricina, including
an area of mutual interest agreement which has now expired. Over the past two
years, we have participated in four land acquisitions and in 2007 invested
approximately $8 million in an effort to delineate the potential on these
lands. We believe the value of our equity investment has appreciated
significantly since 2005 and based upon a recent financing by Laricina, we
would value our investment at approximately $140 million and own approximately
12% of the total shares outstanding.
2008 PRODUCTION AND CAPITAL SPENDING PLANS
On December 3, 2007, Enerplus announced pro-forma 2008 guidance assuming
the merger between Enerplus and Focus occurred January 1, 2008. The actual
closing date of the merger was February 13, 2008, and therefore we have
revised our 2008 guidance to reflect the combined results of Enerplus and
Focus from that date forward.
We anticipate that our average daily production volumes will increase
significantly in 2008 to approximately 98,000 BOE/day representing a
production estimate of approximately 80,000 BOE/day from Enerplus and a pro-
rated estimate of 18,000 BOE/day from the Focus assets. Given the timing of
our capital development program, we expect to exit 2008 with production of
approximately 100,000 BOE/day.
We also intend to significantly increase our capital spending plans in
2008 as a result of the Focus transaction and our investment in the oil sands.
We currently expect to spend approximately $580 million in total with
approximately $475 million directed to conventional oil and gas with a slight
bias to oil related projects over natural gas projects. Over 70% of our
capital program is currently dedicated to resource play assets which we
believe offer lower risk, repeatable development opportunities and
approximately 75% of the spending is anticipated to be on operated properties.
We also expect our spending on activities such as land, seismic and
exploration will account for approximately 15% of our conventional spending
which helps to create opportunities in the future. We expect our drilling
activity to virtually double in 2008 as we focus our activities on shallow
natural gas development in southeastern Alberta and southwestern Saskatchewan.
Our largest expenditures are expected to be in shallow gas, particularly the
Shackleton property in Saskatchewan where we now operate, and on our crude oil
waterflood properties across the Western Canadian Sedimentary Basin.
We are currently estimating capital spending of approximately
$105 million dedicated to our oil sands portfolio in 2008. This spending is
evenly split between Kirby and Joslyn with the Kirby spending concentrated on
the initial core hole drilling program and regulatory project application and
Joslyn spending focused on advancing the mining interests. We expect capital
spending on our oil sands assets to continue to increase over the next few
years and as a result, we are reviewing our options for financing which could
include the sale of a portion of our oil sands portfolio as well as debt,
partnering opportunities and special purposes equity alternatives.
2008 Estimated 2008 Estimated 2008 Estimated
Average Drilling Capital
Daily Production Activity Spending
Play Types (BOE/day) (Net Wells) ($MM)
-------------------------------------------------------------------------
Shallow Gas
& CBM 25,000 371 $128
Crude Oil
Waterfloods 16,000 49 105
Deep Tight Gas 13,800 20 53
Bakken Oil 10,800 6 47
Other
Conventional
Oil & Gas 32,400 61 142
-------------------------------------------------------------------------
Total
Conventional 98,000 507 $475
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil Sands - n/a 105
-------------------------------------------------------------------------
Total Company 98,000 507 $580
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Includes the Focus assets effective February 13, 2008
ACQUISITIONS & DIVESTMENTS
In 2007 Enerplus acquired approximately 4.3 million BOE of company
interest proved plus probable conventional oil and gas reserves, the majority
of which was through the acquisition of gross overriding royalty ("GORR")
interests in the state of Wyoming for consideration of $61 million. The assets
produce natural gas from the Jonah field in Wyoming, which is one of the
largest gas fields in the U.S. We acquired an effective interest of
approximately 540 BOE/day of daily production and approximately 2.2 million
BOE of proved reserves and 2.9 million BOE of proved plus probable reserves at
Jonah. We believe the field has a significant number of additional infill
drilling locations that will provide growth potential for the future and to
date have seen a 10% increase in our net production volumes. Enerplus is not
required to pay any capital or operating costs on the assets.
We also acquired a 100% working interest in the Kirby oil sands lease for
$203.1 million as described more fully in the oil sands section of this
release. The following table outlines our acquisition and divestment activity
in 2007.
2007 Acquisition & Divestment Summary
Cost of
Proved Proved
plus plus Cost per
Cost/ Probable Probable Daily
Proceeds(*) Reserves Production Reserves Barrel
Conventional Oil & Gas ($MM) (MBOE) (BOE/day) ($/BOE) ($000)
-------------------------------------------------------------------------
Acquisitions $ 71.1 4,773 667 $ 14.90 $ 106.6
Divestments 9.6 523 128 18.36 75.0
-------------------------------------------------------------------------
Net Conventional Oil
& Gas Acquisitions $ 61.5 4,250 539 $ 14.47 $ 114.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil Sands
Acquisitions(xx) $203.1 - - n/a n/a
-------------------------------------------------------------------------
(*) After adjustment for working capital and excluding future
development
(xx) The Kirby lease has been assessed by GLJ as containing a best
estimate of 244 MMBOE of bitumen contingent resources. For
information on contingent resource estimates and the risks and
uncertainties associated therewith, see "Information Regarding
Disclosure in this News Release and Oil and Gas Reserves,
Resources and Operational Information" at the conclusion of this
news release
RESERVES
Total proved plus probable reserves at December 31, 2007 were 440
million BOE, down less than 1% from 2006 levels. Through our development and
acquisition activities, we replaced 90% of produced volumes including the
addition of 6.8 million barrels from our oil sands properties. Over the last
5 years we have replaced on average 179% of produced volumes including
acquisition and divestment activity.
Enerplus has built a large, diversified portfolio of conventional and
unconventional capital projects that we believe will support our operations in
the years ahead through the addition of production and reserves. We estimate
our current inventory of conventional capital projects at over $2.3 billion
representing over 4,000 net wells excluding any future capital associated with
our oil sands activities. This includes approximately $430 million of
estimated future development potential that was added through the Focus
acquisition ($320 million at Shackleton and $85 million at Tommy Lakes) and in
total represents approximately four to five years of conventional future
development potential at current capital spending levels assuming no new
acquisitions or changes of strategies on existing properties. We believe this
opportunity set includes significant potential across our entire asset base
and capital projects which are both technically and economically viable at
today's commodity prices. Future development capital estimates associated with
our oil sands activities are not currently available but we expect to provide
such estimate later in 2008. We continue to expect production volumes in the
range of 60,000 bbls/day net to Enerplus from our current oil sands projects
once all such projects, as currently planned, have reached their peak
production rates.
The following table highlights our year end reserves, reserve life index
and future development potential by resource play. Approximately 75% of proved
plus probable reserves are attributable to resource plays.
Proved
plus Future
Proved Probable Devel-
Plus Reserve opment
Proved Probable Probable Life Opport-
Reserves Reserves Reserves Index unities
Conventional Play Types (MMBOE) (MMBOE) (MMBOE) (years) ($MM)
-------------------------------------------------------------------------
Crude Oil Waterfloods 80.3 20.9 101.2 17.3 $ 350
Shallow Gas & CBM 65.7 25.9 91.7 17.4 640
Deep Tight Gas 23.5 7.7 31.2 10.3 225
Bakken Oil 30.8 10.8 41.6 10.1 280
Other Conventional
Oil & Gas 81.0 30.1 111.0 9.9 850
-------------------------------------------------------------------------
Total Conventional 281.3 95.4 376.7 12.8 $2,345
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil Sands 8.6 54.9 63.5 n/a TBA
-------------------------------------------------------------------------
Total Company 289.9 150.3 440.2 14.8 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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. Three external,
independent third party engineering firms were used to evaluate and review our
reserves this year. Sproule, our historical independent engineering
evaluators, evaluated our Canadian conventional reserves. GLJ evaluated the
Joslyn SAGD bitumen reserves as they have previously performed such
evaluations for the operator of the Joslyn project. Netherland, Sewell
Associates Inc. ("NSA") of Dallas, Texas evaluated the reserves attributed to
our assets in the United States. Sproule evaluated 92% of the total proved
plus probable value (discounted at 10%) of our Canadian conventional year-end
reserves and has reviewed the remainder of the reserves which were internally
evaluated by Enerplus. Both GLJ and NSA evaluated 100% of the reserves in
their respective areas and utilized Sproule's forecast price and cost
assumptions as of December 31, 2007 in their evaluations to maintain
consistency among our reserve reporting.
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.
2007 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 63,963 28,832 2,365 95,160 10,469 649,382 213,860
United
States 21,672 - - 21,672 74 28,527 26,501
-------------------------------------------------------------------------
Total 85,635 28,832 2,365 116,832 10,543 677,909 240,361
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved
developed
non-producing
Canada 190 - - 190 510 14,911 3,185
United
States 1,588 - - 1,588 5 1,623 1,863
-------------------------------------------------------------------------
Total 1,778 - - 1,778 515 16,534 5,048
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved
undeveloped
Canada 3,233 2,383 6,203 11,819 694 164,829 39,984
United
States 3,377 - - 3,377 33 6,805 4,544
-------------------------------------------------------------------------
Total 6,610 2,383 6,203 15,196 727 171,634 44,528
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved
Canada 67,386 31,215 8,568 107,169 11,673 829,122 257,029
United
States 26,637 - - 26,637 112 36,955 32,908
-------------------------------------------------------------------------
Total 94,023 31,215 8,568 133,806 11,785 866,077 289,937
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable
Canada 17,837 10,948 54,930 83,715 3,797 308,276 138,891
United
States 6,719 - - 6,719 30 27,938 11,406
-------------------------------------------------------------------------
Total 24,556 10,948 54,930 90,434 3,827 336,214 150,297
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved
plus
Probable
Canada 85,223 42,163 63,498 190,884 15,470 1,137,398 395,920
United
States 33,356 - - 33,356 142 64,893 44,314
-------------------------------------------------------------------------
Total 118,579 42,163 63,498 224,240 15,612 1,202,291 440,234
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 to December 31, 2007.
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,
2006 70,504 31,153 8,730 110,387 12,690 905,261 273,954
-------------------------------------------------------------------------
Acquisitions 2 - - 2 4 3,496 588
Divestments - - - - - (2,814) (469)
Discoveries 251 - - 251 5 178 285
Extensions 849 - - 849 550 22,574 5,161
Improved
Recovery 961 1,870 - 2,831 21 7,838 4,158
Economic
Factors 1,581 548 - 2,129 114 5,527 3,164
Technical
Revisions (986) 844 (162) (304) (214) (21,118) (4,036)
Production (5,776) (3,200) - (8,976) (1,497) (91,820) (25,776)
-------------------------------------------------------------------------
Proved
Reserves at
Dec. 31,
2007 67,386 31,215 8,568 107,169 11,673 829,122 257,029
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 23,391 - - 23,391 - 14,800 25,858
-------------------------------------------------------------------------
Acquisitions - - - - 124 13,311 2,343
Divestments - - - - - - -
Discoveries - - - - - - -
Extensions 66 - - 66 - 36 72
Improved
Recovery 6,772 - - 6,772 - 5,585 7,703
Economic
Factors - - - - - - -
Technical
Revisions 15 - - 15 - 7,126 1,202
Production (3,607) - - (3,607) (12) (3,903) (4,270)
-------------------------------------------------------------------------
Proved
Reserves at
Dec. 31,
2007 26,637 - - 26,637 112 36,955 32,908
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 93,895 31,153 8,730 133,778 12,690 920,061 299,812
-------------------------------------------------------------------------
Acquisitions 2 - - 2 128 16,807 2,931
Divestments - - - - - (2,814) (469)
Discoveries 251 - - 251 5 178 285
Extensions 915 - - 915 550 22,610 5,233
Improved
Recovery 7,733 1,870 - 9,603 21 13,423 11,861
Economic
Factors 1,581 548 - 2,129 114 5,527 3,164
Technical
Revisions (971) 844 (162) (289) (214) (13,992) (2,834)
Production (9,383) (3,200) - (12,583) (1,509) (95,723) (30,046)
-------------------------------------------------------------------------
Proved
Reserves at
Dec. 31,
2007 94,023 31,215 8,568 133,806 11,785 866,077 289,937
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 16,872 8,912 47,998 73,782 3,777 306,804 128,693
-------------------------------------------------------------------------
Acquisitions - - - - - 7,532 1,256
Divestments - - - - - (325) (54)
Discoveries 63 - - 63 1 45 72
Extensions 378 - 4,064 4,442 172 6,829 5,753
Improved
Recovery 276 1,301 - 1,577 16 3,193 2,125
Economic
Factors 343 338 - 681 20 1,156 894
Technical
Revisions (95) 397 2,868 3,170 (189) (16,958) 152
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2007 17,837 10,948 54,930 83,715 3,797 308,276 138,891
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 8,637 - - 8,637 - 37,221 14,840
-------------------------------------------------------------------------
Acquisitions - - - - 30 3,340 586
Divestments - - - - - - -
Discoveries - - - - - - -
Extensions 16 - - 16 - 37 22
Improved
Recovery 1,378 - - 1,378 - 5,106 2,229
Economic
Factors - - - - - - -
Technical
Revisions (3,312) - - (3,312) - (17,766) (6,271)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2007 6,719 - - 6,719 30 27,938 11,406
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 25,509 8,912 47,998 82,419 3,777 344,025 143,533
-------------------------------------------------------------------------
Acquisitions - - - - 30 10,872 1,842
Divestments - - - - - (325) (54)
Discoveries 63 - - 63 1 45 72
Extensions 394 - 4,064 4,458 172 6,866 5,775
Improved
Recovery 1,654 1,301 - 2,955 16 8,299 4,354
Economic
Factors 343 338 - 681 20 1,156 894
Technical
Revisions (3,407) 397 2,868 (142) (189) (34,724) (6,119)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2007 24,556 10,948 54,930 90,434 3,827 336,214 150,297
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 87,376 40,065 56,728 184,169 16,467 1,212,065 402,647
-------------------------------------------------------------------------
Acquisitions 2 - - 2 4 11,028 1,844
Divestments - - - - - (3,139) (523)
Discoveries 314 - - 314 6 223 357
Extensions 1,227 - 4,064 5,291 722 29,403 10,914
Improved
Recovery 1,237 3,171 - 4,408 37 11,031 6,283
Economic
Factors 1,924 886 - 2,810 134 6,683 4,058
Technical
Revisions (1,081) 1,241 2,706 2,866 (403) (38,076) (3,884)
Production (5,776) (3,200) - (8,976) (1,497) (91,820) (25,776)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2007 85,223 42,163 63,498 190,884 15,470 1,137,398 395,920
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 32,028 - - 32,028 - 52,021 40,698
-------------------------------------------------------------------------
Acquisitions - - - - 154 16,651 2,929
Divestments - - - - - - -
Discoveries - - - - - - -
Extensions 82 - - 82 - 73 94
Improved
Recovery 8,150 - - 8,150 - 10,691 9,932
Economic
Factors - - - - - - -
Technical
Revisions (3,297) - - (3,297) - (10,640) (5,069)
Production (3,607) - - (3,607) (12) (3,903) (4,270)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2007 33,356 - - 33,356 142 64,893 44,314
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
2006 119,404 40,065 56,728 216,197 16,467 1,264,086 443,345
-------------------------------------------------------------------------
Acquisitions 2 - - 2 158 27,679 4,773
Divestments - - - - - (3,139) (523)
Discoveries 314 - - 314 6 223 357
Extensions 1,309 - 4,064 5,373 722 29,476 11,008
Improved
Recovery 9,387 3,171 - 12,558 37 21,722 16,215
Economic
Factors 1,924 886 - 2,810 134 6,683 4,058
Technical
Revisions (4,378) 1,241 2,706 (431) (403) (48,716) (8,953)
Production (9,383) (3,200) - (12,583) (1,509) (95,723) (30,046)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2007 118,579 42,163 63,498 224,240 15,612 1,202,291 440,234
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 and 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
following information does not give effect to the proposed revised Alberta
royalty regime as no legislation has yet been introduced to pass the proposed
new royalty regime into law.
The net estimated present value of all future net revenues at
December 31, 2007 was based upon forecast crude oil and natural gas pricing
assumptions prepared by Sproule as of December 31, 2007. These prices were
applied to the reserves evaluated by Sproule, GLJ and NSA. The base reference
prices and exchange rates used by Sproule are detailed below:
Sproule December 31, 2007 - Forecast Price Assumptions
-------------------------------------------------------------------------
Differ-
ential
Between Natural
Hardisty Gas
Heavy 30 day
Hardisty And Henry spot
WTI Light Heavy Bitumen(2) Hub @
crude crude(1) 12(degrees) (Oil Price AECO Exchange
oil Edmonton API Sands) US$/ CDN$/ Rate
US$/bbl CDN$/bbl CDN$/bbl CDN$/bbl MMbtu MMbtu US$/CDN$
-------------------------------------------------------------------------
2008 $89.61 $88.17 $54.67 $20.50 $7.56 $6.51 $1.00
2009 86.01 84.54 52.42 15.96 8.27 7.22 1.00
2010 84.65 83.16 51.56 14.02 8.74 7.69 1.00
2011 82.77 81.26 50.38 12.05 8.75 7.70 1.00
2012 82.26 80.73 50.05 12.02 8.66 7.61 1.00
There-
after (xx) (xx) (xx) (xx) 2.0% (xx) 1.00
-------------------------------------------------------------------------
(1) Edmonton refinery postings for 40 degree API, 0.4% sulphur content
crude
(2) The bitumen price is derived by GLJ from Sproule's forecasts of
various stream prices
(xx) Escalation varies after 2012
Net Present Value of Future Production Revenue- Forecast Prices and Costs
(Before Tax)
At December 31, 2007
-------------------------------------------------------------------------
Conventional Reserves ($ Millions,
before tax, discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing $ 8,661 $ 5,602 $ 4,252 $ 3,487
Proved developed non-producing 187 127 95 76
Proved undeveloped 827 512 334 223
-------------------------------------------------------------------------
Total Proved $ 9,675 $ 6,241 $ 4,681 $ 3,786
Probable 3,805 1,740 1,032 707
-------------------------------------------------------------------------
Total Proved Plus Probable
Conventional Reserves $ 13,480 $ 7,981 $ 5,713 $ 4,493
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bitumen Reserves
Proved developed producing $ 35 $ 28 $ 23 $ 19
Proved undeveloped 100 56 32 19
-------------------------------------------------------------------------
Total Proved 135 84 55 38
Probable 1,293 294 89 29
-------------------------------------------------------------------------
Total Proved plus Probable
Bitumen Reserves $ 1,428 $ 378 $ 144 $ 67
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Conventional
and Bitumen Reserves $ 14,908 $ 8,359 $ 5,857 $ 4,560
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (after Tax) at December 31, 2007
Conventional Reserves
($ Millions, discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing $ 7,316 $ 4,890 $ 3,787 $ 3,146
Proved developed non-producing 132 91 67 53
Proved undeveloped 670 406 259 167
-------------------------------------------------------------------------
Total Proved $ 8,118 $ 5,387 $ 4,113 $ 3,366
Probable 2,838 1,314 789 546
-------------------------------------------------------------------------
Total Proved Plus Probable
Conventional Reserves $ 10,956 $ 6,701 $ 4,902 $ 3,912
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bitumen Reserves
Proved developed producing $ 28 $ 22 $ 19 $ 15
Proved developed non-producing 72 40 22 13
-------------------------------------------------------------------------
Total Proved $ 100 $ 62 $ 41 $ 28
Probable 928 207 59 15
-------------------------------------------------------------------------
Total Proved plus Probable
Bitumen Reserves $ 1,028 $ 269 $ 100 $ 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Conventional
and Bitumen Reserves $ 11,984 $ 6,970 $ 5,002 $ 3,955
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET ASSET VALUE
Enerplus' estimated net asset value is measured with reference to the net
present value of all future net revenue from our reserves as estimated by our
independent reserve engineers (Sproule, GLJ 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 22 year history of replacing production through acquisitions and
development.
In addition, we are including an estimated net asset value of our oil
sands portfolio to approximate the value of these assets. We used a market
valuation if a recent third party, arms length transaction had occurred
subsequent to our investment or our original investment cost if no such
transaction had occurred.
Forecast Prices and Costs at December 31, 2007
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 $13,480 $ 7,981 $ 5,713 $ 4,493
Undeveloped acreage 66 66 66 66
Asset retirement obligations (292) (148) (49) (26)
Long-term debt (net of cash) (725) (725) (725) (725)
Net Working Capital excluding
deferred financial asset,
distributions to unitholders,
deferred credits,
and future income tax (117) (117) (117) (117)
-------------------------------------------------------------------------
Net Asset Value of
Conventional Assets(1) $12,412 $ 7,057 $ 4,888 $ 3,691
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per Trust Unit
- Conventional Assets(1)(2) $ 95.61 $ 54.36 $ 37.65 $ 28.43
-------------------------------------------------------------------------
Oil Sands
Value of Joslyn Lease(3) $ 340.0 $ 340.0 $ 340.0 $ 340.0
Value of Kirby Oil Sands Lease(4) 205.4 205.4 205.4 205.4
Laricina Equity Investment(5) 139.9 139.9 139.9 139.9
Undeveloped Oil Sands acreage(6) 10.7 10.7 10.7 10.7
-------------------------------------------------------------------------
Net Asset Value of Oil Sands
Assets $ 695.9 $ 695.9 $ 695.9 $ 695.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per Trust Unit
- Oil Sands $ 5.36 $ 5.36 $ 5.36 $ 5.36
Total Net Asset Value
per Trust Unit(2) $100.97 $ 59.72 $ 43.01 $ 33.79
-------------------------------------------------------------------------
(1) Asset retirement obligations ("ARO") do not equal the amount on the
balance sheet ($165.7 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
(2) Based on 129,813,000 trust units outstanding at December 31, 2007
(3) Joslyn valuation represents 15% working interest valued using Total's
purchase price of Deer Creek in 2005 including development capital
spent since the Total purchase
(4) Kirby valuation represents $203.1 MM purchase price plus capital
spending of $2.3 MM since acquisition
(5) Laricina equity investment represents 4,305,675 shares at most recent
equity offering of $32.50/share
(6) Undeveloped oil sands acreage valued at cost of land acquisitions and
development capital spent on those lands.
RESERVE LIFE INDEX ("RLI")
Enerplus has maintained one of the longest RLIs in the sector throughout
our 22 year history. In 2007, our RLI increased from 12.2 years to 12.8 years
on our conventional oil and gas reserves (proved plus probable) and from
14.0 years to 14.8 years on an overall basis including oil sands using both
proved and probable reserves. Subsequent to the Focus transaction, our proved
plus probable RLI decreased to 14.0 years.
As at December 31 Post Focus 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
Without Oil Sands
Proved 9.7 10.0 9.8 9.6 10.1 10.6
Proved plus Probable 12.4 12.8 12.2 12.0 12.4 13.3
-------------------------------------------------------------------------
With Oil Sands
Proved 9.9 10.3 10.1 9.9 10.1 10.6
Proved plus Probable 14.0 14.8 14.0 13.5 14.0 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")
Through our conventional capital development program, we added
27.6 million BOE of proved plus probable reserves. Unfortunately, we also
experienced negative technical revisions of 11.7 million proved plus probable
BOE. On a net basis, our capital development program added 15.9 million BOE
resulting in F&D costs of $19.97/BOE on our conventional oil and gas assets on
a proved plus probable basis.
Our total spending on our conventional asset base delivered a FD&A cost
of $19.79/BOE on a proved plus probable basis including future development
capital ("FDC"). Our three-year conventional proved plus probable FD&A was
$19.57/BOE including changes in future development capital.
F&D costs on our oil sands assets were $21.16/bbl based on proved plus
probable reserves which reflects a significant increase in FDC associated with
the SAGD development. Our oil sands acquisition activity consisted solely of
the acquisition of the Kirby lease which did not add any reserves or
production but has a contingent resource estimate of 244 million barrels as
described above. As we move forward with the development of the Kirby lease,
we expect to move contingent resources into the probable reserve category. Our
proved plus probable oil sands FD&A cost in 2007 was $51.03/bbl.
Combined our 2007 corporate F&D cost was $20.33/BOE and our FD&A cost was
$27.69/BOE (both measures including changes in FDC). Our three-year average
F&D cost was $17.96/BOE and our three-year average FD&A cost was $20.69/BOE.
F&D and FD&A costs can be calculated either including or excluding future
development capital. F&D and FD&A costs calculated under NI 51-101 include
future development capital as this provides a more representative view of the
full cost of reserve additions as it accounts for future costs to bring the
reserves to market. Under the historic method, F&D and FD&A costs are
understated as reserves are included without taking into account the future
capital expenditures required to fully develop the reserve base. We have
included both the NI 51-101 method which includes future development capital
and the historic method for comparison purposes. The aggregate of the
exploration and development costs incurred in the most recent financial year
and the change during that year in estimated future development costs
generally will not reflect total finding and development costs related to
reserves additions for that year. For information on the use of the term "BOE"
see "Information Regarding Disclosure in this News Release and Oil and Gas
Reserves, Resources and Operational Information" at the conclusion of this
news release.
F&D and FD&A Costs (Including Future
Development Capital)
($ millions except for per BOE amounts) 2007 2006 2005
-------------------------------------------------------------------------
Proved Reserves
Conventional Oil & Gas
-------------------------------------------------------------------------
Capital Expenditures $ 348.3 $ 452.1 $ 335.5
Net change in Future
Development Capital $ 39.3 $ 22.3 $ 97.4
Gross Reserve additions (MMBOE) 17.9 16.1 28.8
F&D costs ($/BOE) $ 21.65 $ 29.47 $ 15.03
Three year averages F&D cost
($/BOE)(1) $ 20.62 $ 15.54 n/a
Capital Expenditures
and net acquisitions $ 409.8 $ 502.0 $ 973.0
Net change in Future Developments
Costs $ 48.5 $ 8.0 $ 184.7
Gross company reserve additions (MMBOE) 20.4 18.6 53.7
FD&A costs ($/BOE) $ 22.47 $ 27.42 $ 21.56
Three year average FD&A costs
($/BOE)(1) $ 22.93 $ 19.80 $ 24.02
Oil Sands
-------------------------------------------------------------------------
Capital Expenditures $ 38.9 $ 39.1 $ 33.2
Net change in Future
Development Capital $ (1.7) $ (10.8) $ 44.6
Gross Reserve additions (MMBOE) (0.2) (0.1) 9.5
F&D costs ($/BOE) $ (186.00) $(283.00) $ 8.19
Three year averages F&D cost
($/BOE)(1) $ 15.58 $ 12.17 $ 9.51
Capital Expenditures
and net acquisitions $ 242.0 $ 19.4 $ 33.2
Net change in Future Development Costs $ (1.7) $ (13.6) $ 44.6
Gross company reserve additions (MMBOE) (0.2) (0.7) 9.5
FD&A costs ($/BOE) $(1,201.50) $ (8.29) $ 8.19
Three year average FD&A
costs ($/BOE)(1) $ 37.66 $ 10.44 $ 9.51
Total Fund
-------------------------------------------------------------------------
Capital Expenditures $ 387.2 $ 491.2 $ 368.7
Net change in Future
Development Capital $ 37.6 $ 11.5 $ 142.0
Gross Reserve additions (MMBOE) 17.7 16.0 38.3
F&D costs ($/BOE) $ 24.00 $ 31.42 $ 13.33
Three year averages F&D
cost ($/BOE)(1) $ 19.98 $ 15.16 n/a
Capital Expenditures and
net acquisitions $ 651.8 $ 521.4 $1,006.2
Net change in Future Development Costs $ 46.8 $ (5.6) $ 229.3
Gross company reserve additions (MMBOE) 20.2 17.9 63.2
FD&A costs ($/BOE) $ 34.58 $ 28.82 $ 19.55
Three year average FD&A
costs ($/BOE)(1) $ 24.18 $ 19.20 $ 22.73
-------------------------------------------------------------------------
Proved Plus Probable Reserves
($ millions except for per BOE amounts) 2007 2006 2005
Conventional Oil & Gas
-------------------------------------------------------------------------
Capital Expenditures $ 348.3 $ 452.1 $ 335.5
Net change in Future
Development Capital $ (30.7) $ 50.7 $ 92.1
Gross Reserve additions (MMBOE) 15.9 18.3 32.0
F&D costs ($/BOE) $ 19.97 $ 27.48 $ 13.36
Three year averages F&D
cost ($/BOE)(1) $ 18.85 $ 20.22 n/a
Capital Expenditures
and net acquisitions $ 409.8 $ 502.0 $ 973.0
Net change in Future Development Costs $ (12.0) $ 54.4 $ 197.7
Gross company reserve additions (MMBOE) 20.1 21.9 66.6
FD&A costs ($/BOE) $ 19.79 $ 25.41 $ 17.58
Three year average FD&A
costs ($/BOE)(1) $ 19.57 $ 18.10 $ 15.97
Oil Sands
-------------------------------------------------------------------------
Capital Expenditures $ 38.9 $ 39.1 $ 33.2
Net change in Future
Development Capital $ 105.0 $ 34.3 $ 33.4
Gross Reserve additions (MMBOE) 6.8 6.9 5.4
F&D costs ($/BOE) $ 21.16 $ 10.64 $ 12.33
Three year averages F&D
cost ($/BOE)(1) $ 14.86 $ 6.91 n/a
Capital Expenditures
and net acquisitions $ 242.0 $ 19.4 $ 33.2
Net change in Future
Development Costs $ 105.0 $ 15.6 $ 33.4
Gross company reserve additions (MMBOE) 6.8 3.6 5.4
FD&A costs ($/BOE)(1) $ 51.03 $ 9.72 $ 12.33
Three year average FD&A
costs ($/BOE)(1) $ 28.39 $ 6.63 $ 6.50
Total Fund
-------------------------------------------------------------------------
Capital Expenditures $ 387.2 $ 491.2 $ 368.7
Net change in Future
Development Capital $ 74.3 $ 85.0 $ 125.5
Gross Reserve additions (MMBOE) 22.7 25.2 37.4
F&D costs ($/BOE) $ 20.33 $ 22.87 $ 13.21
Three year averages F&D
cost ($/BOE)(1) $ 17.96 $ 13.52 n/a
Capital Expenditures
and net acquisitions $ 651.8 $ 521.4 $1,006.2
Net change in Future Development Costs $ 93.0 $ 70.0 $ 231.1
Gross company reserve additions (MMBOE) 26.9 25.5 72.0
FD&A costs ($/BOE)(1) $ 27.69 $ 23.19 $ 17.18
Three year average FD&A
costs ($/BOE)(1) $ 20.69 $ 14.90 $ 13.46
-------------------------------------------------------------------------
(1) Calculated over a three year period.
F&D and FD&A Costs (Excluding Future
Development Capital)
($ millions except for per BOE amounts) 2007 2006 2005
-------------------------------------------------------------------------
Proved Reserves
Conventional Oil & Gas
-------------------------------------------------------------------------
Capital Expenditures $ 348.3 $ 452.1 $ 335.5
Gross Reserve additions (MMBOE) 17.9 16.1 28.8
F&D Cost ($/BOE) $ 19.46 $ 28.08 $ 11.65
Three year averages F&D
costs ($/BOE)(1) $ 18.09 $ 13.17 $ 9.87
Capital Expenditures
and net acquisitions $ 409.8 $ 502.0 $ 973.0
Gross company reserve additions (MMBOE) 20.4 18.6 53.7
FD&A costs ($/BOE) $ 20.09 $ 26.99 $ 18.12
Three year average FD&A
costs ($/BOE)(1) $ 20.33 $ 17.55 $ 14.94
Oil Sands
-------------------------------------------------------------------------
Capital Expenditures $ 38.9 $ 39.1 $ 33.2
Gross Reserve additions (MMBOE) (0.2) (0.1) 9.5
F&D Cost ($/BOE) $ (194.50) $(391.00) $ 3.49
Three year averages F&D
costs ($/BOE)(1) $ 12.09 $ 8.57 $ 4.81
Capital Expenditures
and net acquisitions $ 242.0 $ 19.4 $ 33.2
Gross company reserve additions (MMBOE) (0.2) (0.7) 9.5
FD&A costs ($/BOE) $(1,210.00) $(27.71) $ 3.49
Three year average FD&A
costs ($/BOE)(1) $ 34.26 $ 6.92 $ 4.81
Total Fund
-------------------------------------------------------------------------
Capital Expenditures $ 387.2 $ 491.2 $ 368.7
Gross Reserve additions (MMBOE) 17.7 16.0 38.3
F&D Cost ($/BOE) $ 21.88 $ 30.70 $ 9.63
Three year averages F&D
costs ($/BOE)(1) $ 17.32 $ 12.65 $ 9.26
Capital Expenditures
and net acquisitions $ 651.8 $ 521.4 $1,006.2
Gross company reserve additions (MMBOE) 20.2 17.9 63.2
FD&A costs ($/BOE) $ 32.27 $ 29.13 $ 15.92
Three year average FD&A
costs ($/BOE)(1) $ 21.51 $ 16.88 $ 14.30
Proved Plus Probable Reserves
Conventional Oil & Gas
-------------------------------------------------------------------------
Capital Expenditures $ 348.3 $ 452.1 $ 335.5
Gross Reserve additions (MMBOE) 15.9 18.3 32.0
F&D Cost ($/BOE) $ 21.91 $ 24.70 $ 10.48
Three year averages F&D
costs ($/BOE)(1) $ 17.16 $ 16.66 $ 12.48
Capital Expenditures
and net acquisitions $ 409.8 $ 502.0 $ 973.0
Gross company reserve additions (MMBOE) 20.1 21.9 66.6
FD&A costs ($/BOE) $ 20.39 $ 22.92 $ 14.61
Three year average FD&A
costs ($/BOE)(1) $ 17.36 $ 15.55 $ 13.20
Oil Sands
-------------------------------------------------------------------------
Capital Expenditures $ 38.9 $ 39.1 $ 33.2
Gross Reserve additions (MMBOE) 6.8 6.9 5.4
F&D Cost ($/BOE) $ 5.72 $ 5.67 $ 6.15
Three year averages F&D
costs ($/BOE)(1) $ 5.82 $ 1.34 $ 0.86
Capital Expenditures
and net acquisitions $ 242.0 $ 19.4 $ 33.2
Gross company reserve additions (MMBOE) 6.8 3.6 5.4
FD&A costs ($/BOE) $ 35.59 $ 5.39 $ 6.15
Three year average FD&A
costs ($/BOE)(1) $ 18.65 $ 1.07 $ 0.86
Total Fund
-------------------------------------------------------------------------
Capital Expenditures $ 387.2 $ 491.2 $ 368.7
Gross Reserve additions (MMBOE) 22.7 25.2 37.4
F&D Cost ($/BOE) $ 17.06 $ 19.49 $ 9.86
Three year averages F&D
costs ($/BOE)(1) $ 14.62 $ 8.95 $ 6.78
Capital Expenditures
and net acquisitions $ 651.8 $ 521.4 $1,006.2
Gross company reserve additions (MMBOE) 26.9 25.5 72.0
FD&A costs ($/BOE) $ 24.23 $ 20.45 $ 13.98
Three year average FD&A
costs ($/BOE)(1) $ 17.52 $ 11.51 $ 10.09
-------------------------------------------------------------------------
(1) Calculated over a three year period.
RECYCLE RATIO
Recycle ratio is calculated as operating income 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 has no operating income or proved plus probable
reserves.
Proved plus probable reserves 2007 2006 2005
-------------------------------------------------------------------------
Conventional Recycle Ratio 1.6x 1.2x 1.7x
Conventional 3-Year Average 1.5x 1.4x 1.6x
-------------------------------------------------------------------------
PRODUCTION AND RESERVES PER UNIT
Production and reserves per unit is an effective measure of
sustainability. 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. The last three years
Enerplus has enjoyed both a growing reserves and production per unit when
adjusted for debt and distributions which we believe compares favorably with
other oil and gas producers, whether they are trusts or traditional oil and
gas entities. Metrics in 2007 have been impacted by the acquisition and equity
financing of the Kirby oil sands project which does not add any current
production or reserves.
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.
Production per Debt and
Distribution-Adjusted Trust Unit 2007 2006 2005
-------------------------------------------------------------------------
Average daily production 82,319 85,779 79,727
Debt-adjusted weighted
average trust units (000's) 142,666 132,208 120,875
Production per debt-adjusted
trust unit (BOE/unit) 0.211 0.237 0.241
Production per debt and distribution
adjusted trust unit (BOE/unit) 0.392 0.390 0.365
-------------------------------------------------------------------------
Reserves per debt-adjusted trust unit is 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.
Reserves per Debt and
Distribution-Adjusted Trust Unit 2007 2006 2005
-------------------------------------------------------------------------
Year-end proved plus probable reserves 440,234 443,345 449,137
Debt-adjusted trust units outstanding
at year end (000's) 147,997 136,562 129,172
Reserves per debt-adjusted
trust unit (BOE/unit) 2.97 3.25 3.48
Reserves per debt and distribution
adjusted trust unit (BOE/unit) 5.43 5.32 5.19
-------------------------------------------------------------------------
HEALTH, SAFETY & ENVIRONMENT ("HS&E")
Enerplus continued to place a high emphasis on our HS&E program
throughout the year. We maintained our participation in the Canadian
Association of Petroleum Producer's stewardship program at the highest level,
Platinum, reduced our reportable spills and pipeline failures, increased our
remediation, reclamation and abandonment spending and had one of the best
safety records in our history.
Enerplus' safety performance record in 2007 saw no employee lost-time
injury incidents and only one employee medical aid injury recorded. This
resulted in a recordable injury frequency rate of 0.17 injuries per
200,000 man hours compared to 1.43 injuries per 200,000 man hours in 2006. In
addition, our contractor lost-time injury frequency substantially improved
from 0.97 injuries per 200,000 man hours in 2006 to a rate of 0.10 injuries in
2007. This improvement equates to having only one contractor lost-time injury
incident in all of 2007.
Remediation, reclamation and abandonment expenditures increased 31% year-
over-year to $20.5 million in 2007. Reclamation and site abandonment
expenditures for 2007 totaled $8.2 million up $2.1 million from 2006
expenditures due mainly to an increase in the number of wells abandoned during
the year. Site abandonment and reclamation occurs when areas are returned to
their original state once operations have been completed. Enerplus' 2007
reclamation activities resulted in 27 reclamation certificates being received
and 111 Phase II environmental assessments being completed. Remediation
expenditures for 2007 totaled $12.3 million up from $9.6 million in 2006.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated
February 27, 2008 and is to be read in conjunction with the audited
consolidated financial statements as at and for the years ended December 31,
2007 and 2006. All amounts are stated in Canadian dollars unless otherwise
specified. All references to GAAP refer to Canadian generally accepted
accounting principles. All note references relate to the notes included with
the consolidated financial statements. In accordance with Canadian practice
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. In addition to disclosing reserves under
the requirements of NI 51-101, we also disclose our reserves on a company
interest basis which is not a term defined under NI 51-101. This information
may not be comparable to similar measures presented by other issuers. Where
applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading.
The following MD&A contains forward-looking information and statements.
We refer you to the end of this news release for our disclaimer on forward-
looking information and statements.
NON-GAAP MEASURES
Throughout the MD&A we use the term "payout ratio" to analyze operating
performance, leverage and liquidity. We calculate payout ratio by dividing
cash distributions to unitholders ("cash distributions") by cash flow from
operating activities ("cash flow"), both of which appear on our consolidated
statements of cash flows. The term "payout ratio" does not have a standardized
meaning or definition as prescribed by GAAP and therefore may not be
comparable with the calculation of similar measures by other entities.
Refer to the Liquidity and Capital Resources section of the MD&A for
further information on cash flow, cash distributions and payout ratio.
2007 OVERVIEW
Cash flow from operating activities totaled $868.5 million in 2007,
essentially flat over 2006. Higher realized crude oil prices, cash gains
generated from our price risk management program and a decrease in our non-
cash working capital helped to mitigate the impact of lower production,
reduced natural gas prices and increased operating costs. Monthly cash
distributions remained constant at $0.42 per trust unit throughout 2007 for an
annual total of $5.04 per trust unit.
Our 2007 development capital spending totaled $387.2 million, resulting
in the drilling of 252 net wells with a 99% success rate. On January 31, 2007
we acquired gross-overriding royalty interests in the Jonah natural gas field
in Wyoming U.S. ("Jonah") for approximately $61 million. In the second quarter
we acquired the Kirby Oil Sands Partnership ("Kirby"), an operated Steam
Assisted Gravity Drainage ("SAGD") project, for $203.1 million ($148.3 million
in cash and $54.8 million in equity). An equity offering consisting of
4.25 million trust units for gross proceeds of $210.6 million was also
completed in conjunction with the Kirby acquisition.
During 2007 production averaged 82,319 BOE/day, in-line with our third
quarter guidance of 82,500 BOE/day and 4% below our 2006 production of
85,779 BOE/day. Reduced development capital spending, unplanned downtime,
lower initial production rates on our third well per section Bakken oil wells
and natural reservoir declines are the primary reasons for the decrease.
On June 22, 2007 the Federal Government enacted a new tax on publicly
traded income trusts and limited partnerships (specified investment flow-
through entities, or "SIFTs") effective January 1, 2011. As a result we
recorded a $78.1 million future income tax expense. We are currently
evaluating alternatives to determine the optimal structure for Enerplus post
2010 to maximize the return to investors. However, we see value in the
remaining three-year tax exemption period through 2010 and currently look to
maintaining our current structure during this period unless there are
compelling reasons to change. In the fourth quarter of 2007 the Alberta
Government also announced proposed changes to the provincial royalty program
effective January 1, 2009 which have not yet been enacted into law.
On February 13, 2008 we successfully closed the largest transaction in
our 22 year history, acquiring Focus Energy Trust ("Focus") for total
consideration of approximately $1.7 billion including approximately
$340 million of assumed debt. Under the plan of arrangement, Focus unitholders
received 0.425 of an Enerplus trust unit for each Focus trust unit. We believe
the combined entity is well positioned for future growth with a strong balance
sheet and production expected to be approximately 98,000 BOE/day in 2008.
RESULTS OF OPERATIONS
Production
Production during 2007 averaged 82,319 BOE/day, in-line with our third
quarter guidance of 82,500 BOE/day and 4% lower than 85,779 BOE/day in 2006.
Our 2007 production was impacted by the fact that we spent $104 million or 21%
less development capital than the prior year. In addition we experienced
unexpected down time and turn-around activities at partner operated
facilities. Our third well per section program at our U.S. Bakken property had
lower initial production rates than originally forecast; however the program
continues to deliver attractive economics and reserves. These decreases were
partially offset by production from our acquisition of Jonah that closed
January 31, 2007.
Average production during the year was weighted 53% to natural gas and
47% to liquids on a BOE basis. Average production volumes for the years ended
December 31, 2007 and 2006 are outlined below:
Daily Production Volumes 2007 2006 % change
-------------------------------------------------------------------------
Natural gas (Mcf/day) 262,254 270,972 (3)%
Crude oil (bbls/day) 34,506 36,134 (5)%
Natural gas liquids (bbls/day) 4,104 4,483 (8)%
Total daily sales (BOE/day) 82,319 85,779 (4)%
-------------------------------------------------------------------------
We exited the year with production of approximately 79,800 BOE/day based
on December's average production rate, 4% below our exit target of 83,000
BOE/day. Approximately 2,000 BOE/day of the decrease related to a previously
announced fire that occurred at our Giltedge property on November 30, 2007. We
expect production from this property to be back on-line by mid-2008. We have
both business interruption insurance and property insurance which we
anticipate will mitigate the majority of these losses. The remainder of the
1,200 BOE/day difference related to tie-in delays primarily on non-operated
capital projects at year end and pipeline problems at our non-operated Mitsue
property.
Considering our acquisition of Focus that closed on February 13, 2008 and
our current development capital program, we expect 2008 annual production
volumes to average 98,000 BOE/day, weighted 60% to natural gas and 40% to
liquids. We expect to exit 2008 with production of approximately
100,000 BOE/day. This guidance does not contemplate any other 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 2007 with those of 2006. It also
compares the benchmark price indices for the same periods.
Average Selling Price(1) 2007 2006 % Change
-------------------------------------------------------------------------
Natural gas (per Mcf) $ 6.45 $ 6.81 (5)%
Crude oil (per bbl) $ 65.11 $ 61.80 5%
Natural gas liquids (per bbl) $ 51.35 $ 50.90 1%
Per BOE $ 50.48 $ 50.23 -%
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Average Benchmark Pricing 2007 2006 % Change
-------------------------------------------------------------------------
AECO natural gas - monthly index
(CDN$/Mcf) $ 6.61 $ 6.99 (5)%
AECO natural gas - daily index
(CDN$/Mcf) $ 6.45 $ 6.53 (1)%
NYMEX natural gas - monthly NX3 index
(US$/Mcf) $ 6.92 $ 7.26 (5)%
NYMEX natural gas - monthly NX3 index:
CDN$ equivalent (CDN$/Mcf) $ 7.44 $ 8.25 (10)%
WTI crude oil (US$/bbl) $ 72.34 $ 66.22 9%
WTI crude oil: CDN$ equivalent
(CDN$/bbl) $ 77.78 $ 75.25 3%
CDN$/US$ exchange rate 0.93 0.88 6%
-------------------------------------------------------------------------
Natural Gas
Natural gas prices started 2007 in a weak position due to a mild December
2006. However cold weather across key consuming regions of the United States
from the latter part of January 2007 through to March resulted in increased
prices. Early forecasts for an active hurricane season led to an expectation
that strong prices would carry into and through the summer. However, this past
year marked a changing dynamic in global liquefied natural gas ("LNG") trade,
with cargos more readily shifting between Asia, Europe, and North America
depending on spot market prices and access to storage. Accordingly, low demand
in Europe pushed significant volumes of LNG to North America from March
through August. This LNG, along with continued strong North American
production, resulted in high U.S. and Canadian storage balances by the end of
the summer which depressed prices. Natural gas prices during the year traded
within a band that saw highs of approximately $8.00/Mcf during the winter and
lows of around $5.00/Mcf at the end of the summer injection season. This was a
narrower band than was experienced during 2006 where natural gas prices
fluctuated between $12.00/Mcf and $4.00/Mcf.
Our natural gas portfolio in 2007 was comprised of aggregator, AECO, and
downstream direct sales. In 2007 we sold 40% of our natural gas on the daily
AECO market and 40% on the monthly AECO market, as well as 20% against the day
and month NYMEX indices. During 2007 we realized an average price for our
natural gas sales of $6.45/Mcf (net of transportation costs), a decrease of 5%
from $6.81/Mcf realized in 2006. This reduction is comparable to the price
decreases realized in each of: the AECO monthly index which decreased by 5%;
the AECO daily index which decreased by 1%; and the NYMEX monthly index
(converted to CDN$/Mcf) which decreased by 10%.
Crude Oil
Crude prices were weak in the first quarter of 2007, with a low of
US$50.48/bbl. Prices rose steadily through the remaining months reaching a
high of US$98.18/bbl in mid November. In terms of market fundamentals, OPEC
kept its supply constant, non-OPEC production was lower than expected and
growth demands in Asia remained strong. As a result, global crude and refined
product inventories declined. In addition there was growing concern global
production was reaching its peak. These fundamentals placed steady upward
pressure on crude oil prices through the year.
Our crude oil portfolio in 2007 was approximately 74% light/medium and
26% heavy. The average price received for our crude oil (net of transportation
costs) was CDN$65.11/bbl during 2007, a 5% increase over 2006. The West Texas
Intermediate ("WTI") crude oil benchmark price, after adjusting for the change
in the US$ exchange rate, increased 3% year-over-year. On average for 2007,
the slight narrowing of the light to heavy differential had a positive effect
on our overall crude oil and gas sales. However, in the fourth quarter of
2007, and in particular in December, absolute heavy oil differentials to WTI
widened significantly due to a number of factors, including: outages of
refineries with heavy oil conversion capabilities; drawdown of inventories
prior to year end; and operational issues on key intra-Alberta and export
pipelines. These differentials reverted to historical levels in January 2008.
The Canadian dollar opened 2007 at an exchange rate of $0.86/US$ and
strengthened throughout the year hitting a high in November of $1.09/US$ and
ending the year at $0.99/US$. On average it strengthened 6% against the U.S.
dollar during 2007 compared to 2006 based on the annual average exchange rate.
As most of our crude oil and a portion of our natural gas are priced in
reference to U.S. dollar denominated benchmarks, this movement in the exchange
rate reduced the Canadian dollar prices that we would have otherwise realized.
Historically we have not attempted to hedge against fluctuations in the
foreign exchange value of our oil and gas sales. In the fourth quarter of 2007
we entered into a foreign exchange swap on our US$54 million debentures which
effectively fixed the principal repayments at a CAN/US dollar exchange rate of
1.02.
Price Risk Management
While we believe that the overall energy outlook remains generally
bullish long term, the threat of a U.S. recession reducing demand for crude
oil and natural gas requires prudent management of our commodity price
exposure.
We have developed a price risk management framework to respond to the
volatile price environment in a measured manner. Consideration is given to our
overall financial position together with the economics of our acquisitions and
capital development program. Consideration is also given to the upfront costs
of our risk management program as we seek to limit our exposure to price
downturns and maintain participation in upside potential should commodity
prices increase.
Consistent with our price risk management framework, we entered into
additional commodity contracts during the fourth quarter of 2007 and during
the first quarter of 2008. These contracts are designed to protect a portion
of our natural gas sales for the period January 2008 through March 2009 and to
protect a portion of our crude oil sales for the period January 2008 through
December 2009. We have also hedged electricity volumes for the period January
2008 through December 2009 to protect against rising electricity costs in the
Alberta power market. See Note 12 for a detailed list of our current price
risk management positions including positions we assumed through the Focus
acquisition.
The following is a summary of the financial contracts in place at
February 20, 2008, including positions entered into by Focus, expressed as a
percentage of our forecasted net production volumes:
Natural Gas
(CDN$/Mcf)
-------------------------------------
January 1, April 1, November 1,
2008 - 2008 - 2008 -
March 31, October 31, March 31,
2008 2008 2009
-------------------------------------------------------------------------
Floor Prices (puts) $ 8.28 $ 7.06 $ 8.18
% (net of royalties) 18% 24% 4%
Fixed Price (swaps) $ 8.73 $ 7.16 $ -
% (net of royalties) 11% 16% - %
Capped Price (calls) $10.12 $ 8.22 $10.10
% (net of royalties) 19% 24% 4%
-------------------------------------------------------------------------
Crude Oil
(US$/bbl)
-------------------------------------
January 1, July 1, January 1,
2008 - 2008 - 2009 -
June 30, December 31, December 31,
2008 2008 2009
-------------------------------------------------------------------------
Floor Prices (puts) $70.91 $72.09 $77.63
% (net of royalties) 35% 35% 10%
Fixed Price (swaps) $79.95 $79.97 $ -
% (net of royalties) 17% 19% - %
Capped Price (calls) $85.09 $85.48 $92.98
% (net of royalties) 23% 22% 10%
-------------------------------------------------------------------------
Based on weighted average price (before premiums), estimated average
annual production of 98,000 BOE/day and assuming a 19% royalty rate.
Accounting for Price Risk Management
During 2007, our commodity price risk management program generated cash
gains of $23.6 million on our natural gas contracts and cash losses of
$10.0 million on our crude oil contracts. The natural gas cash gains are due
to contracts in place during 2007 that provided floor protection as the price
of natural gas declined. The crude oil cash losses are due to crude oil prices
rising above our swap positions. In comparison, our 2006 commodity price risk
management program resulted in cash losses of $7.1 million on our natural gas
contracts and $27.2 million on our crude oil contracts.
At December 31, 2007 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represents a gain of $9.7 million and
a loss of $52.5 million, respectively. The natural gas gain is recorded as a
current deferred financial asset on our balance sheet and the crude oil loss
is recorded as a current deferred financial credit. In comparison, at
December 31, 2006 the fair value of our natural gas and crude oil derivative
instruments represented gains of $12.7 million and $10.9 million respectively,
both of which were recorded on our balance sheet as deferred financial assets.
The change in the fair value of these financial contracts year-over-year
resulted in unrealized losses of $3.0 million for natural gas and
$63.4 million for crude oil. As the forward markets for natural gas and crude
oil fluctuate and new contracts are executed and existing contracts are
realized, changes in fair value are reflected as a non-cash charge or non-cash
gain in earnings. See Note 3 for details.
The following table summarizes the effects of our financial contracts on
income for the years ended December 31, 2007 and 2006.
Risk Management Costs
($ millions, except
per unit amounts) 2007 2006
-------------------------------------------------------------------------
Cash gains/(losses):
Natural gas $ 23.6 $ 0.25/Mcf $ (7.1) $(0.07)/Mcf
Crude oil (10.0) $(0.79)/bbl (27.2) $(2.06)/bbl
------------ ------------
Total cash
gains/(losses) $ 13.6 $ 0.45/BOE $ (34.3) $(1.10)/BOE
Non-cash
(losses)/gains on
financial contracts:
Change in fair value
- natural gas $ (3.0) $(0.03)/Mcf $ 50.6 $ 0.51/Mcf
Change in fair value
- crude oil (63.4) $(5.03)/bbl 30.4 $ 2.30/bbl
Amortization of
deferred financial
assets - $ - /BOE (49.9) $(1.59)/BOE
------------ ------------
Total non-cash
(losses)/gains $ (66.4) $(2.21)/BOE $ 31.1 $ 0.99/BOE
------------ ------------
Total (losses) $ (52.8) $(1.76)/BOE $ (3.2) $(0.11)/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Flow Sensitivity
The sensitivities below reflect all commodity contracts as described in
Note 12 (including those entered into by Focus) and are based on 2008 forward
markets as at February 20, 2008. 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.
Estimated Effect on 2008
Sensitivity Table Cash Flow per Trust Unit(1)
-------------------------------------------------------------------------
Change of $0.15 per Mcf in the price of
AECO natural gas $0.08
Change of US$1.00 per barrel in the price
of WTI crude oil $0.06
Change of 1,000 BOE/day in production $0.10
Change of $0.01 in the US$/CDN$ exchange rate $0.12
Change of 1% in interest rate $0.07
-------------------------------------------------------------------------
(1) Assumes constant working capital and 129,813,000 units outstanding.
The impact of a change in one factor may be compounded or offset by
changes in other factors. This table does not consider the impact of
any inter-relationship among the factors.
Revenues
Crude oil and natural gas revenues for the year ended December 31, 2007
were $1,517.1 million ($1,539.2 million, net of $22.1 million of
transportation costs), a decrease of 4% or $55.6 million compared to
$1,572.7 million ($1,595.3 million, net of $22.6 million of transportation
costs) during 2006. Decreased production and lower natural gas prices were
partially offset by an increase in realized crude oil prices.
Analysis of Sales Revenue(1) Natural
($ millions) Crude oil NGLs Gas Total
-------------------------------------------------------------------------
2006 Sales Revenue $815.0 $83.3 $674.4 $1,572.7
Price variance(1) 41.8 0.7 (33.8) 8.7
Volume variance (36.7) (7.1) (20.5) (64.3)
-------------------------------------------------------------------------
2007 Sales Revenue $820.1 $76.9 $620.1 $1,517.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Royalties
Royalties are paid to various government entities and other land and
mineral rights owners. Royalties in 2007 and 2006 were approximately 19% of
oil and gas sales, net of transportation costs. Overall, royalties decreased
marginally in 2007 to $285.1 million compared to $296.6 million during 2006
primarily as a result of the decrease in natural gas revenue experienced over
the period.
We expect royalties to be approximately 19% of oil and gas sales, net of
transportation costs for 2008.
Alberta Royalty Review
On October 25, 2007 the Alberta government announced the 'New Royalty
Framework' ("NRF"), an updated royalty regime proposed to be effective
January 1, 2009 which is intended to increase Government royalty revenue by
20%. On conventional oil and gas production during 2007, Alberta Crown
royalties were $122.1 million (43%) of our total royalties. Based on this
royalty rate and in the context of our production and pricing experienced
during 2007, we estimate that the NRF would have increased the royalties on
our conventional production by approximately $15 to $20 million. The
acquisition of Focus in 2008 will help to mitigate the effects of the Alberta
royalty review as the production from Focus is concentrated in Saskatchewan
and British Columbia.
The moderate royalty increase is a reflection of the NRF's sensitivity to
our portfolio, which includes lower productivity wells combined with the low
natural gas prices experienced in 2007. It is important to note that this
context may not be indicative of the environment in 2009 when the NRF comes
into effect. The fundamental design of the new Alberta 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. As a result, Alberta will not be as attractive to invest
in as other jurisdictions that allow greater participation in price upside.
The Alberta government is currently working with industry to address
"unintended consequences" of economic issues related to the NRF and as at the
date of this MD&A the Alberta government had not yet made the necessary
legislative and administration changes to implement the NRF. The NRF
announcement can be found on the Alberta government's website at
www.gov.ab.ca.
Operating Expenses
Operating expenses during 2007 were $9.12/BOE or $274.2 million,
representing a 1% decrease from our third quarter guidance of $9.20/BOE and a
14% increase from $8.02/BOE in 2006. Operating expenses for the year were
lower than our guidance primarily due to lower than expected electricity
charges during the fourth quarter. The increase in operating costs over 2006
was due to the combination of increased labour, well servicing, and repairs
and maintenance costs along with lower production volumes during 2007. A field
training initiative in 2007 directed at optimizing production and reducing the
time required to drill, complete and bring new wells on stream also
contributed to the year-over-year increase.
By combining the lower cost operating expenses associated with the Focus
properties we expect operating costs for 2008 to average $8.65/BOE,
representing a decrease of 5% per BOE compared to 2007.
General and Administrative Expenses ("G&A")
G&A expenses were $2.26/BOE or $67.9 million for the year ended
December 31, 2007, approximately 6% lower than our guidance of $2.40/BOE and
18% higher than $1.91/BOE in 2006. G&A expenses were lower than our guidance
primarily due to lower than anticipated long term cash compensation charges
related to our performance trust unit plan ("PTU") which is impacted by our
trust unit price. The increase in general and administrative costs over 2006
was mainly due to increased overall salary and benefits as a result of
continued wage inflation, increased staff and lower production volumes during
2007.
For the year ended December 31, 2007 our G&A expenses included non-cash
charges for our trust unit rights incentive plan of $8.4 million or $0.28/BOE
compared to $6.3 million or $0.20/BOE for 2006. These amounts relate solely to
our trust unit rights incentive plan and are determined using a binomial
lattice option-pricing model. The volatility of our trust unit price combined
with the increased number of rights outstanding associated with additional
employees increased the non-cash cost of the plan. Although non-cash charges
have increased as a result of the option pricing model, the proportion of
rights that are "in-the-money" has decreased in comparison with 2006. See
Note 10 for further details.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and Administrative Costs ($ millions) 2007 2006
-------------------------------------------------------------------------
Cash $59.5 $53.6
Trust unit rights incentive plan (non-cash) 8.4 6.3
-------------------------------------------------------------------------
Total G&A $67.9 $59.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2007 2006
-------------------------------------------------------------------------
Cash $1.98 $1.71
Trust unit rights incentive plan (non-cash) 0.28 0.20
-------------------------------------------------------------------------
Total G&A $2.26 $1.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In 2008 we expect total G&A costs to decrease slightly to approximately
$2.20/BOE, including non-cash G&A costs of approximately $0.20/BOE.
Interest Expense
With the adoption of the new accounting standards on January 1, 2007
interest expense includes interest on long-term debt, the premium amortization
on our US$175 million senior unsecured notes, unrealized gains and losses
resulting from the change in fair value of our interest rate swaps as well as
the interest component on our cross currency interest rate swap (see Note 8).
Interest on long-term debt during 2007 totaled $41.9 million, a
$9.7 million increase from $32.2 million in 2006. The increase was due to
higher average indebtedness and a higher weighted average interest rate of
5.1% during 2007 compared to 4.8% in 2006.
The following table summarizes the cash and non-cash interest expense
recorded.
Interest Expense ($ millions) 2007 2006
-------------------------------------------------------------------------
Interest on long-term debt $41.9 $32.2
Unrealized gain (8.3) -
-------------------------------------------------------------------------
Total Interest Expense $33.6 $32.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At December 31, 2007 approximately 18% of our debt was based on fixed
interest rates while 82% had floating interest rates.
Capital Expenditures
During 2007 we spent $387.2 million on development capital and
facilities, which is $104.0 million or 21% less than 2006. Spending in 2007
was in-line with our guidance of $390.0 million. Development capital spending
was lower in 2007 as we spent less on natural gas development due to
decreasing natural gas prices and increasing drilling and servicing costs.
Development in 2007 focused primarily on Bakken oil and waterfloods. We
achieved a 99% success rate with our drilling program on 252 net wells drilled
during 2007.
Property acquisitions were $274.2 million during 2007 compared to
$51.3 million in 2006. The majority of our 2007 acquisitions related to the
purchase of 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. Property dispositions were $9.6 million during 2007 compared to
$21.1 million in 2006. Our 2007 divestments included $5.6 million of property
interests in the Thorhild area and the sale of 36,000 net acres of undeveloped
land in North Dakota for approximately $3.6 million. Divestments in 2006
primarily related to the $19.7 million sale of a 1% working interest in the
Joslyn property.
Capital Expenditures ($ millions) 2007 2006
-------------------------------------------------------------------------
Development expenditures $ 321.3 $ 380.5
Plant and facilities 65.9 110.7
-------------------------------------------------------------------------
Development Capital 387.2 491.2
Office 6.5 5.0
-------------------------------------------------------------------------
Sub-total 393.7 496.2
Acquisitions of oil and gas properties(1) 274.2 51.3
Dispositions of oil and gas properties(1) (9.6) (21.1)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 658.3 $ 526.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Capital Expenditures financed with cash flow $ 221.7 $ 249.4
Total Capital Expenditures financed
with debt and equity 443.2 296.5
Total non-cash consideration
for property dispositions (6.6) (19.5)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 658.3 $ 526.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
The following is a summary by play type of our development capital
expenditures during 2007 and 2006, as well as our current expectations for
2008 including Focus.
Play type ($ millions) 2008 Estimate 2007 2006
-------------------------------------------------------------------------
Shallow Gas and CBM $128.0 $39.3 $94.0
Crude Oil Waterfloods 105.0 54.2 66.0
Deep Tight Gas 53.0 34.7 34.1
Bakken Oil 47.0 106.2 116.7
Other Conventional Oil and Gas 142.0 113.9 141.3
Oil Sands 105.0 38.9 39.1
-------------------------------------------------------------------------
Total $580.0 $387.2 $491.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We currently expect total development capital expenditures in 2008 to be
approximately $580 million. Conventional development capital is presently
anticipated to be approximately $475 million with a slight bias to oil related
projects over natural gas projects. Oil sands development capital is currently
projected to be approximately $105 million.
Oil Sands
Our Joslyn and Kirby development projects have not commenced commercial
production. As a result all associated costs, net of revenues generated, are
capitalized and excluded from our depletion calculation. During 2007 we
capitalized costs of $35.2 million on Joslyn and $205.4 million on Kirby,
inclusive of acquisition costs, development capital spending, salaries and
benefits, engineering and planning. At December 31, 2007 capitalized costs
life-to-date for Joslyn were $116.4 million and for Kirby were $205.4 million
for a combined total of $321.8 million.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
DDA&A of property, plant and equipment ("PP&E") is recognized using the
unit-of-production method based on proved reserves. For the year ended
December 31, 2007 DDA&A of $15.43/BOE is comparable to $15.38/BOE during the
year ended December 31, 2006.
No impairment existed at December 31, 2007 using year-end reserves and
management's estimates of future prices. Our future price estimates are more
fully discussed in Note 4.
Asset Retirement Obligations
We have estimated our total 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 future periods.
Our asset retirement obligation was $165.7 million at December 31, 2007
compared to $123.6 million at December 31, 2006. The majority of the
$42.1 million increase was due to increased cost estimates as a result of
enhanced regulatory requirements on abandonment and reclamation activities.
The remainder of the change was due to retirement costs incurred, offset by
accretion expense for the year. See Note 5 for further details.
The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation, and asset retirement
obligations settled.
($ millions) 2007 2006
-------------------------------------------------------------------------
Amortization of the asset retirement cost $11.4 $12.6
Accretion of the asset retirement obligation 6.7 6.2
-------------------------------------------------------------------------
Total Amortization and Accretion $18.1 $18.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement Obligations Settled $16.3 $11.5
-------------------------------------------------------------------------
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 2038
and 2047. For accounting purposes, the asset retirement cost is amortized
using a unit-of-production method based on proved reserves before royalties
while the asset retirement obligation accretes until the time the obligation
is settled.
Taxes
Canadian Government's tax changes
On June 22, 2007 Bill C-52, which contained legislative provisions to
implement the proposals to tax publicly traded income trusts in Canada became
law. As a result, our second quarter future income tax provision included a
future income tax expense of $78.1 million related to this legislation. This
non-cash expense related to temporary differences between the accounting and
tax basis of the Fund's assets and liabilities at that time and had no
immediate impact on cash flow.
On December 14, 2007, Bill C-28, which contained legislative provisions
to implement corporate income tax rate reductions announced in the October 30,
2007 fall economic statement, became law. The general corporate tax rate will
decrease by 1.0% in 2008 from 20.5% to 19.5%. There are additional rate
reductions scheduled until the target federal tax rate of 15.0% is reached as
of January 1, 2012. These rate reductions will also apply to the SIFT tax from
income trusts. As a result, our fourth quarter future income tax provision
includes a future income tax recovery of $22.6 million related to this
legislation.
Future Income Taxes
Future income taxes arise from differences between the accounting and tax
basis of assets and liabilities. A portion of the future income tax liability
that is recorded on the balance sheet will be recovered through earnings
before 2011. The balance will be realized when future income tax assets and
liabilities are realized or settled.
As a result of the SIFT tax, all entities within our organization are now
subject to future income taxes whereas prior to the SIFT tax enactment only
incorporated entities in our organization were subject to future income taxes.
As a result our future income tax recovery was $1.0 million for the year ended
December 31, 2007 compared to a recovery of $112.0 million for the same period
in 2006. The changes in future income taxes compared to 2006 are primarily a
result of the following:
- The SIFT tax resulted in a future income tax expense of $78.1 million
in the second quarter of 2007; and
- Corporate income tax rate changes enacted during the year have
resulted in a year-to-date future tax recovery of $22.6 million
compared to a $35.5 million recovery in 2006.
After consideration of the above items, the future income tax provisions
were comparable between the 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, no cash income taxes have been
paid by our Canadian operating entities. However, effective January 1, 2011 we
will be subject to the SIFT tax should we remain a trust.
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 the funds to Canada. Our U.S. taxes as a percentage of cash
flow, assuming constant working capital, were 11% in 2007 compared to our
guidance of 10%. We expect the current income and withholding taxes to average
approximately 20% of cash flow from U.S. operations in 2008 based on our
current development capital program and assuming all funds are repatriated to
Canada after U.S. development capital spending. The increase for 2008 is a
result of plans for reduced development capital spending in the U.S. during
the year.
During 2007 our U.S. operations incurred income related taxes in the
amount of $23.0 million compared to $18.2 million in 2006. The increase in
current taxes is due to an increase in net income combined with a modest
decrease in drilling and completion expenditures for the year.
Tax Pools
We estimate our tax pools at December 31, 2007 to be as follows:
Operating
Pool Type ($ millions) Trust entities Total
-------------------------------------------------------------------------
COGPE $470 $ 100 $ 570
CDE - 340 340
UCC - 600 600
Tax losses and other 30 600 630
Foreign tax pools - 140 140
-------------------------------------------------------------------------
Total $500 $1,780 $2,280
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We acquired approximately $200 million in tax pools related to the Focus
acquisition (net of any pools required to offset partnership deferrals).
Net Income
Net income in 2007 was $339.7 million or $2.66 per trust unit compared to
$544.8 million or $4.48 per trust unit in 2006. The $205.1 million decrease in
net income was primarily due to a $111.0 million decrease in future income tax
recovery, a $49.6 million increase in cash and non-cash risk management costs,
a $55.6 million decrease in oil and gas sales (net of transportation costs)
and a $22.9 million increase in operating costs, partially offset by an
increase in other income of $12.5 million and decreased DDA&A charges of
$17.9 million.
Cash Flow from Operating Activities
Cash flow from operating activities in 2007 was $868.5 million or $6.80
per trust unit compared to $863.7 million or $7.10 per trust unit in 2006. The
decrease on a per unit basis is largely due to the April 2007 equity offering,
which was primarily used to purchase Kirby, a development project that is not
currently generating cash flow.
Selected Financial Results
Year ended December 31, Year ended December 31,
2007 2006
Operating Non-Cash Operating Non-Cash
Per BOE of Cash & Other Cash & Other
production (6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production per day 82,319 85,779
-------------------------------------------------------------------------
Weighted average
sales price(2) $50.48 $ - $50.48 $50.23 $ - $50.23
Royalties (9.49) - (9.49) (9.47) - (9.47)
Commodity
derivative
instruments 0.45 (2.21) (1.76) (1.10) 0.99 (0.11)
Operating costs (9.11) (0.01) (9.12) (8.02) - (8.02)
General and
administrative (1.98) (0.28) (2.26) (1.71) (0.20) (1.91)
Interest expense,
net of interest
income (1.37) 0.28 (1.09) (0.95) - (0.95)
Foreign exchange
gain/(loss) (0.06) 0.30 0.24 0.02 - 0.02
Current income tax (0.77) - (0.77) (0.59) - (0.59)
Restoration and
abandonment
cash costs (0.54) 0.54 - (0.37) 0.37 -
Depletion,
depreciation,
amortization and
accretion - (15.43) (15.43) - (15.38) (15.38)
Future income tax
(expense)/recovery - 0.04 0.04 - 3.58 3.58
Marketable
securities(3) - 0.47 0.47 - - -
-------------------------------------------------------------------------
Total per BOE $27.61 $(16.30) $11.31 $28.04 $(10.64) $17.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash Flow from Operating Activities before changes in non-cash
operating working capital.
(2) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(3) In addition to non-cash shares of marketable securities, a gain on
sale of marketable securities was a cash item; however the cash item
is included in cash flow from investing activities not cash flow from
operating activities.
Selected Annual Canadian and U.S. Financial Results
The following table provides a geographical analysis of key operating and
financial results for 2007 and 2006.
(CDN$ millions, except Year ended December 31, 2007
per unit amounts) Canada U.S. Total
-------------------------------------------------------------------------
Daily Production Volumes
Natural gas (Mcf/day) 251,561 10,693 262,254
Crude oil (bbls/day) 24,590 9,916 34,506
Natural gas liquids (bbls/day) 4,104 - 4,104
Total daily sales (BOE/day) 70,621 11,698 82,319
Pricing(1)
Natural gas (per Mcf) $ 6.45 $ 6.55 $ 6.45
Crude oil (per bbl) $ 62.27 $ 72.17 $ 65.11
Natural gas liquids (per bbl) $ 51.35 $ - $ 51.35
Capital Expenditures
Development capital and office $ 287.3 $ 106.4 $ 393.7
Acquisitions of oil
and gas properties $ 213.3 $ 60.9 $ 274.2
Dispositions of oil
and gas properties $ (6.0) $ (3.6) $ (9.6)
Revenues
Oil and gas sales(1) $ 1,230.4 $ 286.7 $ 1,517.1
Royalties $ (226.4) $ (58.7)(2) $ (285.1)
Commodity derivative instruments $ (52.8) $ - $ (52.8)
Expenses
Operating $ 264.4 $ 9.8 $ 274.2
General and administrative $ 62.6 $ 5.3 $ 67.9
Depletion, depreciation,
amortization and accretion $ 359.8 $ 103.9 $ 463.7
Current income taxes $ - $ 23.0 $ 23.0
-------------------------------------------------------------------------
(CDN$ millions, except Year ended December 31, 2006
per unit amounts) Canada U.S. Total
-------------------------------------------------------------------------
Daily Production Volumes
Natural gas (Mcf/day) 265,019 5,953 270,972
Crude oil (bbls/day) 25,858 10,276 36,134
Natural gas liquids (bbls/day) 4,483 - 4,483
Total daily sales (BOE/day) 74,511 11,268 85,779
Pricing(1)
Natural gas (per Mcf) $ 6.79 $ 7.78 $ 6.81
Crude oil (per bbl) $ 59.36 $ 67.93 $ 61.80
Natural gas liquids (per bbl) $ 50.90 $ - $ 50.90
Capital Expenditures
Development capital and office $ 378.5 $ 117.7 $ 496.2
Acquisitions of oil
and gas properties $ 35.3 $ 16.0 $ 51.3
Dispositions of oil
and gas properties $ (21.1) $ - $ (21.1)
Revenues
Oil and gas sales(1) $ 1,301.0 $ 271.7 $ 1,572.7
Royalties $ (244.4) $ (52.2)(2) $ (296.6)
Commodity derivative instruments $ (3.2) $ - $ (3.2)
Expenses
Operating $ 243.8 $ 7.4 $ 251.2
General and administrative $ 51.4 $ 8.5 $ 59.9
Depletion, depreciation,
amortization and accretion $ 369.6 $ 112.0 $ 481.6
Current income taxes $ - $ 18.2 $ 18.2
-------------------------------------------------------------------------
(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, lower production volumes have resulted in lower oil and gas sales
and net income during 2007 as compared to 2006. The rise in crude oil prices
during 2005, 2006 and 2007 contributed to higher oil and gas sales, however
sales moderated in 2007 as a result of lower natural gas prices and
production. The following table provides a summary of net income, cash flow
and other key measures.
($ millions, except per unit amounts) 2007 2006 2005
-------------------------------------------------------------------------
Oil and gas sales(1) $1,517.1 $1,572.7 $1,523.7
Net income 339.7 544.8 432.0
Per unit (Basic)(2) 2.66 4.48 3.96
Per unit (Diluted) 2.66 4.47 3.95
Cash flow from operating activities 868.5 863.7 774.6
Per unit (Basic)(2) 6.80 7.10 7.10
Cash distributions 646.8 614.3 498.2
Per unit (Basic)(2) 5.07 5.05 4.57
Payout ratio 74% 71% 64%
Total assets 4,303.1 4,203.8 4,130.6
Long-term debt, net of cash 725.0 679.7 649.8
-------------------------------------------------------------------------
(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
Sustainability of our Distributions and Asset Base
As an oil and gas producer we have a declining asset base and therefore
rely on ongoing development activities and acquisitions to replace production
and add additional reserves. Our future oil and natural gas production is
highly dependent on our success in exploiting our asset base and acquiring or
developing additional reserves. To the extent we are unsuccessful in these
activities our cash distributions could be reduced.
Development activities and acquisitions may be funded internally by
withholding a portion of cash flow or through external sources of capital such
as debt or the issuance of equity. To the extent that we withhold cash flow to
finance these activities, the amount of cash distributions to our unitholders
may be reduced. Should external sources of capital become limited or
unavailable, our ability to make the necessary development expenditures and
acquisitions to maintain or expand our asset base may be impaired and
ultimately reduce the amount of cash distributions.
Following the completion of the Focus acquisition, Enerplus has
approximately $10 billion of safe harbor growth capacity within the context of
the Government's "normal growth" guidelines associated with Bill C-52. This
amount is calculated in reference to the combined market capitalizations of
Enerplus and Focus on October 31, 2006 and also includes equity that may be
issued to replace existing debt of both entities at that time.
Distribution Policy
The amount of cash distributions is proposed by management and approved
by the Board of Directors. We continually assess distribution levels with
respect to forecasted cash flows, debt levels and capital spending plans. The
level of cash withheld has historically varied between 10% and 40% of annual
cash flow from operating activities and is dependent upon numerous factors,
the most significant of which are the prevailing commodity price environment,
our current levels of production, debt obligations, our access to equity
markets and funding requirements for our development capital program.
Although we intend to continue to make cash distributions to our
unitholders, these distributions are not guaranteed. To the extent there is
taxable income at the trust level, determined in accordance with the Canadian
Income Tax Act, the distribution of that taxable income is non-discretionary.
Cash Flow from Operating Activities, Cash Distributions and Payout Ratio
Cash flow from operating activities and cash distributions are reported
on the Consolidated Statements of Cash Flows. During 2007 cash distributions
of $646.8 million were funded entirely through cash flow of $868.5 million.
Our payout ratio, which is calculated as cash distributions divided by cash
flow, was 74% for 2007 compared to 71% in 2006.
Our cash outlays in 2007 were comprised of: $646.8 million of
distributions to unitholders, $393.7 million of development capital and office
expenditures and $209.8 million of acquisitions (net of dispositions) for a
total of $1,250.3 million. These cash outlays were financed with a combination
of: $868.5 million from cash flow from operating activities, $199.6 million
from the equity issue, $56.8 million from our distribution reinvestment plan
and trust unit rights incentive plan and an increase in our credit facility of
$148.8 million.
In aggregate, our 2007 cash distributions of $646.8 million and our
development capital and office of $393.7 million totaled $1,040.5 million, or
approximately 120% of our cash flow of $868.5 million. We rely on access to
capital markets to the extent cash distributions and development capital
exceeds cash flow. Over the long term we would expect to support our
distributions and capital expenditures with our cash flow, however we would
continue to fund acquisitions and growth through additional debt and equity.
There will be years when we are investing capital in opportunities that do not
immediately generate cash flow (such as our Joslyn and Kirby oil sands
projects) where this relationship will vary. Despite our 2007 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 0.8x at December 31, 2007.
For the year ended December 31, 2007 our cash distributions exceeded our
net income by $307.1 million (2006 - $69.5 million). Net income includes
$520.3 million of non-cash items (2006 - $344.7 million) such as DDA&A,
changes in the fair value of our derivative instruments and future income
taxes that do not reduce our cash flow from operations. Future income taxes
can fluctuate from period to period as a result of changes in tax rates (such
as the enactment of the SIFT tax during the second quarter of 2007), changes
in the inter-company royalty, interest and dividends from our operating
subsidiaries paid to the Fund. In addition, other non-cash charges such as
DDA&A are not a good proxy for the cost of maintaining our productive capacity
as they are based on the historical costs of our PP&E and not the fair market
value of replacing those assets within the context of the current environment.
The level of investment in a given period may not be sufficient to
replace productive capacity given the natural declines associated with oil and
natural gas assets. In these instances a portion of the cash distributions
paid to unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income.
($ millions, except per unit amounts) 2007 2006 2005
-------------------------------------------------------------------------
Cash flow from operating activities $ 868.5 $ 863.7 $ 774.6
Cash Distributions 646.8 614.3 498.2
-------------------------------------------------------------------------
Excess of cash flow over
cash distributions $ 221.7 $ 249.4 $ 276.4
Net income $ 339.7 $ 544.8 $ 432.0
Shortfall of net income over
cash distributions $ (307.1) $ (69.5) $ (66.2)
Cash distributions per
weighted average trust unit $ 5.07 $ 5.05 $ 4.57
Payout ratio(1) 74% 71% 64%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow from operating
activities.
It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. Therefore we do not disclose
maintenance capital separately from development capital spending.
Asset Retirement Costs
Actual asset retirement costs incurred in the period are deducted for
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 the
MD&A and Note 5.
Long-Term Debt
Long-term debt at December 31, 2007 was $726.7 million, an increase of
$46.9 million from $679.8 million at December 31, 2006. Long-term debt at
December 31, 2007 is comprised of $497.3 million of bank indebtedness, which
increased $148.8 million from prior year and $229.3 million of senior
unsecured notes. With the adoption of the financial instrument accounting
standards (see Note 2) on January 1, 2007 we adjusted the carrying value of
our US$175 million senior unsecured notes to fair value of $208.2 million from
their previous carrying value of $268.3 million, a decrease of $60.1 million.
Subsequent to this adoption entry, our $175 million senior notes have
decreased a further $32.2 million as a result of the strengthening Canadian
dollar. Increases in long-term debt resulting from the Jonah and Kirby
acquisitions along with our development capital program more than offset
decreases resulting from the April 2007 equity issue and the foreign exchange
impact of the strengthening Canadian dollar on our U.S. dollar denominated
senior notes.
In the fourth quarter of 2007 we extended our bank credit facility by one
year to November 2010 and increased the facility size to $1.0 billion.
Subsequent to December 31, 2007, in conjunction with the Focus acquisition, we
increased the bank credit facility size to $1.4 billion. On February 13, 2008
an additional $340 million was drawn on the bank credit facility to settle
outstanding indebtedness of Focus.
Our working capital, excluding cash, at December 31, 2007 decreased
$73.2 million compared to December 31, 2006. Excluding deferred financial
assets and credits, working capital decreased $7.3 million compared to the
prior year. This is primarily due to lower accounts receivable in 2007 as a
result of lower sales in December 2007 compared to 2006.
We continue to maintain a conservative balance sheet as demonstrated
below:
Year ended Year ended
Financial Leverage and Coverage Dec. 31, 2007 Dec. 31, 2006
-------------------------------------------------------------------------
Long-term debt to trailing cash flow 0.8 x 0.8 x
Cash flow to interest expense 25.8 x 26.8 x
Long-term debt to long-term debt plus equity 22% 20%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
Cash flow and interest expense are 12-months trailing.
Enerplus currently has a $1.4 billion ($1.0 billion at December 31, 2007)
unsecured covenant based three-year term bank facility ending November 2010,
through its wholly-owned subsidiary EnerMark Inc. We have the ability to
extend the facility each year or repay the entire balance at the end of the
three-year term. This bank debt carries floating interest rates that we
expect to range between 55.0 and 110.0 basis points over Bankers' Acceptance
rates, depending on Enerplus' ratio of senior debt to earnings before
interest, taxes and non-cash items.
Payments with respect to the bank facilities, senior unsecured notes and
other third party debt have priority over claims of and future distributions
to the unitholders. Unitholders have no direct liability should cash flow be
insufficient to repay this indebtedness. The agreements governing these bank
facilities and senior unsecured notes stipulate that if we default or fail to
comply with certain covenants, the ability of the Fund's operating
subsidiaries to make payments to the Fund and consequently the Fund's ability
to make distributions to the unitholders may be restricted. At December 31,
2007 we are in compliance with our debt covenants, the most restrictive of
which limits our long-term debt to three times trailing cash flow reflecting
acquisitions on a pro forma basis. Refer to "Debt of Enerplus" in our Annual
Information Form for the year ended December 31, 2006 for a detailed
description of these covenants.
Principal payments on Enerplus' senior unsecured notes are required
commencing in 2010 and 2011 and are more fully discussed in Note 7.
We anticipate that we will continue to have adequate liquidity to fund
planned development capital spending during 2008 through a combination of cash
flow retained by the business and debt.
Commitments
Enerplus has contracted to transport 104 MMcf/day of natural gas on the
Nova system in the province of Alberta as well as 20 MMcf/day of natural gas
on various pipelines to the U.S. midwest. Enerplus also 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.
Including Focus, approximately 24% of our current gas production is
dedicated to aggregator sales arrangements. 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 2007 we extended our Canadian office lease commitments. Our Canadian
and U.S. leases now 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, 2007 Enerplus has the following minimum annual
commitments including long-term debt:
Total
Minimum Annual Commitment Each Year Committed
---------------------------------------- after
($ millions) Total 2008 2009 2010 2011 2012 2012
-------------------------------------------------------------------------
Bank credit
facility $497.3(1) $ - $ - $497.3 $ - $ - $ -
Senior
unsecured
notes 323.4(1)(2) - - 53.7 64.7 64.7 140.3
Pipeline
commitments 31.1 10.0 5.9 4.0 2.8 2.4 6.0
Office
lease 67.9 6.9 7.6 10.3 10.8 11.1 21.2
-------------------------------------------------------------------------
Total
commit-
ments(3) $919.7 $16.9 $13.5 $565.3 $78.3 $78.2 $167.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
Not reflected in the above schedule are those term contracts for
transportation and the office lease that Enerplus assumed upon the completion
of the Focus acquisition. The Focus term transportation contracts consist of
45 MMcf/day of natural gas in British Columbia, and 60 MMcf/day of natural gas
in Saskatchewan.
Accumulated Deficit
We have historically paid cash distributions in excess of accumulated
earnings as cash distributions are based on 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, future income tax provisions and non-
cash charges resulting from the adoption of the financial instrument
accounting standards (see Note 2).
Trust Unit Information
We had 129,813,000 trust units outstanding at December 31, 2007 compared
to 123,151,000 trust units at December 31, 2006. The weighted average number
of trust units outstanding during 2007 was 127,691,000 (2006 - 121,588,000).
At February 20, 2008 we had 160,022,000 trust units outstanding, which
reflects the additional trust units issued to acquire Focus, and 9,087,000
exchangeable partnership units outstanding that were assumed with the Focus
acquisition and are convertible at the option of the holder into 0.425 of an
Enerplus trust unit (3,862,000 trust units).
On April 10, 2007 in conjunction with the acquisition of Kirby we issued
1,105,000 trust units as part of the purchase price consideration representing
$54.8 million and also closed a public offering of 4,250,000 trust units for
net proceeds of $199.6 million.
In addition 1,307,000 trust units (2006 - 1,242,000) 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 $56.8 million (2006 - $55.9 million) of additional equity to the
Fund.
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, as well as consider the
Government's proposal to implement a tax on trusts.
Canadian Unitholders
The Fund qualifies as a mutual fund trust under the Income Tax Act
(Canada) and accordingly, trust units of the Fund are qualified investments
for RRSPs, RRIFs, RESPs, and DPSPs. Each year the Fund has historically
transferred all of its 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 $5.04 per trust unit in cash distributions to unitholders on
record during 2007. For Canadian tax purposes, approximately 2% of these
distributions, or $0.12 per trust unit was a tax deferred return of capital,
approximately 98% or $4.92 per trust unit was taxable to unitholders as other
income, and there was no eligible dividend income.
For 2008, 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. This
preferential rate of tax for "Qualified Dividends" is set to expire at the end
of 2010. On March 24, 2007, Bill 1672 was introduced into the U.S. House of
Representatives which, if enacted as presented, would make dividends from
Canadian income funds such as Enerplus ineligible for treatment as a
"Qualified Dividend". The dividends would then become a "non-qualified
dividend from a foreign corporation" subject to the normal rates of tax
commencing with dividends received after the date of enactment. The proposed
bill still requires the approval of the House of Representatives, the Senate
and the President prior to it being enacted. Therefore, we are unable to
determine when or even if the bill will become enacted as presented.
We paid US$4.71 per trust unit to U.S. residents during the 2007 calendar
year of which 7% or US$0.33 per trust unit was a tax deferred return of
capital and 93% or US$4.38 per unit was a taxable qualified dividend.
For 2008, we estimate that 90% of cash distributions will be taxable to
most U.S. investors and 10% will be a tax deferred return of capital. Actual
taxable amounts may vary depending on actual distributions which are dependent
upon production, commodity prices and cash flow experienced throughout the
year.
Quarterly Financial Information
In general, oil and gas sales have been decreasing since the first
quarter of 2006 due mainly to lower natural gas prices and lower production.
Sales increased slightly in the fourth quarter of 2007 due to higher crude oil
prices.
Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating and G&A
costs, changes in future tax provisions due to changes in government
legislation (SIFT tax and corporate rate reductions) as well as changes to
accounting policies adopted during 2007. Furthermore, changes in the fair
value of our commodity derivative instruments along with changes in fair value
of other financial instruments cause net income to fluctuate between quarters.
Quarterly Financial
Information
(CDN$ millions,
except per trust Oil and Net Income Per Trust Unit
unit amounts) Gas Sales(1) Net Income Basic Diluted
-------------------------------------------------------------------------
2007
Fourth Quarter $ 389.8 $ 98.7 $ 0.76 $ 0.76
Third Quarter 364.8 93.0 0.72 0.72
Second Quarter 382.5 40.1 0.31 0.31
First Quarter 380.0 107.9 0.88 0.87
-----------------------------------------------
Total $ 1,517.1 $ 339.7 $ 2.66 $ 2.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006
Fourth Quarter $ 369.5 $ 110.2 $ 0.90 $ 0.89
Third Quarter 398.0 161.3 1.31 1.31
Second Quarter 403.5 146.0 1.19 1.19
First Quarter 401.7 127.3 1.08 1.07
-----------------------------------------------
Total $ 1,572.7 $ 544.8 $ 4.48 $ 4.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Summary Fourth Quarter Information
In comparing the fourth quarter of 2007 with the same period in 2006:
- Net income decreased 10% to $98.7 million due to increased commodity
derivative instrument losses, partially offset by higher oil and gas
sales.
- Cash flow was $205.1 million in 2007 similar to $207.1 million in
2006.
- Average daily production decreased 7% to 80,959 BOE/day due to the
fire at Giltedge, operational interruptions and reductions in our
development capital program.
- The average selling price per BOE increased 13% to $52.33 due to
stronger crude oil prices.
- Operating expenses of $8.57/BOE (including non-cash amounts) were
similar to the fourth quarter of 2006 at $8.52/BOE.
- G&A expenses including non-cash amounts increased 4% on a BOE basis
to $2.21/BOE from $2.13/BOE as a result of lower production.
- Development capital spending decreased 14% compared to the fourth
quarter of 2006 as a result of a reduced development capital spending
program in 2007.
The following tables provide an analysis of key financial and operating
results for the three months ended December 31, 2007 and 2006.
Three Three
Months Months
(CDN$ millions, Ended Ended
except per December 31, December 31,
unit amounts) 2007 2006
-------------------------------------------------------------------------
Financial (000's)
Net Income $ 98.7 $ 110.2
Cash Flow from Operating Activities $ 205.1 $ 207.1
Cash Distributions to Unitholders(1) $ 163.4 $ 155.0
Financial per Unit(2)
Net Income $ 0.76 $ 0.90
Cash Flow from Operating Activities $ 1.58 $ 1.69
Cash Distributions to Unitholders(1) $ 1.26 $ 1.26
Payout Ratio(3) 80% 75%
Average Daily Production 80,959 87,092
Selected Financial Results per BOE(4)
Oil and Gas Sales(5) $ 52.33 $ 46.11
Royalties (9.83) (8.26)
Commodity Derivative Instruments (0.08) 0.75
Operating Costs (8.53) (8.52)
General and Administrative (1.94) (1.88)
Interest and Foreign Exchange (1.70) (1.02)
Taxes (1.70) (0.64)
Restoration and Abandonment (0.75) (0.54)
-------------------------------------------------------------------------
Cash Flow from Operating Activities before
changes in non-cash working capital $ 27.80 $ 26.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted Average Number of Units
Outstanding (thousands) 129,658 122,971
Development Capital 106.1 123.1
Net Wells Drilled 76 89
Success Rate 100% 100%
Average Benchmark Pricing
AECO natural gas - monthly index (CDN$/Mcf) $ 6.00 $ 6.36
AECO natural gas - daily index (CDN$/Mcf) $ 6.14 $ 6.91
NYMEX natural gas - monthly NX3 index (US$/Mcf) $ 7.03 $ 6.62
NYMEX natural gas - monthly NX3 index:
CDN$ equivalent (CDN$/Mcf) $ 6.89 $ 7.52
WTI crude oil (US$/bbl) $ 90.68 $ 60.21
WTI crude oil: CDN$ equivalent (CDN$/bbl) $ 88.90 $ 68.42
CDN$/US$ exchange rate 1.02 0.88
-------------------------------------------------------------------------
(1) Calculated based on distributions paid or payable. Cash distributions
to unitholders per unit may not correspond to actual distributions of
$1.26 per trust unit as a result of using the annual weighted average
trust units outstanding.
(2) Based on weighted average trust units outstanding.
(3) Based on cash distributions divided by cash flow from operating
activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Selected Quarterly Canadian and U.S. Financial Results
(CDN$ millions, Three months ended Three months ended
except per December 31, 2007 December 31, 2006
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily
Production
Volumes
Natural gas
(Mcf/day) 245,219 12,196 257,415 271,061 6,654 277,715
Crude oil
(bbls/day) 24,248 9,973 34,221 25,903 10,436 36,339
Natural gas
liquids
(bbls/day) 3,836 - 3,836 4,467 - 4,467
Total daily
sales
(BOE/day) 68,953 12,006 80,959 75,547 11,545 87,092
Pricing(1)
Natural
gas
(per Mcf) $5.91 $5.98 $5.91 $6.57 $6.81 $6.58
Crude oil
(per bbl) $68.94 $80.16 $72.21 $52.39 $59.85 $54.53
Natural gas
liquids
(per bbl) $58.12 $- $58.12 $46.15 $- $46.15
Capital
Expenditures
Development
capital
and office $94.3 $13.7 $108.0 $96.7 $29.1 $125.8
Acquisitions
of oil and
gas
properties $5.0 $0.1 $5.1 $4.1 $0.7 $4.8
Dispositions
of oil and
gas
properties $(0.4) $(3.6) $(4.0) $(0.1) $- $(0.1)
Revenues
Oil and gas
sales(1) $309.5 $80.3 $389.8 $307.9 $61.6 $369.5
Royalties $(56.1) $(17.1)(2) $(73.2) $(54.1) $(12.1)(2) $(66.2)
Commodity
derivative
instru-
ments $(48.8) $- $(48.8) $(5.4) $- $(5.4)
Expenses
Operating $61.0 $2.8 $63.8 $66.4 $1.9 $68.3
General and
admini-
strative $16.5 $(0.1) $16.4 $14.6 $2.5 $17.1
Depletion,
depreciation,
amortization
and
accretion $89.9 $21.8 $111.7 $93.3 $26.2 $119.5
Current
income taxes $- $12.6 $12.6 $- $5.1 $5.1
-------------------------------------------------------------------------
(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 16. Most accounting policies are mandated under GAAP.
However, in accounting for oil and gas activities, we have a choice between
two acceptable accounting policies: the full cost and the successful efforts
methods of accounting.
The Fund follows the full cost method of accounting for oil and natural
gas activities. Using 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 exploration 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
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.
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 estimated (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,
amounts recorded for depletion, impairment in the cost centre, and the change
in fair value of financial contracts.
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.
Derivative Financial Instruments
Management uses derivative financial instruments to manage its exposure
to market risks relating to commodity prices, foreign currency exchange rates
and interest rates. Fair values of derivative contracts are subject to
fluctuation depending on the underlying estimate of future commodity prices,
foreign currency exchange rates and interest rates.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
Convergence of Canadian GAAP with International Financial Reporting
Standards
In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP, as used by public entities, being
converged with International Financial Reporting Standards ("IFRS") by 2011.
On February 13, 2008 the AcSB confirmed that use of IFRS will be required for
public companies beginning January 1, 2011. We continue to assess the impact
of adopting IFRS and implementing plans for transition.
Financial Instruments, Comprehensive Income and Hedges
CICA Section 3862 - Financial Instruments - Disclosures
This standard requires entities to provide disclosures in their financial
statements that enable users to evaluate the significance of financial
instruments to the entity's financial position and performance. It also
requires that entities disclose the nature and extent of risks arising from
financial instruments and how the entity manages those risks.
This standard is effective for reporting periods beginning January 1,
2008 and will result in additional disclosures for our financial instruments.
CICA Section 3863 - Financial Instruments - Presentation
This standard establishes presentation guidelines for financial
instruments and non-financial derivatives and deals with the classification of
financial instruments, from the perspective of the issuer, between liabilities
and equity, the classification of related interest, dividends, losses and
gains, and the circumstances in which financial assets and financial
liabilities are offset.
This standard is effective for reporting periods beginning January 1,
2008 and should have a minimal impact on our reporting.
CICA Section 1535 - Capital Disclosures
This section details disclosures that must be made regarding an entity's
capital and how it is managed. The standard requires qualitative information
about an entity's objectives, policies and processes for managing capital and
quantitative data about what the entity regards as capital. It requires
disclosure of compliance with any capital requirements and consequences of any
non-compliance.
This standard is effective for reporting periods beginning January 1,
2008 and will result in additional disclosures around managing capital.
RISK FACTORS AND RISK MANAGEMENT
Enerplus investors are participating in the net cash flow from a
portfolio of crude oil and natural gas producing properties. As such, the cash
distributions and the value of Enerplus units are subject to numerous risk
factors. These risk factors, many of which are associated with the oil and gas
industry, include, but are not limited to, the following influences:
Canadian Government Tax on Income Trusts
On June 22, 2007, Bill C-52 was passed by the Senate and was given royal
assent by the Governor General. As a result, our second quarter future income
tax provision includes a future income tax expense of $78.1 million related to
this legislation. This non-cash expense relates to temporary differences
between the accounting and tax basis of the Fund's assets and liabilities and
has no immediate impact on cash flow. Tax pools in 2011 may not be sufficient
to shelter taxable income from the new SIFT tax and as a result increased tax
may reduce cash flow available for distributions and development spending.
We are currently evaluating alternatives to determine the optimal
business structure for our unitholders. However, we currently see value in the
three-year tax exemption period through 2010 as a distributing entity and
would be hesitant to make major structural changes during this period without
compelling reasons that we do not currently foresee.
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
may fluctuate widely in response to a variety of factors including global and
domestic economic conditions, 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 oil price volatility.
However, we do not hedge all of our production and expect there will always be
a portion that remains unhedged. Furthermore, we may use financial 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.
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 can affect the quantity and quality of reserves and
resources and the cost of ultimately recovering those reserves and resources.
Lower oil and natural gas prices may increase the risk of write-downs of 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, mature 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 while farming out or monetizing higher risk exploratory
prospects.
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 92% 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 Enerplus evaluated internally. GLJ Petroleum
Consultants Ltd. ("GLJ") evaluated the Joslyn bitumen reserves as they have
previously performed such evaluations for the operator of the Joslyn project.
Netherland, Sewell & Associates Inc. ("NSA") of Dallas, Texas, evaluated the
reserves attributed to our assets in the United States. Both GLJ and NSA
evaluated 100% of the reserves in their respective areas. Both GLJ and NSA
utilized Sproule's forecast and constant price and cost assumptions as of
December 31, 2007 in their evaluations to maintain consistency. GLJ also
evaluated the resources attributable to our Joslyn and Kirby oil sands
projects. The Reserves Committee of the Board of Directors has reviewed and
approved the reserve and resource reports of the independent evaluators.
Operational Inflation Risk
Over the last few years we have experienced inflationary pressures on
both our development capital costs and our operating costs. Higher costs
decrease the amount of cash flow from our operating activities which may
affect the amount of distributions to unitholders.
We strive to control costs through incentive-based compensation plans
that reward employees for such things as cost control and value-added
initiatives. We attempt to minimize costs by exploiting our purchasing
strength with suppliers. We use detailed budgeting and accounting practices to
monitor costs. Multi-functional teams regularly perform integrated field
reviews designed to reduce costs and increase revenues from our properties.
Despite these efforts, it can be difficult to control costs in the oil
and gas industry, especially in periods of high commodity prices when the
demand for goods and services is strong. Oil and gas production involves a
significant amount of fixed costs that are difficult to reduce without
decreasing production. In addition, subsequent to the Focus acquisition,
approximately 30% of our production is operated by third parties. We have
limited ability to influence costs on partner-operated properties.
Access to Transportation Capacity
Market access for crude oil and natural gas production in Canada and the
United States is dependent on the ability of Enerplus and the buyers of our
production 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 pipeline capacity is
insufficient to transport all of the production from a given region, causing
volume curtailments for all shippers, including Enerplus and its production
buyers.
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 by using other means of transportation.
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.
Acquisitions of oil and gas assets depend on our assessment of value at the
time of acquisition. Incorrect assessments of value can 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.
Non-Resident Ownership and Mutual Fund Trust Status
Since our listing on the New York Stock Exchange in November of 2000, we
have seen increased trading volumes and levels of ownership by non-residents
of Canada. Based on information received from our transfer agent and financial
intermediaries in February 2008, an estimated 72% of our outstanding trust
units were held by non-residents. Immediately after the acquisition of Focus,
on February 13, 2008, we estimate that approximately 63% of our trust units
were held by non-residents. However, 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.
Enerplus currently meets 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, management does not anticipate any legislative changes that
would affect our status as a mutual fund trust; however, we have implemented
provisions in our trust indenture to allow the Board of Directors to adopt
non- resident ownership constraints, if required, in order to ensure Enerplus
maintains its mutual fund trust status.
Regulatory Risk
Government royalties, income tax laws, environmental laws and regulatory
requirements can have a significant financial and operational impact on
Enerplus. During 2007 the Alberta government announced proposed changes to the
provincial royalty program, expected to be effective on January 1, 2009 (see
the Royalties section of the MD&A for further details). Canada ratified the
Kyoto Protocol in late 2002, which requires countries to reduce their
emissions of carbon dioxide and other greenhouse gases. The Canadian federal
government is currently gathering information to set emission targets for the
industry. The details are projected to be announced by 2010 and could affect
capital expenditures and operating costs.
Our operations expose us to possible regulatory changes by both 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 through such activities as participating in
industry organizations and conferences, the exchange of information with third
party experts and employing qualified individuals to assess the impact of such
changes on our financial and operating results.
Access to Capital Markets
Our 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. As such,
we are dependent on continued access to the capital markets to fund our
activities directed towards maintaining and increasing value for our
unitholders. To the extent the cash flow retained by the Fund together with
new equity and debt financing is not sufficient to cover required capital
expenditures then cash distributions to unitholders may be reduced.
Furthermore, current tightening global credit markets may have an adverse
effect on our ability to access these capital markets.
Enerplus has listings on the Toronto and New York stock exchanges and
maintains 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.
Continued access to capital is 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.
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.
Interest Rate Exposure
The Fund has exposure to movements in interest rates. Changing interest
rates can affect borrowing costs and the trust unit price of yield-based
investments such as Enerplus.
We monitor the interest rate forward market and have fixed the interest
rate on approximately 18% of our debt through our senior unsecured notes and
interest rate swaps.
Foreign Currency Exposure
We have exposure to fluctuations in foreign currency as a result of the
issuance of senior unsecured notes 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 negatively impacted as the
Canadian dollar strengthens relative to the U.S. dollar.
We have hedged our foreign currency exposure on both our US$175 million
and US$54 million of 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.
Counterparty Risk
We assume customer credit risk associated with oil and gas sales,
financial hedging transactions and joint venture participants.
We have established credit policies and controls designed to mitigate the
risk of default or non-payment with respect to oil and gas sales, financial
hedging transactions and joint venture participants. We maintain a diversified
sales customer base and we review our single-entity exposure on a regular
basis. We do not have exposure to asset backed commercial paper, however we
do have exposure to Canadian and U.S. banks as a counterparty to financial
hedging transactions.
Unitholder Liability
In the past, there has been some concern that trust unitholders might be
held personally liable for the indebtedness of the Fund.
Enerplus is registered in Alberta, which passed legislation in June 2005
to provide statutory protection for unitholders similar to the protection
afforded shareholders in a corporation. Three other provinces (Ontario,
Quebec, and Manitoba) also have statutory protection for unitholders. Our bank
credit agreement and our debenture agreements do not allow the creditors to
extend recourse to unitholders beyond the unitholders' equity investment in
the Fund.
Recruitment and Retention of Qualified Personnel
There is strong competition in all aspects of the oil and gas industry.
Enerplus competes with a substantial number of other organizations for
capital, acquisitions of reserves, undeveloped lands, access to drilling rigs,
service rigs and other equipment, access to processing facilities, pipeline
and refining capacity and in all other aspects of our operations. Other
organizations may have greater technical and financial resources than Enerplus
which leads to increased competition. Another rising challenge is the
recruitment and retention of qualified professional staff at all levels in the
organization. Increased activity within the oil and gas sector can create a
competitive marketplace which presents challenges in recruiting and retaining
key personnel.
In order to attract and retain qualified personnel we offer competitive
compensation including performance based plans.
Summary 2008 Outlook
Enerplus offers investors the benefits of owning a large, diversified
portfolio of producing 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 2008 outlook should be taken within the context of the
current commodity price environment.
The following summarizes Enerplus' 2008 guidance as provided throughout
this MD&A and includes the acquisition of Focus at the closing date of
February 13, 2008. 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 2008 Expectations Target Comments
-------------------------------------------------------------------------
Average annual production 98,000 BOE/day Does not include any
further potential
acquisitions/divestments
Exit rate December 2008 100,000 BOE/day Assumes $580 million
production development capital
spending
2008 production mix 60% gas,
40% liquids
Average royalty rate 19% Percentage of gross
unhedged sales
Operating costs $8.65/BOE
G&A costs $2.20/BOE Includes non-cash
charges of $0.20/BOE
(unit rights incentive
plan)
U.S. income and Applied to net cash flow
withholding tax - cash costs 20% generated by U.S.
operations and assumes
repatriation of the
funds to Canada after
U.S. development capital
spending
Average interest cost 4.5% Based on current fixed
rates and forward market
Payout ratio 60% - 90%
Development capital spending $580 million
-------------------------------------------------------------------------
We expect our 2008 development capital spending to be $580 million, which
is 50% higher than our 2007 spending. We plan to continue to withhold a
portion of our cash flow to finance this capital program and we expect the
payout ratio to be within our 60-90% guidance range. We believe it is
important to maintain a conservative balance sheet as a defense against
commodity price changes and to be positioned to capture acquisition
opportunities.
We will continue to focus on low-risk development opportunities and
review our risk management strategies in response to changing prices and the
economics of our acquisition and development projects.
For 2008, we estimate that 95% of cash distributions will be taxable and
5% will be a tax-deferred return of capital for our Canadian unitholders. For
our U.S. unitholders, we estimate that 90% of cash distribution will be
taxable and 10% will be a tax-deferred return of capital.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL
REPORTING
Under the supervision of our Chief Executive Officer and Chief Financial
Officer we have evaluated the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this report and concluded
that our disclosure controls and procedures are effective. There were no
changes in our internal control over financial reporting during the quarter
ended December 31, 2007 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting.
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund, including our
Annual Information Form, is available under our profile on the SEDAR website
at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.
CONSOLIDATED BALANCE SHEETS
As at December 31 (CDN$ thousands) 2007 2006
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 1,702 $ 124
Accounts receivable 145,602 175,454
Deferred financial assets (Notes 2 and 3) 10,157 23,612
Future income taxes (Note 11) 10,807 -
Other current 6,373 6,715
-------------------------------------------------------------------------
174,641 205,905
Property, plant and equipment (Note 4) 3,872,818 3,726,097
Goodwill (Note 1(f)) 195,112 221,578
Other assets (Note 12) 60,559 50,224
-------------------------------------------------------------------------
$ 4,303,130 $ 4,203,804
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 269,375 $ 284,286
Distributions payable to unitholders 54,522 51,723
Deferred financial credits (Notes 2 and 3) 52,488 -
-------------------------------------------------------------------------
376,385 336,009
-------------------------------------------------------------------------
Long-term debt (Note 7) 726,677 679,774
Deferred financial credits (Notes 2 and 3) 90,090 -
Future income taxes (Note 11) 304,259 331,340
Asset retirement obligations (Note 5) 165,719 123,619
-------------------------------------------------------------------------
1,286,745 1,134,733
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 10)
Trust Units
Authorized: Unlimited
Issued and Outstanding: 2007 - 129,813,445
2006 - 123,150,820 4,032,680 3,713,126
Accumulated deficit (1,283,953) (971,085)
Accumulated other comprehensive income
(Notes 1(j) and 2) (108,727) (8,979)
-------------------------------------------------------------------------
(1,392,680) (980,064)
2,640,000 2,733,062
-------------------------------------------------------------------------
$ 4,303,130 $ 4,203,804
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
For the year ended December 31 (CDN$ thousands) 2007 2006
-------------------------------------------------------------------------
Accumulated income, beginning of year $ 1,952,960 $ 1,408,178
Adjustment for adoption of financial
instruments standards (Note 2) (5,724) -
-------------------------------------------------------------------------
Revised Accumulated income, beginning of year 1,947,236 1,408,178
Net income 339,691 544,782
-------------------------------------------------------------------------
Accumulated income, end of year $ 2,286,927 $ 1,952,960
Accumulated cash distributions,
beginning of year $(2,924,045) $(2,309,705)
Cash distributions (646,835) (614,340)
-------------------------------------------------------------------------
Accumulated cash distributions, end of year $(3,570,880) $(2,924,045)
-------------------------------------------------------------------------
Accumulated deficit, end of year $(1,283,953) $ (971,085)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
For the year ended December 31 (CDN$ thousands) 2007 2006
-------------------------------------------------------------------------
Balance, beginning of year $ (8,979) $ (15,568)
Transition adjustments (Note 2):
Cash flow hedges 660 -
Available for sale marketable securities 14,252 -
Other comprehensive (loss)/income (114,660) 6,589
-------------------------------------------------------------------------
Balance, end of year $ (108,727) $ (8,979)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
For the year ended December 31
(CDN$ thousands except per trust unit amounts) 2007 2006
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 1,539,153 $ 1,595,324
Royalties (285,148) (296,554)
Commodity derivative instruments (Notes 3
and 12) (52,841) (3,226)
Other income (Note 12) 14,991 2,465
-------------------------------------------------------------------------
1,216,155 1,298,009
-------------------------------------------------------------------------
Expenses
Operating 274,150 251,239
General and administrative (Note 10(b)) 67,921 59,937
Transportation 22,098 22,611
Interest (Note 8) 33,627 32,168
Foreign exchange (Note 9) (7,071) (528)
Depletion, depreciation, amortization
and accretion 463,718 481,598
-------------------------------------------------------------------------
854,443 847,025
-------------------------------------------------------------------------
Income before taxes 361,712 450,984
Current taxes 23,011 18,236
Future income tax recovery (Note 11) (990) (112,034)
-------------------------------------------------------------------------
Net Income $ 339,691 $ 544,782
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 2.66 $ 4.48
Diluted $ 2.66 $ 4.47
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)
Basic 127,691 121,588
Diluted 127,752 121,858
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the year ended December 31 (CDN$ thousands) 2007 2006
-------------------------------------------------------------------------
Net income $ 339,691 $ 544,782
-------------------------------------------------------------------------
Other comprehensive (loss)/income, net of tax:
Unrealized gain on marketable securities 629 -
Realized gains on marketable securities
included in net income (11,302) -
Gains and losses on derivatives designated as
hedges in prior periods included in net income (733) -
Change in cumulative translation adjustment (103,254) 6,589
-------------------------------------------------------------------------
Other comprehensive (loss)/income (114,660) 6,589
-------------------------------------------------------------------------
Comprehensive income (Note 2) $ 225,031 $ 551,371
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the year ended December 31 (CDN$ thousands) 2007 2006
-------------------------------------------------------------------------
Operating Activities
Net income $ 339,691 $ 544,782
Non-cash items add/(deduct):
Depletion, depreciation, amortization and
accretion 463,718 481,598
Change in fair value of derivative
instruments (Note 3) 91,852 (31,106)
Unit based compensation (Note 10(b)) 8,435 6,323
Foreign exchange on translation of senior
notes (Note 9) (41,182) (32)
Future income tax (Note 11) (990) (112,034)
Amortization of senior notes premium (631) -
Reclassification adjustments from AOCI to
net income (733) -
Other (132) -
Gain on sale of marketable securities (Note 12) (14,055) -
Asset retirement obligations settled (Note 5) (16,280) (11,514)
-------------------------------------------------------------------------
829,693 878,017
Decrease/(Increase) in non-cash operating
working capital 38,855 (14,321)
-------------------------------------------------------------------------
Cash flow from operating activities 868,548 863,696
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue costs (Note 10) 256,369 296,189
Cash distributions to unitholders (646,835) (614,340)
Increase in bank credit facilities (Note 7) 148,827 19,888
Decrease in non-cash financing working capital 2,799 2,356
-------------------------------------------------------------------------
Cash flow from financing activities (238,840) (295,907)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (393,655) (496,201)
Property acquisitions (Note 6) (226,480) (51,313)
Property dispositions 2,947 1,599
Proceeds on sale of marketable securities 16,467 -
Purchase of investments (2,927) (29,172)
Increase in non-cash investing working capital (21,046) (3,535)
-------------------------------------------------------------------------
Cash flow from investing activities (624,694) (578,622)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash (3,436) 864
-------------------------------------------------------------------------
Change in cash 1,578 (9,969)
Cash, beginning of year 124 10,093
-------------------------------------------------------------------------
Cash, end of year $ 1,702 $ 124
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ 17,431 $ 14,060
Cash interest paid $ 42,861 $ 34,924
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 ("GAAP"). 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 CIBC Mellon Trust Company as
Trustee. 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 volumes delivered and contractual delivery points and
price. 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 loss 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.
Changes in goodwill during 2007 represent the effects of foreign exchange
recorded in our U.S. subsidiary.
(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 28.0% SIFT
(specified investment flow-through entities) 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. A provision
has been setup to reflect these current U.S. income taxes.
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
Commencing on January 1, 2007 financial assets and financial liabilities
classified as held-for-trading are measured at fair value with changes in
fair value recognized in net income. Financial assets classified as loans
and receivables along with financial liabilities classified as other
liabilities are measured at amortized cost using the effective interest
rate method. Financial assets classified as available-for-sale are
measured at fair value with changes in fair value recognized in other
comprehensive income ("OCI"). Investments in equity instruments
classified as available-for-sale that do not have a quoted price in an
active market or a readily determinable fair value are measured at cost.
Transaction costs or fees attributable to the acquisition, issue, or
disposal of a financial asset or liability are expensed immediately to
net income.
Derivative instruments are recorded on the consolidated balance sheets at
fair value, including those derivatives that are embedded in financial or
non-financial contracts that are not closely related to the host
contracts. Changes in the fair values of derivative instruments are
recognized in net income.
(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
Financial Instruments
Effective January 1, 2007, the Fund adopted five new accounting standards
that were issued by the CICA: Handbook Section 1530, Comprehensive
Income, Handbook Section 3251, Equity, Handbook Section 3855, Financial
Instruments - Recognition and Measurement, Handbook Section 3861,
Financial Instruments - Disclosure and Presentation and Handbook Section
3865, Hedges. These standards were adopted retrospectively without
restatement, with the exception of CTA amounts which have been
reclassified to AOCI.
Comprehensive Income
CICA Handbook Section 1530 introduces comprehensive income, which
consists of net income and other comprehensive income ("OCI").
Comprehensive income represents changes in equity during a period
arising from transactions and other events and circumstances with
non-owner sources. OCI comprises revenues, expenses, gains and
losses that are recognized in comprehensive income but excluded
from net income. Examples of these gains and losses are unrealized
gains and losses on marketable securities classified as available-
for-sale along with unrealized foreign currency translation gains
or losses arising from self-sustaining foreign operations. The
Consolidated Statements of Comprehensive Income include a
calculation of comprehensive income, while the cumulative changes
in OCI are included in the Statements of Accumulated Other
Comprehensive Income (AOCI). CICA Handbook Section 3251
establishes standards for the presentation of equity and changes
in equity during the period.
Financial Instruments - Recognition and Measurement
CICA Handbook Section 3855 establishes the criteria for
recognizing and measuring financial assets, financial liabilities
and non-financial derivatives. Under this standard, all financial
instruments are required to be measured at fair value on
recognition except for certain related party transactions.
Measurement in subsequent periods depends on whether the financial
instrument has been classified as held-for-trading, available-for-
sale, held-to-maturity, loans and receivables, or other financial
liabilities.
Financial assets and financial liabilities classified as held-for-
trading are measured at fair value with changes in fair value
recognized in net income. Financial assets classified as loans and
receivables along with financial liabilities classified as other
liabilities are measured at amortized cost using the effective
interest rate method. Financial assets classified as available-
for-sale are measured at fair value with changes in fair value
recognized in OCI. Investments in equity instruments classified as
available-for-sale that do not have a quoted price in an active
market are measured at cost. Transaction costs or fees
attributable to the acquisition, issue, or disposal of a financial
asset or liability are expensed immediately to net income.
Derivative instruments are recorded on the consolidated balance
sheets at fair value, including those derivatives that are
embedded in financial or non-financial contracts that are not
closely related to the host contracts. Embedded derivatives are
included as of January 1, 2003. Changes in the fair values of
derivative instruments are recognized in net income with the
exception of derivatives that are designated as effective cash
flow hedges. Refer to the Hedges section for further detail.
CICA Handbook Section 3861 establishes standards for the
presentation and disclosure of financial instruments and non-
financial derivatives.
Hedges
CICA Handbook Section 3865 specifies the criteria and method of
accounting for each of the designated hedging strategies.
When hedge accounting is discontinued for a cash flow hedge, the
amounts previously recognized in AOCI are reclassified to net
income over the remaining term of the hedged item.
When hedge accounting is discontinued for a fair value hedge, the
carrying value of the hedged item is no longer adjusted. Any
difference between the carrying value and the face value or
principal amount of the hedged item is amortized to net income
over the remaining term of the original hedging relationship using
the effective interest method.
Impact upon Adoption of Sections 1530, 3251, 3855, 3861 and 3865
As a result of the adoption of these standards on January 1, 2007 the
Fund elected to stop designating its interest rate and electricity swaps
as cash flow hedges and recorded these items on the consolidated balance
sheet at their fair values with the offset recorded to opening
accumulated other comprehensive income. In addition, the Fund elected to
stop designating its cross currency and interest rate swap ("CCIRS") as a
fair value hedge and recorded the CCIRS on the consolidated balance sheet
at fair value with the offset recorded to opening accumulated deficit. In
conjunction, the underlying US$175,000,000 senior unsecured notes were
recorded at fair value with the offset recorded to opening accumulated
deficit.
The Fund's investments in marketable securities have been classified as
available-for-sale and therefore those that have a quoted price in an
active market were recorded on the consolidated balance sheet at fair
value with the offset recorded to opening AOCI.
Deferred charges of $1,523,000 associated with issuance of the senior
unsecured notes were recorded to the opening accumulated deficit.
Amounts previously recorded in the cumulative translation adjustment were
reclassified into opening AOCI. Our prior year comparative statements
have been restated to reflect this change.
The Fund has recorded the following transition adjustments as of
January 1, 2007 in the Consolidated Financial Statements: (a) an increase
of $1,494,000 to deferred financial assets to record the electricity
swaps at fair value; (b) an increase to other current assets of
$14,493,000 to record publicly traded marketable securities at fair
value; (c) an increase of $1,708,000 to other assets, consisting of
$3,231,000 to record publicly traded marketable securities at fair value
less $1,523,000 to write-off the deferred charges associated with the
issuance of the senior unsecured notes; (d) an increase of $65,675,000 to
deferred financial credits to record the CCIRS and interest rates swaps
at fair value; (e) a decrease to long-term debt of $60,111,000 to record
the US$175,000,000 senior unsecured note at fair value; (f) an increase
to future income taxes of $ 2,943,000 to reflect the tax impact of the
adoption entries; (g) an increase of $5,724,000, net of taxes, to the
opening accumulated deficit; (h) recognition in AOCI of $14,912,000, net
of taxes, related to the net gains on marketable securities classified as
available-for-sale along with the fair value of the interest rate and
power swaps formerly designated as cash flow hedges. In addition, the
Fund reclassified to AOCI $8,979,000 of net unrealized foreign currency
losses that were previously presented as a separate item in equity. These
transition adjustments are summarized below.
Impact of transition adjustment on selected consolidated balance sheets
line items:
Transition adjustment
Increase/decrease (CDN$ thousands) as at January 1, 2007
-------------------------------------------------------------------------
Deferred financial assets $ 1,494
Other current assets 14,493
Other assets 1,708
Deferred financial credits 65,675
Long-term debt (60,111)
Future income taxes 2,943
Accumulated deficit (5,724)
Cumulative translation adjustment 8,979
Accumulated other comprehensive income 5,933
-------------------------------------------------------------------------
As a result of these changes, net income increased by $5,619,000
($7,943,000 before future income taxes of $2,324,000) for the year ended
December 31, 2007. Both the basic and diluted net income per trust unit
calculations for the year ended December 31, 2007 increased by $0.04.
Recent Canadian Accounting Pronouncements
CICA Section 3862 - Financial Instruments - Disclosures
This standard requires entities to provide disclosures in their financial
statements that enable users to evaluate the significance of financial
instruments to the entity's financial position and performance. It also
requires that entities disclose the nature and extent of risks arising
from financial instruments and how the entity manages those risks.
This standard is effective for reporting periods beginning after
January 1, 2008 and will result in additional disclosures for our
financial instruments.
CICA Section 3863 - Financial Instruments - Presentation
This standard establishes presentation guidelines for financial
instruments and non-financial derivatives and deals with the
classification of financial instruments, from the perspective of the
issuer, between liabilities and equity, the classification of related
interest, dividends, losses and gains, and the circumstances in which
financial assets and financial liabilities are offset.
This standard is effective for reporting periods beginning after
January 1, 2008 and should have a minimal impact on our reporting.
CICA Section 1535 - Capital Disclosures
This section details disclosures that must be made regarding an entity's
capital and how it is managed. The standard requires qualitative
information about an entity's objectives, policies and processes for
managing capital and quantitative data about what the entity regards as
capital. It requires disclosure of compliance with any capital
requirements and consequences of any non-compliance.
This standard is effective for reporting periods beginning after
January 1, 2008 and will result in additional disclosures around managing
capital.
3. DEFERRED FINANCIAL ASSETS AND DEFERRED FINANCIAL CREDITS
The deferred financial assets and credits result from recording our
derivative financial instruments at fair value. At December 31, 2007 a
current deferred financial asset of $10,157,000, a current deferred
financial credit of $52,488,000 and a long-term deferred financial credit
of $90,090,000 are recorded on the consolidated balance sheet.
The deferred financial credit relating to crude oil instruments of
$52,488,000 at December 31, 2007 consists of the fair value of the
financial instruments, representing a loss position of $44,749,000, plus
the related deferred premiums of $7,739,000. The deferred financial asset
relating to natural gas instruments of $9,707,000 at December 31, 2007
consists of the fair value of the financial instruments of $10,628,000
less the related deferred premiums of $921,000.
Cross
Currency Foreign
Interest Interest Exchange Electricity
($ thousands) Rate Swaps Rate Swaps Swaps Swaps
-------------------------------------------------------------------------
Deferred financial
assets/(credits) as
at December 31,
2006 $ - $ - $ - $ -
Adoption of financial
instruments standards
(Note 2) (673) (65,002) - 1,494
Change in fair value
asset/(credits)
(Note 12) 447(1) (24,437)(2) (425)(3) (1,044)(4)
-------------------------------------------------------------------------
Deferred financial
assets/(credits) as
at December 31,
2007 $ (226) $ (89,439) $ (425) $ 450
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance sheet
classification:
Current asset/
(credit) $ - $ - $ - $ 450
Long-term asset/
(credit) $ (226) $ (89,439) $ (425) $ -
-------------------------------------------------------------------------
Commodity
Derivative
Instruments
($ thousands) Oil Gas Total
-------------------------------------------------------------
Deferred financial
assets/(credits) as
at December 31,
2006 $ 10,922 $ 12,690 $ 23,612
Adoption of financial
instruments standards
(Note 2) - - (64,181)
Change in fair value
asset/(credits)
(Note 12) (63,410)(5) (2,983)(5) (91,852)
-------------------------------------------------------------
Deferred financial
assets/(credits) as
at December 31,
2007 $ (52,488) $ 9,707 $ (132,421)
-------------------------------------------------------------
-------------------------------------------------------------
Balance sheet
classification:
Current asset/
(credit) $ (52,488) $ 9,707 $ (42,331)
Long-term asset/
(credit) $ - $ - $ (90,090)
-------------------------------------------------------------
(1) Recorded in interest expense.
(2) Recorded in foreign exchange expense (loss of $31,777) and interest
expense (gain of $7,340).
(3) Recorded in foreign exchange expense.
(4) Recorded in operating expense.
(5) Recorded in commodity derivative instruments (see below).
The following table summarizes the income statement effects of commodity
derivative instruments:
($ thousands) 2007 2006
-------------------------------------------------------------------------
Change in fair value loss/(gain) $ 66,393 $ (80,980)
Amortization of deferred financial assets - 49,874
Realized cash (gains)/losses, net (13,552) 34,332
-------------------------------------------------------------------------
Commodity derivative instruments loss $ 52,841 $ 3,226
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. PROPERTY, PLANT AND EQUIPMENT
($ thousands) 2007 2006
-------------------------------------------------------------------------
Property, plant and equipment $ 6,429,241 $ 5,855,511
Accumulated depletion, depreciation and
accretion (2,556,423) (2,129,414)
-------------------------------------------------------------------------
Net property, plant and equipment $ 3,872,818 $ 3,726,097
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development general and administrative ("G&A") expenses of
$17,185,000 (2006 - $14,111,000) are included in PP&E. The depletion and
depreciation calculation includes future capital costs of $521,650,000
(2006 - $472,567,000) as indicated in our reserve reports. Excluded from
PP&E for the depletion and depreciation calculation is $321,801,000 (2006
- $81,183,000) related to the Joslyn development project and the Kirby
Oil Sands project, both of which have not yet commenced commercial
production.
An impairment test calculation was performed on a country by country
basis on the PP&E values at December 31, 2007 in which the estimated
undiscounted future net cash flows associated with the proved reserves
exceeded the carrying amount of the Fund's PP&E.
The following table outlines benchmark prices and the exchange rate used
in the impairment tests for both Canadian and U.S. cost centres at
December 31, 2007:
Natural Gas
WTI Crude Exchange Edm Light 30 day spot
Oil(1) Rate Crude(1) @ AECO(1)
Year US$/bbl US$/CDN$ CDN$/bbl CDN$/Mcf
-------------------------------------------------------------------------
2008 $ 89.61 $ 1.00 $ 88.17 $ 6.51
2009 86.01 1.00 84.54 7.22
2010 84.65 1.00 83.16 7.69
2011 82.77 1.00 81.26 7.70
2012 82.26 1.00 80.73 7.61
Thereafter (*) 1.00 (*) (*)
-------------------------------------------------------------------------
(1) Actual prices used in the impairment test were adjusted for commodity
price differentials specific to the Fund.
(*) Escalation varies after 2012.
5. 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 $165,719,000 at December 31, 2007 compared to
$123,619,000 at December 31, 2006 based on a total undiscounted liability
of $542,781,000 and $436,663,000 respectively. These payments are
expected to be made over the next 66 years with the majority of costs
incurred between 2038 and 2047. To calculate the present value of the
asset retirement obligations for 2007 the Fund used a weighted credit-
adjusted rate of approximately 6.1% and an inflation rate of 2.0%, (2006
- 6.3% and 2.0%). Settlements during the year approximated our estimates
and as a result, no gains or losses were recognized.
Following is a reconciliation of the asset retirement obligations:
($ thousands) 2007 2006
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year $ 123,619 $ 110,606
Changes in estimates 46,000 12,757
Acquisition and development activity 6,441 5,574
Dispositions (756) (45)
Asset retirement obligations settled (16,280) (11,514)
Accretion expense 6,695 6,241
-------------------------------------------------------------------------
Asset retirement obligations, end of year $ 165,719 $ 123,619
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. PROPERTY ACQUISITIONS
Kirby Oil Sands Partnership
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) 2007 2006
-------------------------------------------------------------------------
Bank credit facilities(a) $ 497,347 $ 348,520
Senior notes(b)
US$175 million (issued June 19, 2002) 175,973 268,328
US$54 million (issued October 1, 2003) 53,357 62,926
-------------------------------------------------------------------------
Total long-term debt $ 726,677 $ 679,774
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus currently has a $1.4 billion unsecured covenant based three year
term facility ($1.0 billion at December 31, 2007). The facility is
extendible each year with a bullet payment required at the end of the
three year term. In the first quarter of 2008 the bank credit facility
size was increased in conjunction with the acquisition of Focus Energy
Trust ("Focus") (see Note 15). At December 31, 2007 Enerplus had
available credit of $502,653,000 based on a facility size of $1.0 billion
at that time. In conjunction with the Focus acquisition, Enerplus
acquired approximately $340 million in Focus debt. Various borrowing
options are available under the facility including prime rate based
advances and bankers' acceptance loans. This facility carries floating
interest rates that are expected to range between 55.0 and 110.0 basis
points over bankers' acceptance rates, depending on Enerplus' ratio of
senior debt to earnings before interest, taxes and non-cash items. The
effective interest rate on the facility for the year ended December 31,
2007 was 5.1% (2006 - 4.8%).
(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 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 exchange rate was 1.35 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.
During September 2007 Enerplus entered into foreign exchange swaps that
effectively fix the five principal payments on the US$54,000,000 senior
unsecured notes at a CAD/US exchange rate of 1.02.
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 (CDN $208,217,000)
with the offset to opening accumulated deficit. In addition, the Fund
recorded a liability of $65,002,000 with the offset to opening
accumulated deficit, which represented the fair value of the CCIRS. 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, 2007 the amortized cost of the
US$175,000,000 senior notes was US$178,093,000
The bank credit facility and the senior notes (the "Combined Facilities")
are the legal obligation of EnerMark Inc. and are guaranteed by its
subsidiaries. Payments with respect to the Combined Facilities have
priority over payments to the Fund and over claims of and future
distributions to the unitholders. However, unitholders have no direct
liability beyond their equity investment should cash flow be insufficient
to repay the Combined Facilities.
8. INTEREST EXPENSE
($ thousands) 2007 2006
-------------------------------------------------------------------------
Realized
Interest on long-term debt $ 41,934 $ 32,168
Unrealized
Gain on cross currency interest rate swap (7,340) -
Gain on interest rate swaps (447) -
Amortization of the premium on senior
unsecured notes (631) -
Other 111 -
-------------------------------------------------------------------------
Interest Expense $ 33,627 $ 32,168
-------------------------------------------------------------------------
-------------------------------------------------------------------------
9. FOREIGN EXCHANGE
($ thousands) 2007 2006
-------------------------------------------------------------------------
Unrealized foreign exchange gain on translation
of U.S. dollar denominated senior notes $ (41,182) $ (32)
Unrealized foreign exchange loss on cross
currency interest rate swap 31,777 -
Unrealized foreign exchange loss on foreign
exchange swaps 425 -
Realized foreign exchange loss/(gain) 1,909 (496)
-------------------------------------------------------------------------
Foreign exchange gain $ (7,071) $ (528)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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. FUND CAPITAL
(a) Unitholders' Capital
Trust Units
Authorized: Unlimited number of trust units
(thousands) 2007 2006
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance before
Contributed Surplus,
beginning of year 123,151 $ 3,706,821 117,539 $ 3,407,567
Issued for cash:
Pursuant to public
offerings 4,250 199,558 4,370 240,287
Pursuant to rights
incentive plan 205 6,758 640 22,974
Trust unit rights
incentive plan
(non-cash) - exercised - 2,288 - 3,065
DRIP(*), net of
redemptions 1,102 50,053 602 32,928
Issued for acquisition
of corporate and
property interests
(non-cash) 1,105 54,750 - -
-------------------------------------------------------------------------
129,813 4,020,228 123,151 3,706,821
Contributed Surplus
(Trust Unit Rights
Incentive Plan) - 12,452 - 6,305
-------------------------------------------------------------------------
Balance, end of year 129,813 $ 4,032,680 123,151 $ 3,713,126
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Distribution Reinvestment and Unit Purchase Plan
Contributed surplus ($ thousands) 2007 2006
-------------------------------------------------------------------------
Balance, beginning of year $ 6,305 $ 3,047
Trust unit rights incentive plan (non-cash) -
exercised (2,288) (3,065)
Trust unit rights incentive plan (non-cash) -
expensed 8,435 6,323
-------------------------------------------------------------------------
Balance, end of year $ 12,452 $ 6,305
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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). These trust units were eligible for
the April 20, 2007 cash distribution paid to unitholders of record at the
close of business on April 10, 2007.
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.
On March 20, 2006 the Fund closed an equity offering of 4,370,000 units
at a price of $58.00 per unit for gross proceeds of $253,460,000
($240,287,000 net of issuance costs).
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) Trust Unit Rights Incentive Plan
As at December 31, 2007 a total of 3,404,000 rights issued pursuant to
the Trust Unit Rights Incentive Plan ("Rights Incentive Plan") were
outstanding at an average exercise price of $47.59. This represents 2.6%
of the total trust units outstanding of which 1,635,000 rights, with an
average exercise price of $44.84, 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, 2007 reduced the exercise price of the outstanding rights by
$2.05 per trust unit of which a $0.52 reduction is effective January 2008
and a $0.51 reduction is effective April 2008. 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 lower the plan
member's tax rate on the transaction.
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:
2007 2006
-------------------------------------------------------------------------
Dividend yield 10.37% 9.26%
Volatility 26.35% 25.61%
Risk-free interest rate 4.41% 4.13%
Forfeiture rate 6.20% 2.80%
Right's exercise price reduction $1.75 $1.61
-------------------------------------------------------------------------
The fair value of the rights granted under the plan during 2007 ranged
between 9% and 12% (2006 - 12% and 14% of the underlying market price of
a trust unit on the grant date.
During the year the Fund expensed $8,435,000 or $0.07 per unit (2006 -
$6,323,000 or $0.05 per unit) of unit based compensation expense using
the fair value method. The remaining future fair value of the rights of
$6,195,000 at December 31, 2007 (2006 - $10,113,000) 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:
2007 2006
-------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Rights Exercise Rights Exercise
(000's) Price(1) (000's) Price(1)
-------------------------------------------------------------------------
Trust unit rights
outstanding
Beginning of year 3,079 $ 48.53 2,621 $ 42.80
Granted 816 48.71 1,473 54.49
Exercised (205) 32.90 (640) 35.94
Cancelled (286) 50.74 (375) 46.35
-------------------------------------------------------------------------
End of year 3,404 47.59 3,079 48.53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable
at the end of the
year 1,635 $ 44.84 809 $ 39.81
-------------------------------------------------------------------------
(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, 2007. Rights vest between one and three years
and expire between four and six years.
Rights Exercise Rights
Outstanding Original Price after Exercisable
at December 31, Exercise Price Expiry Date at December 31,
2007 (000's) Price Reductions December 31 2007 (000's)
-------------------------------------------------------------------------
16 $ 26.09 $ 18.30 2008 16
4 27.70 20.11 2008 - 2009 4
8 33.00 25.72 2008 - 2009 8
7 36.00 29.10 2008 - 2009 7
128 37.62 31.11 2008 - 2009 128
8 40.70 34.58 2008 - 2010 8
23 37.25 31.50 2008 - 2010 23
49 38.83 33.48 2008 - 2010 49
341 40.80 35.80 2008 - 2010 341
68 45.55 40.87 2009 - 2011 45
72 44.86 40.53 2009 - 2011 46
126 49.75 45.82 2009 - 2011 96
532 56.93 53.41 2009 - 2011 364
145 56.55 53.51 2010 - 2012 63
402 54.21 51.67 2010 - 2012 156
252 56.00 53.97 2010 - 2012 114
443 52.90 51.38 2010 - 2012 167
168 48.86 47.84 2011 - 2013 -
444 50.25 49.74 2011 - 2013 -
153 45.14 45.14 2011 - 2013 -
15 38.70 38.70 2011 - 2013 -
-------------------------------------------------------------------------
3,404 $ 50.32 $ 47.59 1,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Basic and Diluted per Trust Unit Calculations
Net income per trust unit has been determined based on the following:
(thousands) 2007 2006
-------------------------------------------------------------------------
Weighted average units 127,691 121,588
Dilutive impact of rights 61 270
-------------------------------------------------------------------------
Diluted trust units 127,752 121,858
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In 2007 we excluded 222,347 rights because their exercise price was
greater than the annual average unit market price of $47.11. No rights
were excluded in calculating the weighted average number of diluted units
for the year ended December 31, 2006. During the last two years,
outstanding rights were the only potential dilutive instrument.
(d) 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.
At December 31, 2007 there were 179,000 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 2007, the Fund had taxable income of $632,000,000 (2006 -
$588,000,000) or $4.92 per trust unit (2006 - $4.81 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 2007. The amounts
of COGPE and issue costs in the fund remaining as at December 31, 2007
are $466,700,000 and $30,289,000 respectively.
Canadian Government's tax on income trusts
On June 22, 2007 Bill C-52, which contained legislative provisions to
implement the proposals to tax publicly traded income trusts in Canada
became law. As a result, our second quarter future income tax provision
included a future income tax expense of $78,110,000 related to this
legislation. This non- cash expense related to temporary differences
between the accounting and tax basis of the Fund's assets and liabilities
at that time and had no immediate impact on cash flow.
On December 14, 2007, Bill C-28, which contained legislative provisions
to implement corporate income tax rate reductions announced in the
October 30, 2007 fall economic statement, became law. The general
corporate tax rate will decrease by 1.0% in 2008 from 20.5% to 19.5%.
There are additional rate reductions scheduled until the target federal
tax rate of 15.0% is reached as of January 1, 2012. These rate reductions
will also apply to the SIFT tax on distributions from income trusts. The
SIFT tax rate will fall by 3.5% from 31.5% to 28.0%. As a result, our
year to date future income tax provision includes a future income tax
recovery of $22,640,000 related to this legislation and other tax rate
changes enacted earlier in the year.
We are currently evaluating alternatives to determine the optimal
structure for our unitholders. However, we see value in the remaining
three- year tax exemption period through 2010 and will look to maintain
our current structure during this period unless there are compelling
reasons to change.
The future income tax liability on the balance sheet arises as a result
of the following temporary differences:
($ thousands) Canadian Foreign 2007 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)
-------------------------------------------------------------------------
Net future income tax
liability/(asset) $ 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
-------------------------------------------------------------------------
($ thousands) Canadian Foreign 2006 Total
-------------------------------------------------------------------------
Excess of net book value of
property, plant and equipment
over the underlying tax bases $ 179,770 $ 183,081 $ 362,851
Asset retirement obligations (37,667) - (37,667)
Other 6,963 (807) 6,156
-------------------------------------------------------------------------
Future income taxes $ 149,066 $ 182,274 $ 331,340
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current future income tax asset $ - $ - $ -
Long-term future income tax
liability $ 149,066 $ 182,274 $ 331,340
-------------------------------------------------------------------------
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) 2007 2006
-------------------------------------------------------------------------
Income before taxes $ 361,712 $ 450,984
-------------------------------------------------------------------------
Computed income tax expense at the enacted
rate of 32.41% (34.88% for 2006) $ 117,231 $ 157,303
Increase (decrease) resulting from:
Net income attributed to the Fund (162,016) (197,694)
Non-deductible crown royalties - 11,878
Resource allowance - (11,998)
Amended returns and pool balances 5,150 (21,446)
Change in tax rate (22,640) (35,500)
SIFT Tax 78,110 -
Other 6,186 3,659
-------------------------------------------------------------------------
$ 22,021 $ (93,798)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax recovery $ (990) $ (112,034)
Current tax $ 23,011 $ 18,236
-------------------------------------------------------------------------
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, 2007
($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Future income (recovery)/expense $ (8,183) $ 7,193 $ (990)
Current income tax - 23,011 23,011
-------------------------------------------------------------------------
For the year ended December 31, 2006
($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Future income expense $ (113,643) $ 1,609 $ (112,034)
Current income tax - 18,236 18,236
-------------------------------------------------------------------------
12. FINANCIAL INSTRUMENTS
(a) Fair Value of Financial Instruments
As a result of the adoption of the new financial instrument and hedging
accounting standards described in Note 2, 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. 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.
The Fund is exposed to the commodity price fluctuations of crude oil and
natural gas and to fluctuations in the Canada/US dollar exchange rate.
The Fund manages this risk by entering into various derivative financial
instruments.
The Fund is exposed to credit risk due to the potential non-performance
of counterparties to our financial instruments. The Fund mitigates this
risk by having an established credit policy and controls designed to
mitigate the risk of default or non-payment.
The Fund has exposure to movements in interest rates. Changing interest
rates can affect borrowing costs and the price on yield-based investments
such as Enerplus trust units. The Fund monitors the interest rate forward
market and has fixed the interest rate on a portion of our debt through
our senior unsecured notes and interest rate swaps.
(b) Carrying Value and Fair Value of 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, 2007 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. As at
December 31, 2007 the Fund reported investments in marketable securities
of publicly traded marketable securities at a fair value of $14,676,000.
For the year ended December 31, 2007, the change in fair value of these
investments represented a gain of $950,000 ($629,000 net of tax).
Marketable securities without a quoted market price in an active market
are reported at cost. As at December 31, 2007 the Fund reported
investments in marketable securities of private companies at cost of
$45,400,000.
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) being reclassified from accumulated other comprehensive income to
net income. This gain is included in the other income balance of
$14,991,000 on the Consolidated Statements of Income.
As at December 31, 2007 total marketable securities of $60,076,000 are
included in other assets or 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, 2007 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, 2007 the carrying value of the bank
credit facilities approximated their fair value.
US$54 million senior notes
The US$54,000,000 million 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, 2007 the Canadian dollar amortized cost of the senior notes
was approximately $53,357,000 and the fair value of these notes was
$56,585,000.
US$175 million senior notes
The US$175,000,000 million senior notes, which are classified as other
liabilities, are reported at amortized cost of US$178,093,000 and are
translated to Canadian dollars at the period end exchange rate. At
December 31, 2007 the Canadian dollar amortized cost of the senior notes
was approximately $175,973,000 and the fair value of these notes was
$185,591,000.
vi. Derivative Financial Instruments
Interest Rate Swaps
The Fund has entered into interest rate swaps on $75,000,000 of notional
debt at rates varying from 4.10% to 4.61% before banking fees that are
expected to range between 0.55% and 1.10%. These interest rate swaps
mature between June 2011 and January 2012. The interest rate swaps are
classified as held-for-trading and are reported at fair value. At
December 31, 2007 the fair value of the interest rate swaps represented a
liability of $226,000 and the change in fair value of these contracts
represented an unrealized gain of $447,000.
Cross Currency Interest Rate Swap (CCIRS)
Concurrent with the issuance of the 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%. The CCIRS is
classified as held-for- trading and is reported at fair value. At
December 31, 2007 the fair value of the CCIRS represented a liability of
$89,439,000 and the change in fair value of the CCIRS represented an
unrealized loss of $24,437,000.
Foreign Exchange Swaps
In September 2007 the Fund entered into foreign exchange swaps on
US$54,000,000 of notional debt at an average CAD/US foreign exchange rate
of 1.02. These foreign exchange swaps mature between October 2011 and
October 2015 in conjunction with the principal repayments on the
US$54,000,000 senior notes. The foreign exchange swaps are classified as
held-for-trading and are reported at fair value. At December 31, 2007 the
fair value of the interest rate swaps represented a liability of $425,000
and the change in fair value of these contracts represented an unrealized
loss of $425,000.
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, 2007 the fair value of these
contracts represented an asset of $450,000 and the change in fair value
of these contracts represented an unrealized loss of $1,044,000.
Unrealized gains or losses resulting from changes in fair value along
with realized gains or losses on settlement of the electricity contracts
are recognized as operating costs.
The following table summarizes the Fund's electricity management
positions at February 20, 2008.
Price
Term Volumes MWh CDN$/MWh
-------------------------------------------------------------------------
January 1, 2008 - September 30, 2008 4.0 $ 63.00
January 1, 2008 - December 31, 2009 4.0 $ 74.50
-------------------------------------------------------------------------
The Fund did not enter into any new electricity contracts in the first
quarter of 2008.
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, 2007 the fair value of these contracts represented
a liability of $52,488,000 and the change in fair value of these
contracts represented an unrealized loss of $63,410,000.
The net premium cost of the crude oil instruments entered into as of
December 31, 2007 is $7,739,000.
The following table summarizes the Fund's crude oil risk management
positions at February 20, 2008:
WTI US$/bbl
-----------------------------------------------
Daily Fixed
Volumes Price
bbls/day Sold Call Purchased Put Sold Put and Swaps
-------------------------------------------------------------------------
Term
January 1, 2008
- June 30, 2008
Put 1,500 - $74.00 - -
Swap(1) 1,000 - - - $92.61
Swap(1) 500 - - - $94.30
Costless
Collar(1)(3) 400 $79.00 $70.00 - -
January 1, 2008 -
December 31, 2008
Collar 750 $77.00 $67.00 - -
3-Way option 1,000 $84.00 $66.00 $50.00 -
3-Way option 1,000 $84.00 $66.00 $52.00 -
3-Way option 1,000 $86.00 $68.00 $52.00 -
3-Way option 1,000 $87.50 $70.00 $52.00 -
3-Way option 1,500 $90.00 $70.00 $60.00 -
Put Spread(1) 1,500 - $76.50 $58.00 -
Swap 750 - - - $72.94
Swap 750 - - - $74.00
Swap 750 - - - $73.80
Swap 750 - - - $73.35
Swap(1)(3) 400 - - - $78.53
April 1, 2008 -
December 31, 2008
Put(2) 700 - $86.10 - -
July 1, 2008 -
December 31, 2008
Put Spread(1) 1,500 - $78.00 $58.00 -
Swap(1) 1,500 - - - $92.00
Swap(1)(3) 400 - - - $84.60
January 1, 2009 -
December 31, 2009
Collar(2) 850 $100.00 $85.00 - -
3-Way option(1) 1,000 $85.00 $70.00 $57.50 -
3-Way option(1) 1,000 $95.00 $79.00 $62.00 -
-------------------------------------------------------------------------
(1) Financial contracts entered into during the fourth quarter of 2007.
(2) Financial contracts entered into subsequent to December 31, 2007.
(3) Acquired through the acquisition of Focus.
Natural Gas Instruments
Enerplus has certain financial contracts outstanding as at February 20,
2008 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, 2007 the fair value of these contracts
represented an asset of $9,707,000 and the change in fair value of these
contracts represented an unrealized loss of $2,983,000.
The net premium cost of the financial natural gas instruments entered
into as of December 31, 2007 is $921,000.
The following table summarizes the Fund's natural gas risk management
positions at February 20, 2008:
AECO CDN$/Mcf
-----------------------------------------------
Daily Fixed
Volumes Price
MMcf/day Sold Call Purchased Put Sold Put and Swaps
-------------------------------------------------------------------------
Term
January 1, 2008 -
January 31, 2008
Call(1) 4.7 $ 9.13 - - -
February 1, 2008 -
February 29, 2008
Call(1) 4.7 $ 9.58 - - -
January 1, 2008 -
March 31, 2008
Collar 2.4 $ 9.95 $8.00 - -
Collar 2.4 $10.15 $8.00 - -
Collar(1)(3) 14.2 $ 9.50 $8.70 - -
3-Way option 4.7 $10.50 $8.20 $5.70 -
3-Way option 9.5 $11.61 $8.97 $6.33 -
3-Way option 4.7 $11.08 $8.55 $6.01 -
3-Way option 4.7 $ 9.50 $7.49 $5.70 -
3-Way option 9.5 $ 9.50 $7.39 $5.70 -
Swap 4.7 - - - $8.70
Swap 2.4 - - - $9.01
Swap(3) 14.2 - - - $8.46
Swap(3) 9.5 - - - $9.07
April 1, 2008 -
October 31, 2008
Collar 6.6 $ 8.44 $7.17 - -
Collar(1) 6.6 $ 7.49 $6.44 - -
Collar(1) 5.7 $ 7.39 $6.65 - -
Collar(2) 11.4 $ 8.65 $7.60 - -
Collar(2) 2.8 $ 8.65 $7.49 - -
Collar(2) 2.8 $ 8.86 $7.91 - -
3-Way option 5.7 $ 9.50 $7.54 $5.28 -
3-Way option(1) 11.8 $ 7.91 $6.75 $5.49 -
3-Way option(1) 11.8 $ 7.91 $6.75 $5.38 -
3-Way option(2) 4.7 $ 8.23 $7.18 $5.28 -
Swap 4.7 - - - $8.18
Swap(1) 7.6 - - - $6.79
Swap(1)(3) 14.2 - - - $6.70
Swap(2)(3) 14.2 - - - $7.17
Swap(2) 2.8 - - - $7.91
Swap(2) 2.8 - - - $7.87
November 1, 2008 -
March 31, 2009
Collar(2) 5.7 $ 9.50 $8.44 - -
3-Way option 5.7 $10.71 $7.91 $5.80 -
2007 - 2010
Physical (escalated
pricing) 2.0 - - - $2.59
-------------------------------------------------------------------------
(1) Financial contracts entered into during the fourth quarter of 2007.
(2) Financial contracts entered into subsequent to December 31, 2007.
(3) Acquired through the acquisition of Focus.
13. COMMITMENTS AND CONTINGENCIES
(a) Pipeline Transportation
Enerplus has contracted to transport 104 MMcf/day of natural gas on the
Nova system in the province of Alberta as well as 20 MMcf/day of natural
gas on various pipelines to the US midwest. Enerplus also has a contract
to transport a minimum of 2,480 bbls/day of crude oil from the field to
suitable marketing sales points within western Canada.
(b) Oil Sands Lease No.24
The Fund's acquisition of a working interest in the Joslyn project
included the assumption of a proportionate share of certain contingent
project debt. Effectively, this debt is comprised of principal of
$3,150,000 plus accrued interest to December 31, 2007 of $1,571,000.
Interest is accrued at the Bank of Canada prime business rate and is not
compounded. The debt is contingent on attaining certain production
hurdles with respect to development of the project. As it is still too
early to determine if these hurdles will be satisfied, no portion of the
contingent debt has been accrued for in the consolidated financial
statements.
(c) Office Lease
Enerplus has office lease commitments for both its Canadian and U.S.
operations that expire between 2011 and 2014. Annual costs of these lease
commitments include rent and operating fees.
(d) 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 long-term
debt:
Total
Committed
Minimum Annual Commitment Each Year after
----------------------------------------- 2012
($ thousands) Total 2008 2009 2010 2011 2012
-------------------------------------------------------------------------
Bank credit
facility $ 497,347 $ - $ - $497,347 $ - $ - $ -
Senior
unsecured
notes 323,408(1) - - 53,666 64,682 64,682 140,378
Pipeline
commitments 31,063 9,972 5,879 3,960 2,797 2,405 6,050
Office lease 67,875 6,907 7,559 10,304 10,782 11,082 21,241
-------------------------------------------------------------------------
Total
commit-
ments $ 919,693 $16,879 $13,438 $565,277 $78,261 $78,169 $167,669
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes the economic impact of derivative instruments directly
related to the senior unsecured notes (CCIRS and foreign exchange
swap - see Note 12).
In addition, the Fund is involved in claims and litigation arising in the
normal course of business. The resolution of these claims is uncertain
and there can be no assurance they will be resolved in favour of the
Fund; however, management believes the resolution of these matters would
not have a material adverse impact on the Fund's liquidity, consolidated
financial position or results of operations.
Not reflected in the above schedule are those term contracts for
transportation and the office lease that Enerplus assumed upon the
completion of the Focus acquisition. The Focus term transportation
contracts consist of 45 MMcf/day of natural gas in British Columbia, and
60 MMcf/day of natural gas in Saskatchewan.
14. GEOGRAPHICAL INFORMATION
As at December 31, 2007
($ 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
-------------------------------------------------------------------------
As at December 31, 2006
($ thousands) Canada U.S. Total
-------------------------------------------------------------------------
Oil and gas revenue $ 1,323,631 $ 271,693 $ 1,595,324
Capital assets 3,101,277 624,820 3,726,097
Goodwill 47,532 174,046 221,578
-------------------------------------------------------------------------
15. EVENTS SUBSEQUENT TO DECEMBER 31, 2007
On February 13, 2008, Enerplus closed the acquisition of Focus. Under the
plan of arrangement, Focus unitholders received 0.425 of an Enerplus
trust unit for each Focus trust unit. This transaction is being accounted
for as a business combination and the purchase price equation has not yet
been determined. Total estimated consideration, including deal costs and
assumed debt, is $1.7 billion, consisting of trust units issued and trust
units issuable in respect of convertible limited partnership units.
Enerplus issued a total of 30,150,000 trust units and assumed 9,087,000
Class B units of Focus Limited Partnership, each exchangeable at the
option of the holder for no additional consideration, into 0.425 of an
Enerplus trust unit.
5 YEAR DETAILED STATISTICAL REVIEW
($ thousands,
except per
unit amounts) 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
Financial
Oil and
gas
sales(1)$ 1,464,214 $ 1,569,487 $ 1,413,734 $ 989,266 $ 890,011
Cash flow
from
operating
activities 868,548 863,696 774,633 555,060 427,434
Cash distri-
butions to
unitholders 646,835 614,340 498,205 423,311 372,576
Per unit 5.04 5.04 4.47 4.20 4.29
Cash withheld
for acquis-
itions and
capital
expendi-
tures 221,713 249,356 276,428 113,248 34,145
Development
capital
spending 387,165 491,226 368,689 206,874 157,706
Acquisitions 274,244 51,313 704,028 636,326 225,293
Divestments 9,572 21,127 66,511 31,742 73,214
Total net
capital
expendi-
tures 658,327 526,387 1,010,549 813,636 312,073
Total
assets 4,303,130 4,203,804 4,130,623 3,180,748 2,661,765
Long-term
debt, net
of cash 724,975 679,650 649,825 584,991 257,701
Payout
ratio(2) 74% 71% 64% 76% 87%
-------------------------------------------------------------------------
Net debt/
cash flow
ratio 0.8x 0.8x 0.8x 1.1x 0.6x
-------------------------------------------------------------------------
Trust Unit
Trading
Information
Toronto
Stock
Exchange
trading
summary
Close $ 39.87 $ 50.68 $ 55.86 $ 43.60 $ 39.35
Volume 96,898 82,120 62,278 52,821 51,800
New York
Stock
Exchange
trading
summary
Close $ 40.05 $ 43.61 $ 47.98 $ 36.31 $ 30.44
Volume 54,192 81,677 70,454 67,570 60,624
Weighted
average
number of
units out-
standing
(basic) 127,691 121,588 109,083 99,273 86,202
Number of
units out-
standing at
December 31 129,813 123,151 117,539 104,124 94,349
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average
Benchmark
Pricing
AECO natural
gas (per
Mcf) $6.61 $6.99 $8.48 $6.79 $6.70
NYMEX natural
gas (US$ per
Mcf) 6.92 7.26 8.55 6.09 5.54
WTI crude oil
(US$ per bbl) 72.34 66.22 56.56 41.40 31.04
CDN$/US$
exchange
rate 0.93 0.88 0.83 0.77 0.72
-------------------------------------------------------------------------
($ per BOE
except
percentage
data)
-------------------------------------------------------------------------
Oil and Gas
Economics
Net royalty
rate 19% 19% 19% 21% 20%
Weighted
average
price(3) $50.48 $50.23 $52.36 $40.90 $36.94
Hedging(4) 0.45 (1.10) (4.90) (3.50) (1.81)
-------------------------------------------------------------------------
Weighted
average
price(1) 50.93 49.13 47.46 37.40 35.13
Net royalty
expense 9.49 9.36 10.21 8.40 7.51
Operating
expense(4) 9.11 8.02 7.45 7.14 6.73
-------------------------------------------------------------------------
Operating
netback 32.33 31.75 29.80 21.86 20.89
General and
admini-
strative
expense(4) 1.98 1.71 1.28 1.06 0.95
Management
fee - - - - 2.29
Interest
expense,
net of
interest
and other
income(4) 1.37 0.95 0.51 0.68 0.74
Foreign
exchange(4) 0.06 (0.02) 0.13 (0.01) 0.08
Taxes 0.77 0.70 0.31 0.24 0.26
Restoration
and abandon-
ment cash
costs 0.54 0.37 0.27 0.25 0.26
-------------------------------------------------------------------------
Cash flow
before
changes in
non-cash
working
capital $27.61 $28.04 $27.30 $19.64 $16.31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
2007(1) 2006(1) 2005(1) 2004(1) 2003(1)
-------------------------------------------------------------------------
Daily
Production
Oil Sands
(bbls/day) n/a n/a n/a n/a n/a
Crude Oil
(bbls/day) 34,506 36,134 29,315 25,550 24,597
NGLs
(bbls/day) 4,104 4,483 4,689 4,398 4,666
Natural Gas
(Mcf/day) 262,254 270,972 274,336 271,091 240,907
-------------------------------------------------------------------------
BOE per day 82,319 85,779 79,727 75,130 69,414
Drilling
Activity
(net wells) 252 361 393 367 294
Success Rate 99% 99% 99% 99% 99%
Production
Replacement 90% 82% 247% 384% 91%
Proved
Reserves(2)
Oil Sands
(Mbbls) 8,568 8,730 9,453 n/a n/a
Crude Oil
(Mbbls) 125,238 125,048 129,745 104,408 91,063
NGLs (Mbbls) 11,785 12,690 13,084 12,776 13,571
Natural Gas
(MMcf) 866,077 920,061 965,776 971,598 867,204
-------------------------------------------------------------------------
MBOE 289,937 299,812 313,245 279,117 249,168
-------------------------------------------------------------------------
Probable
Reserves(2)
Oil Sands
(Mbbls) 54,930 47,998 43,700 47,747 n/a
Crude Oil
(Mbbls) 35,504 34,421 31,567 26,783 27,807
NGLs (Mbbls) 3,827 3,777 3,539 3,292 3,742
Natural Gas
(MMcf) 336,214 344,025 342,518 295,698 284,096
-------------------------------------------------------------------------
MBOE 150,297 143,533 135,892 127,105 78,898
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves(2)
Oil Sands
(Mbbls) 63,498 56,728 53,153 47,747 n/a
Crude Oil
(Mbbls) 160,742 159,469 161,312 131,191 118,870
NGLs
(Mbbls) 15,612 16,467 16,623 16,068 17,313
Natural Gas
(MMcf) 1,202,291 1,264,086 1,308,294 1,267,296 1,151,300
-------------------------------------------------------------------------
MBOE 440,234 443,345 449,137 406,222 328,066
-------------------------------------------------------------------------
Reserve
Life
Index(3)
Without
Oil Sands:
Proved
(years) 10.0 9.8 9.6 10.1 10.6
Proved Plus
Probable
(years) 12.8 12.2 12.0 12.4 13.3
-------------------------------------------------------------------------
With Oil
Sands:
Proved
(years) 10.3 10.1 9.9 10.1 10.6
Proved Plus
Probable
(years) 14.8 14.0 13.5 14.0 13.3
-------------------------------------------------------------------------
(1) 2003 - 2007 reserve information reflects NI 51-101 reporting
methodology.
(2) Company interest reserves consist of gross reserves (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.
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, 2007, 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 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 given date, to be potentially recoverable from
known accumulations using established technology or technology under
development, but which are not currently considered to be commercially
recoverable due to one or more contingencies. Contingencies may include
factors such as economic, legal, environmental, political and regulatory
matters or a lack of markets. It is also appropriate to classify as
contingent resources the estimated discovered recoverable quantities
associated with a project in the early evaluation stage."
There is no certainty that Enerplus will produce any portion of the
volumes currently classified as "contingent resources". The primary
contingencies which currently prevent the classification of Enerplus'
disclosed contingent resources associated with the Kirby oil sands
project as reserves consist of current uncertainties around the specific
scope and timing of the project development, proposed reliance on
technologies that have not yet been demonstrated to be commercially
applicable in oil sands applications, the uncertainty regarding marketing
plans for production from the subject areas and improved estimation of
project costs. The primary contingencies which currently prevent the
classification of Enerplus' disclosed contingent resources associated
with the Joslyn Project as "reserves" consist of current uncertainties
around the specific scope of the Joslyn Project (and in particular the
finalization of an overall lease development plan), timing of the
proposed development as it relates to proposed changes in the lease
development plan, proposed reliance on technologies that have not yet
been demonstrated to be commercially applicable in oil sands
applications, the uncertainty regarding marketing plans for production
from the subject areas and improved estimation of project costs. Based on
current information and market conditions, Enerplus believes that
development of the Kirby and Joslyn projects will proceed as described in
this news release, although readers should consider the described
uncertainties regarding SAGD expansion and the development of the mining
portion of the Joslyn Project, as described herein. However, there
are a number of inherent risks and contingencies associated with the
development of the Kirby and Joslyn projects, including commodity price
fluctuations, project costs, receipt of regulatory approvals and those
other risks and contingencies described above and under "Risk Factors and
Risk Management" in the Management's Discussion an Analysis section of
this news release and under "Risk Factors" in the Fund's Annual
Information Form (and corresponding Form 40-F) dated March 12, 2007, as
well as the risk factors to be contained in the Fund's Annual Information
Form (and corresponding Form 40-F) to be filed in mid-March 2008.
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") 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 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. Moreover, Enerplus has
determined and disclosed estimated future net revenue from its and Focus'
reserves using forecast prices and costs, whereas the SEC generally
requires that prices and costs be held constant at levels in effect at
the date of the reserve report. As a consequence of the foregoing,
Enerplus' and Focus' reserve estimates and production volumes in this
news release may not be comparable to those made by companies utilizing
United States reporting and disclosure standards. 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",
"objective", "ongoing", "may", "will", "project", "should", "believe",
"plans", "intends", "strategy" and similar expressions are intended to
identify forward-looking information or statements. In particular, but
without limiting the foregoing, this news release contains forward-
looking information and statements pertaining to the following: the
volumes and estimated value of the Fund's oil and gas reserves; the life
of the Fund's reserves; the volume and product mix of the Fund's oil and
gas production; future oil and natural gas prices and the Fund's
commodity risk management programs; the amount of future asset retirement
obligations; future liquidity and financial capacity; future results from
operations and operating metrics; future costs, expenses and royalty
rates; future interest costs; future development, exploration,
acquisition and development activities (including drilling plans) and
related capital expenditures, including with respect to both our
conventional and oil sands activities and in particular the development
of the Kirby and Joslyn leases; future acquisitions and dispositions; the
reinstatement of production from the Giltedge property and the
availability of business interruption insurance to mitigate the costs of
the Giltedge fire; the making and timing of future regulatory filings and
applications; the value of the Fund's equity investments; future tax
treatment of income trusts and future taxes payable by the Fund; the
Fund's tax pools; the impact of the Focus acquisition on the Fund; the
amount, timing and tax treatment of cash distributions to unitholders;
and future payout ratios.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions
of the Fund including, without limitation: that the Fund will continue to
conduct its operations in a manner consistent with past operations; the
general continuance of current industry conditions; the continuance of
existing (and in certain circumstances, the implementation of proposed)
tax, royalty and regulatory regimes; the accuracy of the estimates of the
Fund's reserve and resource volumes; certain commodity price and other
cost assumptions; the continued availability of adequate debt and equity
financing and cash flow to fund its plans expenditures; and accurate
assessment of the value of Focus' assets and the extent of its
liabilities The Fund believes the material factors, expectations and
assumptions reflected in the forward-looking information and statements
are reasonable but no assurance can be given that these factors,
expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown
risks, uncertainties and other factors that may cause actual results or
events to differ materially from those anticipated in such forward-
looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of the Fund's
products; unanticipated operating results or production declines; changes
in tax or environmental laws, royalty rates or other regulatory matters;
changes in development plans the Fund or by third party operators of the
Fund's properties, including the operator of the Joslyn oil sands
project; increased debt levels or debt service requirements; inaccurate
estimation of the Fund's and Focus' oil and gas reserve and resource
volumes; limited, unfavourable or a lack of access to capital markets;
increased costs; a lack of adequate insurance coverage; declines in the
value of the Fund's equity investments; the impact of competitors; and
certain other risks detailed from time to time in the Fund's public
disclosure documents (including, without limitation, those risks
identified in this news release and in the Fund's annual information
form).
The forward-looking information and statements contained in this news
release speak only as of the date of this news release, and none of the
Fund or its subsidiaries assumes any obligation to publicly update or
revise them to reflect new events or circumstances, except as may be
required pursuant to applicable laws.
Gordon J. Kerr
President & Chief Executive Officer
%CIK: 0001126874
For further information: Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com
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