TSX: ERF.un
NYSE: ERF
CALGARY, Feb. 22 /CNW/ - Enerplus is pleased to announce our 2006 year-
end results with highlights summarized as follows:
- Annual average production exceeded our guidance and grew to
85,779 BOE/day primarily as a result of our internal capital program.
Our exit rate volumes were in line with expectations at
87,500 BOE/day.
- We executed the largest development capital program in our history
spending $491.2 million, essentially in line with our target of
$485.0 million.
- Cash flow increased 11% to $863.7 million from $774.6 million in the
previous year.
- Net income increased 26% to $544.8 million. On a trust unit basis,
this resulted in an increase of 13% to $4.48 per unit reflecting the
increase in units outstanding.
- Cash distributions increased in 2006 by 23% to $614.3 million or
11% per unit compared to 2005.
- Cash distributions to unitholders were maintained at $0.42 per unit
throughout 2006 resulting in total distributions of $5.04 per unit.
- Our payout ratio averaged 71%.
- Our Reserve Life Index ("RLI") continued to be one of the longest in
the sector at 14.0 years on a proved plus probable basis and
10.1 years on a proved basis, including both conventional and non-
conventional reserves.
- Proved plus probable reserves decreased 1% to 443.3 MMBOE and proved
reserves decreased 4% to 299.8 MMBOE.
- We replaced 82% of our production without the benefit of any
significant acquisitions.
- Successful drilling efforts resulted in 361 net wells drilled with a
success rate of over 99%.
- We acquired 3.7 MMBOE of proved plus probable reserves at an
attractive cost of $14.04/BOE.
- Our finding, development and acquisition costs ("FD&A") for the year
were $23.19/BOE on a proved plus probable basis and $28.82/BOE on a
proved basis including future development capital ("FDC"). Excluding
FDC our proved plus probable FD&A costs were $20.45/BOE and
$29.13/BOE on a proved basis. Our three-year proved plus probable
FD&A costs were $14.90/BOE ($11.51/BOE excluding FDC).
- Operating costs averaged $8.02/BOE in 2006.
- G&A costs were $1.91/BOE, higher than our guidance of $1.85/BOE.
- We continue to maintain a conservative balance sheet as evidenced by
a net debt to trailing 12 month cash flow ratio of 0.8x.
- Our future opportunity set increased significantly year-over-year to
over $2 billion in attractive conventional capital projects
(excluding oil sands).
SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS
All amounts are stated in Canadian dollars unless otherwise specified. In
accordance with Canadian practice, production volumes, reserve volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. All reserve figures are calculated based
upon company interest reserves using forecast prices and costs. See "Reserve
Reporting and Determination Methodologies" for additional information. Where
applicable, natural gas has been converted to barrels of oil equivalent
("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead. Use of BOE in isolation may be
misleading. Certain prior year amounts have been restated to reflect current
year presentation. Readers are also urged to review the Management's
Discussion & Analysis (MD&A), Audited Financial Statements and forthcoming
Annual Information Form for more fulsome disclosure on our operations. These
reports can be found on our website at www.enerplus.com, our SEDAR profile at
www.sedar.com and as part of our Form 40-F that will be filed with the SEC and
available on www.sec.gov.
FINANCIAL HIGHLIGHTS
For the years ended December 31, 2006 2005
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Financial (000's)
Net Income $ 544,782 $ 432,041
Cash Flow from Operating Activities 863,696 774,633
Cash Distributions to Unitholders(1) 614,340 498,205
Cash Withheld for Acquisitions and
Capital Expenditures 249,356 276,428
Debt Outstanding (net of cash) 679,650 649,825
Development Capital Spending 491,226 368,689
Acquisitions 51,313 704,028
Divestments 21,127 66,511
Financial per Unit(2)
Net Income $ 4.48 $ 3.96
Cash Flow from Operating Activities 7.10 7.10
Cash Distributions to Unitholders(1) 5.05 4.57
Cash Withheld for Acquisitions and
Capital Expenditures 2.05 2.53
Payout Ratio(3) 71% 64%
Selected Financial Results per BOE(4)
Oil & Gas Sales(5) $ 50.23 $ 52.36
Royalties (9.36) (10.21)
Financial Contracts (1.10) (4.90)
Operating Costs (8.02) (7.45)
General and Administrative (1.71) (1.28)
Interest and Foreign Exchange (0.93) (0.64)
Taxes (0.70) (0.31)
Restoration and Abandonment (0.37) (0.27)
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Cash Flow from Operating Activities before
changes in non-cash working capital $ 28.04 $ 27.30
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Weighted Average Number of Trust Units
Outstanding (thousands) 121,588 109,083
Debt/Trailing 12 Month Cash Flow Ratio 0.8x 0.8x
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OPERATING HIGHLIGHTS
For the years ended December 31, 2006 2005
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Average Daily Production
Natural gas (Mcf/day) 270,972 274,336
Crude oil (bbls/day) 36,134 29,315
NGLs (bbls/day) 4,483 4,689
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Total (BOE/day) (6:1) 85,779 79,727
% Natural gas 53% 57%
Average Selling Price(5)
Natural gas (per Mcf) $ 6.81 $ 8.41
Crude oil (per bbl) 61.80 55.93
NGLs (per bbl) 50.90 47.33
US$ exchange rate 0.88 0.83
Net Wells drilled 361 393
Success Rate 99% 99%
Proved Reserves (MMBOE)(6) 299.8 313.2
Probable Reserves (MMBOE)(6) 143.5 135.9
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Total Proved plus Probable Reserves (MMBOE)(6) 443.3 449.1
FD&A Cost per BOE, excluding Future
Development Capital(7) $ 20.45 $ 13.98
FD&A Cost per BOE, including Future
Development Capital(7) $ 23.19 $ 17.18
Recycle Ratio(7) 1.4x 1.7x
Proved Reserve Life Index (years) 10.1 9.9
Proved plus Probable Reserve Life Index (years) 14.0 13.5
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In some circumstances, presentation has been changed to minimize the
use of non-GAAP measures.
(1) Calculated based on distributions paid or payable. Cash
distributions to unitholders per unit will not correspond to the
actual monthly distributions of $5.04 as a result of using the
annual weighted average trust units outstanding.
(2) Based on annual weighted average trust units outstanding.
(3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
from Operating Activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(6) Reserve figures are calculated based upon company interest reserves
using forecast prices and costs.
(7) Based upon proved plus probable company interest reserves.
TSX - ERF.un NYSE - ERF
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Trust Unit Trading Information ($CDN) ($US)
High 66.00 59.45
Low 43.86 38.50
Close 50.68 43.61
Volume (000's) 82,120 81,677
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OPERATIONS REVIEW
2006 Production
In 2006, we were able to grow the production from our assets as a result
of strong base performance and the successful execution of the largest
development capital program in our history. Daily production averaged
85,800 BOE/day, a new high for Enerplus and slightly ahead of our guidance of
85,500 BOE/day. Strong base production performance from our U.S. and Canadian
operations and production additions from our capital program resulted in an
increase in our year-over-year exit rate from 85,000 in 2005 to 87,500 BOE/day
in 2006, demonstrating our ability to grow production through internal
development without the benefit of any significant acquisition activity.
Approximately 50% of our average daily production volumes are attributed
to resource plays, with the Sleeping Giant project in Montana now our single
largest producing property. We continue to operate approximately 64% of our
daily production volumes.
We expect 2007 average production to remain essentially flat at
85,000 BOE/day with a reduced capital program of $410 million. We expect to
exit 2007 with production of 86,000 BOE/day as a result of the timing of our
capital expenditures which are back-end loaded this coming year. These targets
are exclusive of any acquisition or divestment activity that may occur as a
normal part of our business during the course of 2007.
2006 Capital Spending
Development capital spending of $491 million during 2006 was in line with
our guidance of $485 million despite inflationary pressures. Through this
spending, we added approximately 21,400 BOE/day of initial production at an
attractive on-stream cost of $23,000/BOE/day which is significantly better
than our on-stream cost in 2005 and was slightly better than forecast. We
achieved these results due to the strength of our opportunity set and our
ability to allocate capital to our most attractive projects. Our capital high-
grading in 2006 included increasing our Bakken oil spending and deferring some
of our shallow gas and waterflood projects.
Key attributes of our 2006 capital program include:
- We achieved better than expected capital efficiencies despite
inflationary pressures. Inflation averaged approximately 15%,
meaningfully higher than anticipated. As a result we chose to defer
approximately 10% of our planned activity to manage our capital
spending while maintaining attractive capital efficiencies.
- Approximately 57% of our capital was directed to oil development
while 43% was directed to natural gas opportunities reflecting the
strength of the oil markets and the attractiveness of our Bakken oil
development in the U.S.
- 64% of our capital spending was focused on resource plays which are
marked by relatively predictable decline rates with low geologic
risk.
- We also invested approximately $89 million (18% of our total capital)
in longer-term opportunities in oil sands, land, seismic and higher
risk drilling activities which did not add production or cash flow in
the current year but positions us to add significant production and
reserves over the next few years.
- Operated capital spending accounted for 73% of the total which is
higher than last year due to higher spending on our U.S. Bakken oil
projects.
2006 Initial 2006 Cost of 2007
Production 2006 Production Estimated
Additions(*) Capital Additions Capital
Play type (BOE/day) ($millions) ($/BOE/day) ($millions)
---------------------------------------------- --------------------------
Shallow Gas & CBM 3,200 $ 94 $ 29,400 $ 43
Waterflood 1,600 66 41,250 65
Bakken Oil 7,800 117 15,000 70
Oil Sands (SAGD/mine) - 39 n/a 40
Other Conventional
Oil & Gas 8,800 175 19,900 192
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Total 21,400 $ 491 $ 23,000 $ 410
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(*) 2006 production was not recorded for Joslyn as the operation has not
reached commercial production levels. Initial production based on
first month production rates.
2007 Capital Spending
We expect to reduce capital spending to $410 million for 2007 based on
our current commodity price outlook. Should commodity prices change and/or if
we experience better success, our capital budget could increase or decrease.
Our spending will continue to be focused on resource play development. We also
expect to spend $84 million (20%) on longer-term opportunities in oil sands,
land, seismic and higher risk drilling.
The most significant reductions in our program will occur in our shallow
gas/CBM program and U.S. Bakken spending. The shallow gas/CBM program was
deferred given potential risks we see with near-term gas prices although with
continued gas price strength, these programs could be increased. Currently, we
plan to continue with a base level program concentrating on our most
profitable opportunities in this area as it is a core activity for us and
represents a significant percentage of our future opportunity. The reduction
in our U.S. Bakken spending reflects the completion of a majority of our
drilling program of two wells per section. We are currently testing the
benefits of a third well per section, exploring other zones in the area as
well as extending the Bakken play into North Dakota. With success in these
areas, we could increase our U.S. spending.
2006 Drilling Activity
In 2006, we participated in the drilling of 360.9 net wells,
significantly less than our original guidance of 550 net wells, while
maintaining our success rate of 99%. During the course of the year, we elected
to defer a portion of our drilling program as a result of industry
inflationary pressures and lower natural gas prices. We deferred the drilling
of approximately 140 net shallow gas and CBM wells and approximately 30 net
waterflood wells. Funds from these programs offset the inflationary pressures
on the remainder of the drilling program and ensured the execution of other
more profitable drilling programs such as those in our Bakken oil and other
conventional drilling programs. In total we drilled 275.1 net natural gas
wells and 85.8 net crude oil wells in 2006.
Bakken Oil Development
As our single largest producing property, the Sleeping Giant project
represents approximately 13% of our production and 9% of our proved plus
probable reserves. During 2006 we invested $117 million to drill 41 gross
wells (26.5 net) to add 7,800 BOE/day of incremental production at an
attractive on-stream cost of $15,000/BOE/day. As part of our 2006 activities,
we initiated an increased density drilling program by drilling 6 gross wells
(4 net) at 3 wells per section. Based upon results to date, 10 additional
increased density wells have been planned for 2007. Continued success may lead
to additional increased density wells.
To date, we have drilled 56 development wells with a 100% success rate
and executed a successful re-fracture program resulting in production growth
from 8,700 BOE/day upon acquisition to over 11,500 BOE/day at year-end 2006.
These results are far better than we anticipated at the time of the
acquisitions.
In 2007, we plan to invest $70 million to drill 26 gross (17 net) oil
wells and re-fracture stimulate 12 gross (8 net) wells. This year's
development activity will complete the second well per section program in the
primary Bakken field area and focus on identifying and proving up new
opportunities in the general area. We own 120,000 net acres of undeveloped
land in Montana and North Dakota, portions of which we plan to test in 2007.
The primary target on the undeveloped lands is the Bakken formation, however
the lands are also prospective for the Ratcliffe, Mission Canyon, Birdbear,
Duperow and Red River geological formations.
Oil Sands
Enerplus and Total E&P Canada ("Total"), the operator of the Joslyn
project, are continuing to review the lease development plans given the
flexibility which exists for both SAGD and mining operations. Although
meaningful progress was made in 2006, the complexities of determining the
optimal development plan have extended the expected timeline. An extensive
lease development plan is anticipated in 2007 and is not expected to impact
current SAGD operations or the startup timing of the initial phase of the
mine. The development plan will also provide an update of estimates relating
to the future development capital associated with the mine development.
A summary of the expected production and timing for the various projects
on the Joslyn lease are included in the table below. Not all dates are
available given the uncertainty around the final full lease development plan.
Joslyn Project Development
Project Net Future
Production Production Development Full
Throughput(1) Throughput Capital(2) Start Production
(bbls/day) (bbls/day) ($millions) Up(3) (4)
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Phase I
& II SAGD 10,000 1,500 31 2006 2008
Phase III
SAGD 15,000 2,250 284 TBD TBD
North Mine 100,000 15,000 TBD 2013 2014
South Mine 100,000 15,000 TBD 2016 2017
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(1) All production estimates are those of the Operator.
(2) Future development capital for SAGD based on independent third party
reserve report dated December 31, 2006. Future development capital
for mining is currently under full review by the Operator as the
project definition advances and new investment estimates are
anticipated toward the end of 2007.
(3) Start up for SAGD refers to first steam. Start up for mining refers
to initial extraction.
(4) Full production refers to full project production throughput.
In addition to our Joslyn lease, Enerplus has assembled an internal oil
sands team with significant experience in SAGD development. We are actively
pursuing an operated SAGD project in which to deploy this team. Through our
joint venture with Laricina Energy Ltd., we have invested approximately
$3 million to acquire working interest in several land positions with SAGD
potential.
Reserves
Independent reserves evaluation of the Joslyn lease indicates total
proved reserves of 8.7 million BOE, and total proved plus probable reserves of
56.7 million BOE net to Enerplus in the SAGD area for Phases I - III.
Independent contingent resource estimates for the North Mine indicate a "best
estimate" of approximately 140 million BOE net to Enerplus, or over
900 million BOE gross. This is consistent with numbers filed in the North Mine
regulatory application by the Operator. In addition, third party assessments
estimate significant additional mining resources outside the North Mine area.
Please see our 2006 Annual Information Form for further information on the
resource disclosure including risks and uncertainties associated with our
resource estimates associated with the mining potential contained within the
Joslyn lease.
If current development plans are modified and a decision is made to mine
some of the currently identified SAGD areas, existing SAGD Phase III probable
reserve bookings could be impacted. Although mining typically provides about
twice the recovery of the original bitumen in place versus SAGD projects,
there could be timing differences between reserves bookings associated with
the existing SAGD Phase III development plans versus possible expansion of
mine development plans. Although timing of the expected booking may extend
through 2007, depending on the progress made over the next year, we may be in
a position to book probable reserves associated with the North Mine at year-
end.
2006 Capital Investment
In regard to the Joslyn lease, spending in 2006 reached $36 million to
advance both the SAGD ($33 million) and the mining options ($3 million). In
addition, $3 million was spent to acquire lands in conjunction with Laricina,
resulting in a total oil sands investment of $39 million in 2006. This capital
included the drilling of close to 280 gross additional delineation wells over
both SAGD and mining areas and the 4.5 gross sections of land acquired in late
2005. Capital investment to progress the SAGD development included the
completion of central plant facilities, the commissioning and start-up of the
water treatment system, the initiation of steam injection into SAGD well
pairs, and the completion of a 40 kilometre pipeline from Joslyn to the
Athabasca Terminal. Total continues to expect Phase II to reach peak
production of 10,000 bbls/day gross (1,500 bbls/day net to Enerplus) in 2008,
however due to reduced operating pressures, this may require additional wells
and capital in 2007 and 2008. We currently do not have any production volumes
associated with this project included in our 2007 production estimates as
commercial volumes are not expected until 2008. Investment on the mining side
supported the application for regulatory approval of the North Mine,
representing 100,000 bbls/day of potential gross bitumen production
(15,000 bbls/day net to Enerplus).
2007 Oil Sands Capital Spending Outlook
Total capital spending on oil sands is expected to increase to
approximately $40 million including:
- Joslyn SAGD development of $21 million, which includes the continued
start-up and ramp-up of Phase II well pairs, and the possible
addition of 10 new well pairs late in the year. The regulatory
approval process continues for SAGD Phase III with approvals
expected in the first quarter of 2007 assuming no change in the base
development plan. Currently Phase III represents a 15,000 bbl/day
expansion of the existing facilities to a potential of
25,000 bbls/day of gross SAGD production (3,750 bbls/day net
to Enerplus).
- Mining investment of $13 million to advance the regulatory approval
process and engineering, and to further delineate the mine.
- Investment of $6 million to further delineate the new Laricina lands
in the first quarter of 2007.
These investments will enhance the value of our portfolio of oil sands
assets. Our capital spending may increase further should we identify and
execute on other attractive oil sands opportunities.
Crude Oil Waterfloods
Crude oil waterfloods are a significant part of the Enerplus portfolio
representing 20% of our production and 24% of our proved plus probable
reserves. During 2006 we invested approximately $66 million on waterflood
development including drilling 40 gross (29.7 net) wells. Pembina and Joarcam
were our most active waterflood development areas in 2006. During 2007, we
expect to maintain our investment activity in this area at approximately $65
million. This will include drilling 76 gross wells (41 net). Key development
areas include Pembina, Joarcam, Virden as well as the Medicine Hat Glauconitic
"C" East Unit. Although capital efficiency measures based on initial
waterflood production may be higher, the low decline rates and long life
nature of these projects provide attractive full-cycle returns.
Shallow Natural Gas and Coalbed Methane
Shallow gas and coalbed methane represent 22% of our reserves, with an
attractive reserve life index of 17.2 years. Production volumes from these two
resource plays represent 16% of our total production, with shallow gas
representing the majority in this category. During 2006, we invested
$94 million on shallow gas/CBM development, drilling 430 gross (249.5 net)
wells and adding 3,200 BOE/day of incremental production at an average on-
stream cost of $29,400/BOE/day. Key areas of shallow gas development include
Hanna, Bantry and Shackleton, while CBM development efforts were focused at
Bashaw, Joffre and Trochu. Currently, our inventory of shallow gas/CBM future
drilling locations represents approximately six years of development at
historical investment levels. However, for 2007 we have chosen to high grade
our development program to $43 million, focusing on our most profitable
programs given potential risks in near-term gas prices. Should gas price
strength continue, the size of this program could increase.
Other Conventional Oil and Gas
We also have a diversified portfolio of other conventional opportunities
in western Canada. These properties are diversified by commodity (67% natural
gas, 33% liquids) and are mixed between operated (46%) and non-operated (54%).
Conventional oil and gas represents approximately 51% of our production and
32% of our proved plus probable reserves. In 2006, we invested approximately
$175 million in other conventional oil and gas development activities
including the drilling of 275 gross wells (53.5 net). In 2007, we plan to
invest $192 million in development activities at other conventional oil and
gas properties including drilling approximately 200 gross wells (70 net).
Actual capital may vary depending on the activity levels from industry
partners on non-operated properties in which we participate.
FUTURE POTENTIAL
Enerplus has focused on building a large, diversified portfolio of
economic, conventional and non-conventional capital projects that will support
our operations in the years ahead through the addition of production and
reserves. We currently have a conventional opportunity set of approximately $2
billion of capital projects representing approximately 2,500 net wells. The
non-conventional opportunities are estimated at approximately $1 billion of
capital projects associated with oil sands excluding any investments relating
to an upgrader solution. This represents about five years of conventional
future development potential at current capital spending levels assuming no
new acquisitions, land deals, or new opportunity identification on our
existing properties.
Our opportunity set includes significant potential across our entire
asset base and capital projects which are both technically and economically
viable at todayès commodity prices:
- Weighted 60% to natural gas and 40% to oil
- Resource plays comprise over 50% of the total
- Includes approximately $500 million of opportunity included in our
third party reserve engineering reports
- $1 billion of ùbaseâ projects which we project to have a greater
than 80% chance of technical success
- Approximately $500 million of risk-adjusted opportunities that have
less than an 80% chance of success
We have excluded those projects from our opportunity set that are early
stage ideas with greater technical/economic uncertainty.
ACQUISITIONS & DIVESTMENTS
2006 was a year our disciplined approach to acquisitions resulted in
limited transactions despite actively pursuing numerous opportunities. As a
result, we preserved our balance sheet and avoided the high cost acquisitions
within Canada driven by an aggressive energy trust sector. Within the U.S. we
tempered our activities as we built our U.S. operating group and executed an
expanded internal development program which achieved strong internal
production and reserve gains.
Given recent weakness in commodity markets and capital market
uncertainty, we see an increasing number of attractive acquisitions at
potentially more favourable pricing. This increased opportunity set comes at a
time when our equity value is relatively stronger than the general trust
sector, our balance sheet is strong and our U.S. execution capability is now
in place.
During the year, through a series of small transactions, we increased our
interests in core areas, notably at Sleeping Giant in Montana and at Gleneath
in Saskatchewan. We acquired minor non-operated interests in a large block of
land at Copton within the greater Deep Basin which has significant upside from
relatively low risk drilling for deep, sweet natural gas. These properties
were acquired at an attractive cost per BOE of $14 and a higher cost on a
flowing barrel metric given the significant upside we see within the
properties.
In early 2006, we sold a 1% working interest in our Joslyn oil sands
lease in exchange for an equity stake in Laricina Energy Ltd. a private oil
sands focused company. Given the low selling price of these reserves and the
modest number of acquired reserves for the year, the resulting net acquisition
metrics appear unattractive. However, the chart below offers more comparable
per BOE and per flowing BOE metrics by excluding the Joslyn sale.
2006 Acquisition & Divestment Summary
Proved Cost of
plus Proved plus
Cost/ Probable Probable
Proceeds(*) Reserves Production Reserves Cost per
($ millions) (MBOE) (BOE/day) ($/BOE) Daily BOE
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Acquired $ 51.3 3,654 655 $ 14.04 $ 78,321
Divested(xx) $ (1.4) (63) (26) $ (22.22) $ 53,846
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Net excluding
Joslyn $ 49.9 3,591 629 $ 13.90 $ 79,332
Joslyn
Divestment $ (19.7) (3,329) n/a $ (5.91) n/a
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Net including
Joslyn $ 30.2 262 629 $ 115.27 $ 48,013
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(*) After adjustments for working capital and excluding future
development capital.
(xx) Excludes sale of reserves of Joslyn for equity stake in Laricina.
Acquisition of Gross Overriding Royalty Interests
On January 31, 2007, Enerplus acquired various gross overriding royalty
("GORR") interests in the state of Wyoming for total consideration of
US$52 million (CDN$60 million). This acquisition represents a modest addition
to our assets in the United States and establishes a new area with significant
gas development potential.
The assets produce natural gas from the EnCana Corporation operated Jonah
gas field in Wyoming, which is one of the largest gas fields in the U.S. with
an estimated original gas in place of 14 trillion cubic feet. We have acquired
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. This represents a GORR of about 0.5% on about 650 producing gas
wells in the Jonah field. The proved plus probable reserve life index of the
assets is 15.9 years, calculated using independent third party engineering
reserve estimates and management's estimate of current production. We believe
the field has a significant number of additional infill drilling locations
that will provide growth potential for the future. Enerplus will not be
required to expend any future development capital on the assets. We expect the
net operating cash flow per BOE, net of all applicable U.S. taxes, to be
significantly higher than that of our existing production due to the nature of
the GORR which is not subject to deductions for operating costs and royalties.
RESERVES
Attractive reserve additions from our U.S. properties, oil sands and
conventional Canadian operations were partially offset by unexpected capital
inflation and negative revisions (mainly in the probable category) in our
Canadian conventional areas. Enerplus achieved overall proved plus probable
finding, development and acquisition costs including future development
capital of $23.19/BOE in 2006 ($20.45/BOE excluding FDC) and a three-year
average FD&A cost of $14.90/BOE ($11.51/BOE excluding FDC).
Other key points in our reserve assessment include:
- Reserve life index increased to 14 years in line with our historical
performance.
- We replaced 82% of production without the benefit of any significant
acquisitions. Over the last five years, we have averaged almost 200%
reserve replacement inclusive of acquisition and divestment activity.
- Our U.S. operations added 7.3 million BOE at a one-year proved plus
probable F&D cost of $13.78/BOE including FDC reflecting a 20%
increase in reserves at December 31, 2005 as a result of our strong
operational and development performance in the U.S.
- 6.9 million BOE were added to our oil sands reserves at a one-year
proved plus probable F&D cost of $10.54/BOE ($5.67/BOE excluding
FDC) reflecting another successful year of core hole drilling and
analysis.
- No changes were made to the allocation of reserves associated with
the SAGD portion of the Joslyn lease versus the mining portion.
Total and Enerplus are in discussions on a potential change to the
lease development plan which could impact the reserve allocation
between the mine and SAGD portions of the lease and the timing of
reserve bookings.
- There are no proved or probable mining reserves included in our year-
end reserve summary. The current North Mine project continues to
progress and there is the potential to book probable reserves
associated with this project at year-end 2007.
- Canadian conventional development added over 19 million BOE,
excluding negative revisions, at a one-year proved plus probable F&D
cost of $20.63/BOE ($17.17/BOE without FDC). This reflects the
strong conventional drilling results we achieved in Canada which
were partially offset by the negative revisions tied to existing
Canadian operations.
- Proved and probable negative revisions of 7.5 million BOE were
predominantly from the "probable" reserves category which has less
certainty than "proved" reserves. These revisions represent less
than 2% of our total year-end reserves and were mainly due to
performance and economic factors in a few of our older Canadian
conventional properties.
- No changes to the after-tax calculations have been included for our
Canadian assets in connection with the proposed changes on
taxability for trusts in the Canadian market. Should the proposed
legislation be enacted, Enerplus would provide an updated analysis
which would include the effect of any enacted tax legislation.
- Acquisition and divestment activity resulted in no significant
change to our reserves. Minor acquisitions were offset by the sale
of a 1% working interest in our Joslyn lease.
Reserve Reporting and Determination Methodologies
All reports, including our U.S. reserves, were evaluated using Canadian
NI 51-101 rules. Three external, independent third party engineering firms
were used to evaluate and review our reserves this year. Sproule Associates
Limited ("Sproule"), our historical independent engineering evaluators,
evaluated our Canadian conventional reserves. GLJ Petroleum Consultants Ltd.
("GLJ") evaluated the Joslyn SAGD bitumen reserves as they have previously
performed such evaluations for the operator of the Joslyn project. DeGolyer
and MacNaughton ("D&M") of Dallas, Texas, evaluated the reserves attributed to
our assets in the United States. Sproule evaluated 90% 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 internally evaluated
by Enerplus. Both GLJ and D&M evaluated 100% of the reserves in their
respective areas. Both GLJ and D&M utilized Sproule's forecast price and cost
assumptions as of December 31, 2006 in their evaluations to maintain
consistency among our reserve reporting.
The following tables report company interest reserves that include gross
working interest reserves plus owned royalty interest reserves using forecast
prices. "Company interest" reserves are not a measure defined in NI 51-101
adopted by the Canadian securities regulators 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 reserves
statement, which includes complete disclosure of our oil and gas reserves and
other oil and gas information in accordance with NI 51-101 is 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 is part of our Form 40-F that will be filed with the
SEC and available on www.sec.gov.
Probable reserves are evaluated and categorized by our third party
engineering firms or our own internal evaluators under the review of the third
party engineering firm. Care should be used when comparing U.S. and Canadian
style reserves and production reporting between companies. Under U.S.
reporting, reserve estimates are calculated using prices and costs held
constant at amounts in effect at the date of the reserve report and typically
only include net proved reserves. Additionally, proved reserve standards in
the U.S. may not be comparable to the Canadian standards. Generally, Canadian
standards for reporting proved reserves may be more conservative than U.S.
standards.
All evaluations of future net production revenues set forth in the tables
are stated after the provision for income taxes and exclude abandonment costs
on wells and facilities where reserves are not assigned or associated general
and administrative costs. These schedules have been prepared on the basis that
Enerplus will not pay cash income taxes in Canada in the future due to
Enerplus' current structure as an income trust and Canadian tax laws currently
in effect. Under our current mutual fund structure and existing tax
legislation in Canada, annual taxable income is transferred from our operating
entities to the Fund through interest, royalty and other payments. We, in
turn, make distributions to our unitholders and therefore currently do not
incur any Canadian income tax. As a result, after tax future net revenues from
Canadian oil and gas reserves are equal to before tax future net revenues from
Canadian oil and gas reserves. Enerplus' U.S. operations are subject to cash
income taxes, and as a result Enerplus' U.S. reserves are shown net of the
effect of such taxes that we estimate would be payable after taking into
account inter-company debt in our structure. The Canadian federal government
has announced a proposal designed to effectively tax income trusts such as
Enerplus at the same level as Canadian corporations, effective for the 2011
tax year. Such proposal has not yet been approved or put in force and it is
uncertain as what form, if any, changes in Canadian income tax laws will take
as a result of such proposal. Any changes in Canadian income tax laws that may
result from such proposal could adversely affect the estimated future net
revenues associated with Enerplus' oil and gas reserves. For additional
information, investors should refer to disclosure that will be contained in
Enerplus' Annual Information Form.
The net estimated present value of all future net revenues at
December 31, 2006 was based upon crude oil and natural gas pricing assumptions
prepared by Sproule as of December 31, 2006. These prices were applied to the
reserves evaluated by Sproule, GLJ and D&M. The base reference prices and
exchange rates used by Sproule are detailed below:
Sproule December 31, 2006 - Forecast Price Assumptions
Differ-
ential
Between
Hardisty
Heavy Natural
Hardisty And Henry Gas 30
Light Heavy 12 Bitumen(2) Hub day spot
WTI crude(1) degree (Oil Price at AECO Exchange
crude oil Edmonton API Sands) US$/ CDN$/ Rate
US$/bbl CDN$/bbl CDN$/bbl CDN$/bbl MMbtu MMbtu CDN$/US$
-------------------------------------------------------------------------
2007 $ 65.73 $ 74.10 $ 42.98 $ 8.88 $ 7.85 $ 7.72 $ 0.87
2008 68.82 77.62 45.02 11.35 8.39 8.59 0.87
2009 62.42 70.25 40.74 12.83 7.65 7.74 0.87
2010 58.37 65.56 38.03 12.19 7.48 7.55 0.87
2011 55.20 61.90 35.90 11.66 7.63 7.72 0.87
Thereafter 2.0% 2.0% 2.0% (xx) (xx) 2.0% 0.87
-------------------------------------------------------------------------
(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 2011.
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.
2006 Reserve Summary - Company Interest Volumes (Forecast Prices)
OIL AND GAS RESERVES
-------------------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
(Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved developed
producing
Canada 66,458 28,932 2,479 97,869
United States 21,933 - - 21,933
-------------------------------------------------------------------------
Total 88,391 28,932 2,479 119,802
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved developed
non-producing
Canada 537 - - 537
United States 871 - - 871
-------------------------------------------------------------------------
Total 1,408 - - 1,408
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved undeveloped
Canada 3,509 2,221 6,251 11,981
United States 587 - - 587
-------------------------------------------------------------------------
Total 4,096 2,221 6,251 12,568
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved
Canada 70,504 31,153 8,730 110,387
United States 23,391 - - 23,391
-------------------------------------------------------------------------
Total 93,895 31,153 8,730 133,778
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable
Canada 16,872 8,912 47,998 73,782
United States 8,637 - - 8,637
-------------------------------------------------------------------------
Total 25,509 8,912 47,998 82,419
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved plus Probable
Canada 87,376 40,065 56,728 184,169
United States 32,028 - - 32,028
-------------------------------------------------------------------------
Total 119,404 40,065 56,728 216,197
-------------------------------------------------------------------------
-------------------------------------------------------------------------
OIL AND GAS RESERVES
------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
(Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved developed
producing
Canada 11,434 727,596 230,569
United States - 13,626 24,204
------------------------------------------------------------
Total 11,434 741,222 254,773
------------------------------------------------------------
------------------------------------------------------------
Proved developed
non-producing
Canada 621 17,317 4,044
United States - 724 992
------------------------------------------------------------
Total 621 18,041 5,036
------------------------------------------------------------
------------------------------------------------------------
Proved undeveloped
Canada 635 160,348 39,341
United States - 450 662
------------------------------------------------------------
Total 635 160,798 40,003
------------------------------------------------------------
------------------------------------------------------------
Total Proved
Canada 12,690 905,261 273,954
United States - 14,800 25,858
------------------------------------------------------------
Total 12,690 920,061 299,812
------------------------------------------------------------
------------------------------------------------------------
Probable
Canada 3,777 306,804 128,693
United States - 37,221 14,840
------------------------------------------------------------
Total 3,777 344,025 143,533
------------------------------------------------------------
------------------------------------------------------------
Proved plus Probable
Canada 16,467 1,212,065 402,647
United States - 52,021 40,698
------------------------------------------------------------
Total 16,467 1,264,086 443,345
------------------------------------------------------------
------------------------------------------------------------
Proved Reserve Reconciliation
Proved Reserves - Company Interest Volumes (Forecast Prices)
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved Reserves at
Dec. 31, 2005 73,249 32,901 9,453 115,603
-------------------------------------------------------------------------
Acquisitions 984 - - 984
Divestments (30) - (591) (621)
Discoveries - 48 - 48
Extensions 1,648 11 - 1,659
Technical Revisions (2,191) 1,058 (132) (1,265)
Economic Factors 226 58 - 284
Improved Recovery 2,806 327 - 3,133
Production (6,188) (3,250) - (9,438)
-------------------------------------------------------------------------
Proved Reserves at
Dec. 31, 2006 70,504 31,153 8,730 110,387
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
CANADA (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved Reserves at
Dec. 31, 2005 13,084 952,624 287,458
------------------------------------------------------------
Acquisitions 160 5,518 2,063
Divestments (1) (145) (647)
Discoveries 27 4,095 757
Extensions 671 26,180 6,693
Technical Revisions 372 (4,956) (1,717)
Economic Factors (17) (5,304) (616)
Improved Recovery 30 23,981 7,159
Production (1,636) (96,732) (27,196)
------------------------------------------------------------
Proved Reserves at
Dec. 31, 2006 12,690 905,261 273,954
------------------------------------------------------------
------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
UNITED STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved Reserves at
Dec. 31, 2005 23,595 - - 23,595
-------------------------------------------------------------------------
Acquisitions 401 - - 401
Divestments - - - -
Discoveries - - - -
Extensions 440 - - 440
Technical Revisions 584 - - 584
Economic Factors - - - -
Improved Recovery 2,122 - - 2,122
Production (3,751) - - (3,751)
-------------------------------------------------------------------------
Proved Reserves at
Dec. 31, 2006 23,391 - - 23,391
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
UNITED STATES (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved Reserves at
Dec. 31, 2005 - 13,152 25,787
------------------------------------------------------------
Acquisitions - 341 458
Divestments - - -
Discoveries - - -
Extensions - 384 504
Technical Revisions - 1,732 872
Economic Factors - - -
Improved Recovery - 1,364 2,350
Production - (2,173) (4,113)
------------------------------------------------------------
Proved Reserves at
Dec. 31, 2006 - 14,800 25,858
------------------------------------------------------------
------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
TOTAL ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved Reserves at
Dec. 31, 2005 96,844 32,901 9,453 139,198
-------------------------------------------------------------------------
Acquisitions 1,385 - - 1,385
Divestments (30) - (591) (621)
Discoveries - 48 - 48
Extensions 2,088 11 - 2,099
Technical Revisions (1,607) 1,058 (132) (681)
Economic Factors 226 58 - 284
Improved Recovery 4,928 327 - 5,255
Production (9,939) (3,250) - (13,189)
-------------------------------------------------------------------------
Proved Reserves at
Dec. 31, 2006 93,895 31,153 8,730 133,778
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
TOTAL ENERPLUS (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved Reserves at
Dec. 31, 2005 13,084 965,776 313,245
------------------------------------------------------------
Acquisitions 160 5,859 2,521
Divestments (1) (145) (647)
Discoveries 27 4,095 757
Extensions 671 26,564 7,197
Technical Revisions 372 (3,224) (845)
Economic Factors (17) (5,304) (616)
Improved Recovery 30 25,345 9,509
Production (1,636) (98,905) (31,309)
------------------------------------------------------------
Proved Reserves at
Dec. 31, 2006 12,690 920,061 299,812
------------------------------------------------------------
------------------------------------------------------------
Probable Reserve Reconciliation
Probable Reserves - Company Interest Volumes (Forecast Prices)
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Probable Reserves at
Dec. 31, 2005 17,498 8,495 43,700 69,693
-------------------------------------------------------------------------
Acquisitions 451 - - 451
Divestments (5) - (2,738) (2,743)
Discoveries 1 18 - 19
Extensions 407 9 6,935 7,351
Technical Revisions (2,414) 337 101 (1,976)
Economic Factors 47 10 - 57
Improved Recovery 887 43 - 930
Production - - - -
-------------------------------------------------------------------------
Probable Reserves at
Dec. 31, 2006 16,872 8,912 47,998 73,782
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
CANADA (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Probable Reserves at
Dec. 31, 2005 3,539 309,572 124,827
------------------------------------------------------------
Acquisitions 72 2,219 893
Divestments (1) (13) (2,745)
Discoveries 8 845 168
Extensions 217 9,593 9,167
Technical Revisions (62) (22,147) (5,730)
Economic Factors (5) (1,642) (223)
Improved Recovery 9 8,377 2,336
Production - - -
------------------------------------------------------------
Probable Reserves at
Dec. 31, 2006 3,777 306,804 128,693
------------------------------------------------------------
------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
UNITED STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Probable Reserves at
Dec. 31, 2005 5,574 - - 5,574
-------------------------------------------------------------------------
Acquisitions 202 - - 202
Divestments - - - -
Discoveries - - - -
Extensions 982 - - 982
Technical Revisions 37 - - 37
Economic Factors - - - -
Improved Recovery 1,842 - - 1,842
Production - - - -
-------------------------------------------------------------------------
Probable Reserves at
Dec. 31, 2006 8,637 - - 8,637
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
UNITED STATES (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Probable Reserves at
Dec. 31, 2005 - 32,946 11,065
------------------------------------------------------------
Acquisitions - 230 240
Divestments - - -
Discoveries - - -
Extensions - 1,095 1,164
Technical Revisions - (1,002) (129)
Economic Factors - - -
Improved Recovery - 3,952 2,500
Production - - -
------------------------------------------------------------
Probable Reserves at
Dec. 31, 2006 - 37,221 14,840
------------------------------------------------------------
------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
TOTAL ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Probable Reserves at
Dec. 31, 2005 23,072 8,495 43,700 75,267
-------------------------------------------------------------------------
Acquisitions 653 - - 653
Divestments (5) - (2,738) (2,743)
Discoveries 1 18 - 19
Extensions 1,389 9 6,935 8,333
Technical Revisions (2,377) 337 101 (1,939)
Economic Factors 47 10 - 57
Improved Recovery 2,729 43 - 2,772
Production - - - -
-------------------------------------------------------------------------
Probable Reserves at
Dec. 31, 2006 25,509 8,912 47,998 82,419
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
TOTAL ENERPLUS (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Probable Reserves at
Dec. 31, 2005 3,539 342,518 135,892
------------------------------------------------------------
Acquisitions 72 2,449 1,133
Divestments (1) (13) (2,745)
Discoveries 8 845 168
Extensions 217 10,688 10,331
Technical Revisions (62) (23,149) (5,859)
Economic Factors (5) (1,642) (223)
Improved Recovery 9 12,329 4,836
Production - - -
------------------------------------------------------------
Probable Reserves at
Dec. 31, 2006 3,777 344,025 143,533
------------------------------------------------------------
------------------------------------------------------------
Proved Plus Probable Reserve Reconciliation
Proved Plus Probable Reserves - Company Interest Volumes (Forecast
Prices)
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2005 90,747 41,396 53,153 185,296
-------------------------------------------------------------------------
Acquisitions 1,435 - - 1,435
Divestments (35) - (3,329) (3,364)
Discoveries 1 66 - 67
Extensions 2,055 20 6,935 9,010
Technical Revisions (4,605) 1,395 (31) (3,241)
Economic Factors 273 68 - 341
Improved Recovery 3,693 370 - 4,063
Production (6,188) (3,250) - (9,438)
-------------------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2006 87,376 40,065 56,728 184,169
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
CANADA (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2005 16,623 1,262,196 412,285
------------------------------------------------------------
Acquisitions 232 7,737 2,956
Divestments (2) (158) (3,392)
Discoveries 35 4,940 925
Extensions 888 35,773 15,860
Technical Revisions 310 (27,103) (7,447)
Economic Factors (22) (6,946) (839)
Improved Recovery 39 32,358 9,495
Production (1,636) (96,732) (27,196)
------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2006 16,467 1,212,065 402,647
------------------------------------------------------------
------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
UNITED STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved Plus Probable
Reserves
at Dec. 31, 2005 29,169 - - 29,169
-------------------------------------------------------------------------
Acquisitions 603 - - 603
Divestments - - - -
Discoveries - - - -
Extensions 1,422 - - 1,422
Technical Revisions 621 - - 621
Economic Factors - - - -
Improved Recovery 3,964 - - 3,964
Production (3,751) - - (3,751)
-------------------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2006 32,028 - - 32,028
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
UNITED STATES (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved Plus Probable
Reserves
at Dec. 31, 2005 - 46,098 36,852
------------------------------------- -----------------------
Acquisitions - 571 698
Divestments - - -
Discoveries - - -
Extensions - 1,479 1,668
Technical Revisions - 730 743
Economic Factors - - -
Improved Recovery - 5,316 4,850
Production - (2,173) (4,113)
------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2006 - 52,021 40,698
------------------------------------------------------------
------------------------------------------------------------
Light & Heavy Bitumen
Medium Oil Oil (Oil Sands) Total Oil
TOTAL ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls)
-------------------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2005 119,916 41,396 53,153 214,465
-------------------------------------------------------------------------
Acquisitions 2,038 - - 2,038
Divestments (35) - (3,329) (3,364)
Discoveries 1 66 - 67
Extensions 3,477 20 6,935 10,432
Technical Revisions (3,984) 1,395 (31) (2,620)
Economic Factors 273 68 - 341
Improved Recovery 7,657 370 - 8,027
Production (9,939) (3,250) - (13,189)
-------------------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2006 119,404 40,065 56,728 216,197
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural
Gas Natural
Liquids Gas Total
TOTAL ENERPLUS (Mbbls) (MMcf) (MBOE)
------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2005 16,623 1,308,294 449,137
------------------------------------------------------------
Acquisitions 232 8,308 3,654
Divestments (2) (158) (3,392)
Discoveries 35 4,940 925
Extensions 888 37,252 17,528
Technical Revisions 310 (26,373) (6,704)
Economic Factors (22) (6,946) (839)
Improved Recovery 39 37,674 14,345
Production (1,636) (98,905) (31,309)
------------------------------------------------------------
Proved Plus Probable
Reserves at
Dec. 31, 2006 16,467 1,264,086 443,345
------------------------------------------------------------
------------------------------------------------------------
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (after U.S. taxes) at December 31, 2006
Conventional Reserves
($ millions,
discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing
Canada 6,705 4,479 3,464 2,877
United States 804 624 509 431
-------------------------------------------------------------------------
Total 7,509 5,103 3,973 3,308
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved developed
non-producing
Canada 120 75 56 45
United States 25 19 16 13
-------------------------------------------------------------------------
Total 145 94 72 58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved undeveloped
Canada 556 385 272 196
United States 26 16 10 7
-------------------------------------------------------------------------
Total 582 401 282 203
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved
Canada 7,381 4,939 3,792 3,118
United States 855 659 535 451
-------------------------------------------------------------------------
Total 8,236 5,598 4,327 3,569
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable
Canada 2,721 1,242 745 516
United States 419 217 126 78
-------------------------------------------------------------------------
Total 3,140 1,459 871 594
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved Plus
Probable Conventional
Reserves 11,376 7,057 5,198 4,163
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bitumen (Oil Sands)
Reserves
Proved developed
producing 20 16 13 11
Proved undeveloped 39 20 10 4
-------------------------------------------------------------------------
Total Proved 59 36 23 15
-------------------------------------------------------------------------
Probable 453 104 25 2
-------------------------------------------------------------------------
Total Proved plus Probable
Bitumen (Oil Sands)Reserves 512 140 48 17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Conventional and
Bitumen (Oil Sands)
Reserves 11,888 7,197 5,246 4,180
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value
Enerplus' net asset value is measured with reference to the present value
of all future net revenue from our reserves, assuming current income tax laws,
as estimated by our independent reserve engineers, Sproule, GLJ and D&M, 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, despite our 20
year history of replacing production through acquisitions and development.
Net Asset Value - Forecast Prices and Costs (After U.S. Tax) at
December 31, 2006
($ millions except trust
unit amounts, discounted at) 0% 5% 10% 15%
------------------------------------------------------------------------
Present value of proved
plus probable reserves
Canadian Conventional 10,102 6,181 4,537 3,634
United States
(after tax) 1,274 876 661 529
Bitumen (Oil Sands) 512 140 48 17
-------------------------------------------------------------------------
Total, present value
of proved plus
probable reserves 11,888 7,197 5,246 4,180
Undeveloped acreage
Canada 53 53 53 53
United States 16 16 16 16
Long-term debt
(net of cash) (680) (680) (680) (680)
Asset retirement
obligations(1) (194) (95) (24) (11)
-------------------------------------------------------------------------
Net Working Capital
excluding deferred
financial assets and
distributions payable
to unitholders. (102) (102) (102) (102)
-------------------------------------------------------------------------
Net Asset Value 10,981 6,389 4,509 3,456
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per
Trust Unit at
December 31, 2006(2) $ 89.17 $ 51.88 $ 36.61 $ 28.06
-------------------------------------------------------------------------
(1) Asset retirement obligations do not equal the amount on the balance
sheet ($124 million) as the balance sheet amount uses a 6% discount
rate and a portion of the ARO costs are already reflected in the
present value of reserves computed by the independent engineers
(2) Based on 123,151,000 Trust Units outstanding as at December 31, 2006
FINDING DEVELOPMENT AND ACQUISITION COSTS
FD&A costs can be calculated either including or excluding future
development capital ("FDC"). FD&A costs under NI 51-101 include FDC as this
provides a more representative view of the full cost of reserve additions as
it accounts for future costs to bring the reserves to market. Under the
historic method, FD&A costs are understated as reserves are included without
taking into account the future capital expenditures required to fully develop
the reserve base. We have included both the NI 51-101 method which includes
FDC and the historic method for comparison purposes.
FD&A Costs (including Future Development Capital)
($ millions, except per BOE amounts) 2006 2005 2004
-------------------------------------------------------------------------
Proved Reserves
Excluding Oil Sands:
Capital expenditures and
net acquisitions $ 502.0 $ 973.0 $ 803.2
Net change in future
development capital 8.0 184.7 99.0
Company reserve additions (MMBOE) 18.6 53.7 57.5
Oil Sands:
Capital expenditures and net
acquisitions 19.4 33.2 8.3
Net change in future
development capital (13.6) 44.6 -
Company reserve additions (MMBOE) (0.7) 9.5 -
FD&A costs ($/BOE) $ 28.82 $ 19.55 $ 15.83
Three-year average FD&A
costs ($/BOE)(1) $ 19.20 $ 22.73 $ 18.85
-------------------------------------------------------------------------
Proved plus Probable Reserves
Excluding Oil Sands:
Capital expenditures and net
acquisitions $ 502.0 $ 973.0 $ 803.2
Net change in future
development capital 54.4 197.7 120.7
Company reserve additions (MMBOE) 21.9 66.6 58.0
Oil Sands:
Capital expenditures and net
acquisitions 19.4 33.2 8.3
Net change in future
development capital 15.6 33.4 266.1
Company reserve additions (MMBOE) 3.6 5.4 47.7
FD&A costs ($/BOE) $ 23.19 $ 17.18 $ 11.34
Three-year average FD&A
costs ($/BOE)(1) $ 14.90 $ 13.46 $ 11.02
-------------------------------------------------------------------------
(1) FD&A calculated over a three-year period.
FD&A Costs (excluding Future Development Capital)
($ millions, except per BOE amounts) 2006 2005 2004
-------------------------------------------------------------------------
Proved Reserves
Excluding Oil Sands:
Capital expenditures and
net acquisitions $ 502.0 $ 973.0 $ 803.2
Company reserve additions (MMBOE) 18.6 53.7 57.5
Oil Sands:
Capital expenditures and
net acquisitions 19.4 33.2 8.3
Company reserve additions (MMBOE) (0.7) 9.5 -
FD&A costs ($/BOE) $ 29.13 $ 15.92 $ 14.11
Three-year average FD&A costs
($/BOE)(1) $ 16.88 $ 14.30 $ 11.62
-------------------------------------------------------------------------
Proved plus Probable Reserves
Excluding Oil Sands:
Capital expenditures and
net acquisitions $ 502.0 $ 973.0 $ 803.2
Company reserve additions (MMBOE) 21.9 66.6 58.0
Oil Sands:
Capital expenditures and
net acquisitions 19.4 33.2 8.3
Company reserve additions (MMBOE) 3.6 5.4 47.7
FD&A costs ($/BOE) $ 20.45 $ 13.98 $ 7.68
Three-year average FD&A costs
($/BOE)(1) $ 11.51 $ 10.09 $ 8.22
-------------------------------------------------------------------------
(1) Calculated as FD&A 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.
(Proved plus probable reserves) 2006 2005 2004
-------------------------------------------------------------------------
Operating income ($/BOE) 31.75 29.80 21.86
Finding, development and acquisition
costs including FDC ($/BOE) 23.19 17.18 11.34
Recycle ratio 1.4x 1.7x 1.9x
Three-year average recycle ratio 1.6x 1.8x 1.8x
-------------------------------------------------------------------------
FINANCIAL OVERVIEW
Update on Canadian Government Announcement on Intention to Tax Trusts
On October 31, 2006, the Canadian federal government (the "Government")
announced plans to introduce a tax on publicly traded income trusts. For
existing income trusts, such as Enerplus, the new tax measures would be
effective for 2011, provided we comply with the "normal growth" parameters
regarding equity growth until that time. A "Notice of Ways and Means Motion"
was passed in Parliament shortly after the Government announcement. This
notice was a one-page summary of the Government's proposal and it did not
identify any specific amendments to the Income Tax Act.
On December 15, 2006 the Government announced safe harbour guidance
regarding "normal growth" for equity capital. The safe harbour amount will be
measured by reference to the individual trust's market capitalization as of
the end of trading on October 31, 2006 (which was approximately $7.5 billion
for Enerplus). For the period from November 1, 2006 to December 31, 2007 a
trust's safe harbour amount will be 40 percent of the October 31, 2006 market
capitalization benchmark and for each of the years 2008 through and including
2010 will be 20 percent of the benchmark, cumulatively allowing growth of up
to 100 percent until 2011. In addition, we understand that trusts will be able
to issue equity to retire debt existing on October 31, 2006 without eroding
their safe harbour limits.
On December 21, 2006, the Government released more detailed draft
legislation with respect to the proposed amendments to the Income Tax Act and
requested comments from stakeholders. In late January 2007, the House of
Commons Standing Committee on Finance held special hearings on the proposed
tax and the draft legislation. At this time we are unable to determine the
impact, if any, these hearings may have on the proposed legislation or the
timing of when the proposed legislation could be passed in Parliament.
Should the tax legislation become substantially enacted, future income
taxes may be adjusted to include temporary differences between the accounting
and tax bases of the trust's assets and liabilities. In addition, reserves
reported under NI 51-101 may be adjusted to include an estimate of the tax
effect on our estimated future revenues from our reserves. We will assess
alternative organizational structures during the four-year transition period.
We are confident we have the team, the assets, and the opportunities to
prosper regardless of our organizational structure.
RESULTS OF OPERATIONS
Production
Daily production during 2006 averaged 85,779 BOE/day, slightly above our
guidance of 85,500 BOE/day and 8% higher than 79,727 BOE/day in 2005. The
increase was primarily due to our U.S. acquisitions in the second half of 2005
which added an incremental 8,121 BOE/day of production in 2006 along with our
development capital program which added an additional 5,633 BOE/day of
production in 2006. These increases were offset in part by natural reservoir
declines experienced throughout the year.
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, 2006 and 2005 are outlined below:
Daily Production Volumes 2006 2005 % Change
-------------------------------------------------------------------------
Natural gas (Mcf/day) 270,972 274,336 (1%)
Crude oil (bbls/day) 36,134 29,315 23%
Natural gas liquids (bbls/day) 4,483 4,689 (4%)
Total daily sales (BOE/day) 85,779 79,727 8%
-------------------------------------------------------------------------
We exited the year with production of approximately 87,500 BOE/day based
on December's production, in line with our target of 88,000 BOE/day.
We expect 2007 annual production volumes to remain essentially flat year-
over-year, averaging 85,000 BOE/day, weighted 54% to natural gas and 46%
to liquids. As a result of the timing of our planned development capital
program, we expect to exit 2007 with production of approximately 86,000
BOE/day. This does not contemplate any potential acquisitions or dispositions.
Pricing
The prices received for our natural gas and crude oil production directly
impact our earnings, cash flow and financial condition. The following table
compares our average selling prices for 2006 with those of 2005. It also
compares the benchmark price indices for the same periods.
Average Selling Price(1) 2006 2005 % Change
-------------------------------------------------------------------------
Natural gas (per Mcf) $ 6.81 $ 8.41 (19%)
Crude oil (per bbl) 61.80 55.93 10%
Natural gas liquids (per bbl) 50.90 47.33 8%
Per BOE $ 50.23 $ 52.36 (4%)
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Average Benchmark Pricing 2006 2005 % Change
-------------------------------------------------------------------------
AECO natural gas - monthly index
(CDN$/Mcf) $ 6.99 $ 8.48 (18%)
AECO natural gas - daily index
(CDN$/Mcf) 6.53 8.71 (25%)
NYMEX natural gas - monthly NX3
index (US$/Mcf) 7.26 8.55 (15%)
NYMEX natural gas - monthly NX3
index: CDN$ equivalent (CDN$/Mcf) 8.25 10.30 (20%)
WTI crude oil (US$/bbl) 66.22 56.56 17%
WTI crude oil: CDN$ equivalent
(CDN$/bbl) 75.25 68.14 10%
CDN$/US$ exchange rate $ 0.88 $ 0.83 6%
-------------------------------------------------------------------------
Natural Gas
Natural gas prices were in a downward trend during 2006, influenced
initially by demand loss, the residual high storage inventories after a warm
winter, and strong drilling. In July 2006, prices received some support due to
above normal temperatures in key consuming regions of the United States, and
forecasts for a strong hurricane season. Year-over-year the natural gas
storage surplus continued to build and those hurricanes that did develop were
moderate. This ultimately drove the AECO monthly index price to a low for the
year of $4.45/Mcf in October, with the daily spot price dropping to $3.25/Mcf
in the same month. Spot and forward prices recovered significantly as winter
approached, with spot prices rising briefly above $8.00/Mcf before the warmer
than normal November and December, caused by an El Nino weather pattern,
pushed the daily spot price back to $6.07/Mcf on December 31, 2006.
Our natural gas portfolio is comprised of aggregator, AECO, and
downstream direct sales. In 2006 we sold 42% of our natural gas on the daily
AECO market and 42% on the monthly AECO market, as well as 16% against the day
and month NYMEX indices. During 2006 we realized an average price for our
natural gas sales of $6.81/Mcf (net of transportation costs), a decrease of
19% from the $8.41/Mcf realized in 2005. This reduction is comparable to the
price decreases realized in each of: the AECO daily index which decreased by
25% year over year; the AECO monthly index which decreased by 18%; and the
NYMEX monthly index (converted to CDN$/Mcf) which decreased by 20%.
Crude Oil
World crude prices continued to be influenced by a tight supply-demand
balance through the first half of 2006, continuing the upward trend in prices
experienced during 2005. WTI spot prices peaked in July during the Israel-
Hezbollah conflict at US$77.03/bbl. With strong inventories, forecasts for
warmer than normal conditions for the winter, and a strengthening supply
picture, prices fell thereafter through the second half of 2006. The WTI spot
price hit a low of US$55.81/bbl in November, representing a 28% reduction from
the July high.
Our crude oil portfolio in 2006 was approximately 70% light/medium and
30% heavy. The average price received for our crude oil (net of transportation
costs) was $61.80/bbl during 2006, a 10% increase over 2005. Similarly, the
West Texas Intermediate ("WTI") crude oil benchmark price, after adjusting for
the change in the US$ exchange rate, also increased by 10% year over year.
Although we added more light sweet crude oil to our portfolio in 2006 compared
to 2005, this benefit was offset by widening heavy crude oil differentials
during the year.
Canadian/US Exchange Rate
The Canadian dollar strengthened 6% against the U.S. dollar during 2006
compared to 2005 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.
Price Risk Management
While the overall energy outlook remains generally bullish long term,
there remains uncertainty as to the direction prices might move in 2007. Both
natural gas and crude oil prices have the potential to fall further in 2007
given current levels of inventory, aggressive drilling in the U.S. for gas and
across the globe for crude oil and some uncertainty with respect to the world
economy.
We have developed a price risk management framework to respond to the
volatile price environment in a prudent 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 while maintaining participation should commodity prices increase.
Given our price risk management framework we have entered into additional
commodity contracts during the fourth quarter and subsequent to year end.
These contracts are designed to protect a portion of our natural gas revenue
for the period January 2007 through March 2008 and to protect a portion of our
crude oil revenue for the period January 2007 through December 2007. We have
also hedged electricity volumes for the period January 2007 through September
2008 to protect against rising electricity costs in the Alberta power market.
See Note 10 for a detailed list of our current price risk management
positions.
The following is a summary of the physical and financial contracts in
place at February 13, 2007 as a percentage of our forecasted net production
volumes:
Natural Gas Crude Oil
(CDN$/Mcf) (US$/bbl)
----------------------------------- -------------
January 1, April 1, November 1, January 1,
2007 - 2007 - 2007 - 2007 -
March 31, October 31, March 31, December 31,
2007 2007 2008 2007
-------------------------------------------------------------------------
Floor Protection
Price $ 7.53 $ 7.32 $ 8.13 $ 68.93
% (net of royalties) 21% 32% 3% 34%
Upside Capped Price $ 10.64 $ 9.07 $ 10.31 $ -
% (net of royalties) 14% 28% 3% -%
Fixed Price $ - $ 7.58 $ 8.70 $ 66.24
% (net of royalties) -% 12% 2% 8%
-------------------------------------------------------------------------
Based on weighted average price, before premiums, and average production
of 85,000 BOE/day.
Assumes production mix of 54% gas, 42% oil and 4% NGL.
Accounting for Price Risk Management
During 2006, our commodity price risk management positions incurred cash
costs of $27.2 million on crude oil contracts and $7.1 million on natural gas
contracts compared to cash costs of $91.0 million and $51.6 million
respectively during 2005. The decrease in crude oil cash costs is due to the
expiration of contracts on June 30, 2006 that had ceiling prices between
US$35.35/bbl and US$45.80/bbl on 4,500 bbls/day. The decrease in natural gas
cash costs is the result of lower natural gas prices experienced during 2006
and the expiration of old contracts.
The unrealized gain on our financial contracts of $81.0 million for the
year ended December 31, 2006 represents the change in the fair value of
financial contracts since December 31, 2005. 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 increase to earnings. At December 31, 2006 the fair value
of our financial contracts net of premiums is $23.6 million and is recorded on
the balance sheet as a deferred financial asset. See Note 2 for details.
Effective December 31, 2005, we elected to stop designating our commodity
financial contracts as hedges. As a result we recorded a deferred credit
representing the fair value of these contracts on that day, with an offset
recorded as a deferred financial asset that is amortized to income over the
life of the underlying contracts. These costs of $49.9 million are fully
amortized at December 31, 2006. See Note 2 for details.
The following table summarizes the effects of our financial contracts on
income for the years ended December 31, 2006 and 2005.
Risk Management (Gains)
/Losses ($ millions,
except per unit
amounts) 2006 2005
-------------------------------------------------------------------------
Cash (gains)/losses:
Crude oil $ 27.2 $ 2.06/bbl $ 91.0 $ 8.51/bbl
Natural Gas 7.1 $ 0.07/Mcf 51.6 $ 0.52/Mcf
------------ ------------
Total Cash losses $ 34.3 $ 1.10/BOE $ 142.6 $ 4.90/BOE
Non-cash
(gains)/losses:
Change in fair
value - financial
contracts $ (81.0) $(2.59)/BOE $ (35.8) $(1.23)/BOE
Amortization of
deferred financial
assets 49.9 $ 1.59/BOE 3.1 $ 0.11/BOE
------------ ------------
Total Non-cash gains $ (31.1) $(0.99)/BOE $ (32.7) $(1.12)/BOE
------------ ------------
Total losses $ 3.2 $ 0.11/BOE $ 109.9 $ 3.78/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Flow Sensitivity
The sensitivities below reflect all commodity contracts as described in
Note 10 and are based on current forward markets for 2007 at February 13,
2007. 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.
Sensitivity Table Estimated Effect on 2007
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 $ 0.05
Change of 1,000 BOE/day in production $ 0.13
Change of $0.01 in the US$/CDN$ exchange rate $ 0.12
Change of 1% in interest rate $ 0.06
-------------------------------------------------------------------------
(1) Assumes constant working capital and 123,151,000 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, 2006
were $1,572.7 million ($1,595.3 million, net of $22.6 million of
transportation costs) compared to $1,523.7 million ($1,550.6 million, net of
$26.9 million of transportation costs) during 2005. Increased crude oil
volumes from our 2005 acquisitions along with higher realized oil prices were
offset primarily by the decrease in natural gas prices. The result was an
increase of 3% or $49.0 million in revenue net of transportation costs.
Analysis of Sales
Revenue(1) Natural
($ millions) Crude oil NGLs Gas Total
-------------------------------------------------------------------------
2005 Sales Revenue $ 598.4 $ 81.0 $ 844.3 $ 1,523.7
Price variance(1) 77.4 5.9 (159.6) (76.3)
Volume variance 139.2 (3.6) (10.3) 125.3
-------------------------------------------------------------------------
2006 Sales Revenue $ 815.0 $ 83.3 $ 674.4 $ 1,572.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 2006 and 2005 were approximately 19% of
oil and gas sales, net of transportation costs. Overall, royalties decreased
marginally in 2006 to $293.2 million compared to $297.0 million during 2005
primarily as a result of the decrease in natural gas prices experienced over
the period.
For 2007 we expect royalties to remain at approximately 19% of oil and
gas sales, net of transportation costs, however this may change as a result of
the Alberta government's stated intention to review the oil and gas royalty
regime. Alberta royalties represented approximately 70% of our total royalties
incurred during 2006 (2005 - 87%).
Operating Expenses
Operating expenses for the year ended December 31, 2006 were $8.02/BOE or
$251.2 million. This represents a 3% increase over our guidance of $7.80/BOE
and an 8% increase from $7.45/BOE in 2005. Cost pressures associated with the
high level of industry activity have increased operating costs during 2006.
The areas that were most impacted by these activity levels included scheduled
facility maintenance and well servicing.
During the fourth quarter we experienced increases as a result of the
timing of certain well servicing and facility maintenance programs. As well,
we experienced higher natural gas processing fees at certain facilities.
We anticipate continued increases in operating costs in 2007 due to
general cost escalation. As a result, we expect costs to average $8.45/BOE,
representing an increase of 5% per BOE compared to 2006. Although we are
seeing evidence that the cost inflation in our industry has moderated, it is
too soon to tell if this trend is sustainable.
General and Administrative Expenses
G&A expenses were $1.91/BOE or $59.9 million for the year ended
December 31, 2006. On a BOE basis G&A was 3% higher than our guidance of
$1.85/BOE and 37% higher than $1.39/BOE 2005.
The highly competitive marketplace resulted in challenges to recruit and
retain skilled professionals. For the year ended December 31, 2006
compensation and long-term incentives increased approximately $14.0 million or
$0.45/BOE compared to the same period in 2005. Other increases included
additional technology and information systems, our commitment to education
funding for SAIT Polytechnic, along with ongoing regulatory compliance
requirements.
For the year ended December 31, 2006, our G&A expenses included non-cash
charges for our trust unit rights incentive plan of $6.3 million or $0.20/BOE
compared to $3.0 million or $0.11/BOE for 2005. These amounts are determined
using a binomial lattice option-pricing model. The increased volatility of our
trust unit price combined with the increased number of rights outstanding, as
a result of an increase in the number of employees, have impacted the non-
cash cost of the plan.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and Administrative Costs
($ millions) 2006 2005
-------------------------------------------------------------------------
Cash $ 53.6 $ 37.4
Trust unit rights incentive plan (non-cash) 6.3 3.0
-------------------------------------------------------------------------
Total G&A $ 59.9 $ 40.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2006 2005
-------------------------------------------------------------------------
Cash $ 1.71 $ 1.28
Trust unit rights incentive plan (non-cash) 0.20 0.11
-------------------------------------------------------------------------
Total G&A $ 1.91 $ 1.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In 2007 we expect total G&A costs to be approximately $2.40/BOE,
including non-cash G&A costs of approximately $0.30/BOE. The forecasted
increase reflects cost pressures to recruit and retain a technically skilled
labour force. It also includes increased costs associated with ongoing
regulatory compliance and costs associated with planning and responding to the
proposed tax on trusts.
Interest Expense
Annual interest expense increased by $6.4 million to $32.2 million
compared to $25.8 million in 2005. This increase is due to higher average debt
outstanding and rising interest rates during 2006. Our average borrowing rate,
before the effects of hedging, for 2006 was 4.8% compared to 3.4% for 2005. At
December 31, 2006, 20% of our debt was based on fixed interest rates while 80%
was floating. These instruments are more fully described in Note 10.
Capital Expenditures
During the year ended December 31, 2006 we spent $491.2 million on
development capital and facilities, our largest capital program to date. This
was $6.2 million higher than our guidance of $485.0 million and $122.5 million
or 33% higher than the $368.7 million spent in 2005. We achieved a 99% success
rate with our drilling program as 361 net wells were drilled during 2006.
Development in 2006 focused primarily on Bakken oil, shallow gas, coalbed
methane, waterfloods, and our Joslyn oil sands property.
Property acquisitions were $51.3 million for the year ended December 31,
2006 compared to $119.9 million in 2005. Acquisitions during 2006 included
$16.0 million for assets in the U.S., as well as $11.9 million and
$11.7 million for properties at Copton and Gleneath respectively. There were
no corporate acquisitions during 2006 whereas in 2005 we spent $584.1 million
for the acquisitions of Lyco Energy Corporation and TriLoch Resources Inc.
Property dispositions were $21.1 million for the year ended December 31, 2006
compared to $66.5 million for 2005. The majority of our 2006 divestments
related to the sale of a 1% working interest in the Joslyn property in the
amount of $19.7 million compared to the 2005 non-core divestment program which
raised $66.5 million.
Capital Expenditures ($ millions) 2006 2005
-------------------------------------------------------------------------
Development expenditures $ 380.5 $ 272.2
Plant and facilities 110.7 96.5
-------------------------------------------------------------------------
Development Capital 491.2 368.7
Office 5.0 4.3
-------------------------------------------------------------------------
Sub-total 496.2 373.0
Acquisitions of oil and gas properties(1) 51.3 119.9
Corporate acquisitions - 584.1
Dispositions of oil and gas properties(1) (21.1) (66.5)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 526.4 $ 1,010.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Capital Expenditures financed
with cash flow $ 249.4 $ 276.4
Total Capital Expenditures financed with
debt and equity 296.5 734.1
Total non-cash consideration for 1% sale
of Joslyn project (19.5) -
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 526.4 $ 1,010.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
The following is a summary by major property of our largest development
capital expenditures during 2006 and 2005.
($ millions)
Property Development Type 2006 2005
-------------------------------------------------------------------------
Sleeping Giant Bakken oil $ 116.7 $ 29.1
Joslyn and oil sands Oil sands 39.1 33.2
Bantry Conventional oil and
shallow gas 21.7 42.0
Joarcam Oil waterflood 20.2 16.9
Pembina 5-Way Oil waterflood 15.7 19.8
Medicine Hat Oil waterflood and
shallow gas 14.9 11.0
Shackleton Shallow gas 12.7 5.6
Hanna/Garden Plains Shallow gas 12.5 18.5
Joffre Coalbed methane 12.5 15.9
Deep Basin Natural gas 12.4 11.6
Other Oil and gas 212.8 165.1
-------------------------------------------------------------------------
Total $ 491.2 $ 368.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We expect total development capital expenditures in 2007 to be
approximately $410 million. We plan to spend approximately $70 million on
Bakken oil development, $65 million on waterflood development, $43 million on
shallow natural gas and coalbed methane development and $40 million on oil
sands development. We expect other conventional development costs to be
approximately $192 million during 2007.
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, 2006 DDA&A increased to $15.38/BOE compared to $13.27/BOE during
the year ended December 31, 2005. The increase was due to the inclusion of a
full year of operations from our U.S. properties which were acquired in the
latter half of 2005.
No impairment existed at December 31, 2006 using year-end reserves and
management's estimates of future prices. Our future price estimates are more
fully discussed in Note 3.
Asset Retirement Obligations
We have estimated our total future asset retirement obligations based on
our 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. Our asset retirement obligation was
$123.6 million at December 31, 2006 compared to $110.6 million at December 31,
2005. The increase of $13.0 million was due to our acquisition and development
activity during the year combined with changes in estimated future
liabilities. The remainder of the change was due to retirement costs incurred
offset by accretion expense for the year. See Note 4.
The following chart compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation, and asset retirement
obligations settled.
($ millions) 2006 2005
-------------------------------------------------------------------------
Amortization of the asset retirement cost $ 12.6 $ 10.6
Accretion of the asset retirement obligation 6.2 6.3
-------------------------------------------------------------------------
Total Amortization and Accretion $ 18.8 $ 16.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement Obligations Settled $ 11.5 $ 7.8
-------------------------------------------------------------------------
Actual asset retirement costs will be 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 2036 and 2045. For accounting purposes, the asset retirement cost is
amortized using a unit-of-production method based on proved reserves before
royalties while the asset retirement obligation accretes until the time the
obligation is settled.
Taxes
Future Income Taxes
Future income taxes arise from differences between the accounting and tax
bases of the operating companies' assets and liabilities. Net income of the
operating companies and the tax recovery fluctuate based on the royalty and
interest payments to the Fund. Therefore, the future income tax that is
recorded on the balance sheet is expected to be recovered through earnings
over time.
For the year ended December 31, 2006, a future income tax recovery of
$112.0 million was recorded in income compared to a future income tax expense
of $15.3 million in 2005. The change year-over-year was mainly due to a lower
effective tax rate for 2006, a change in discretionary tax deductions in prior
years resulting in a $21.4 million recovery and recognition of a tax rate
reduction for future years resulting in a $35.5 million recovery. See Note 9
for more details.
On October 31, 2006, the Government announced plans to introduce a tax on
publicly traded income trusts, effective for 2011. A "Notice of Ways and Means
Motion" was passed in parliament shortly after the government announcement.
This notice was a one-page summary of the government's proposal and it did not
identify any specific amendments to the Income Tax Act. On December 21, 2006,
draft legislative proposals to implement the tax were released for comment. If
the tax legislation becomes substantively enacted as proposed, future income
taxes may be adjusted to include temporary differences between the accounting
and tax bases of the trust's assets and liabilities.
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.
For the year ended December 31, 2006 our U.S. operations incurred income
related taxes in the amount of $18.2 million compared to $2.8 million for the
year ended December 31, 2005. The increase is primarily a result of a full
year of U.S. operations in 2006.
The amount of current taxes recorded throughout the year is dependent
upon the level of U.S. cash flow as well as the timing of both capital
expenditures and repatriation of the funds to Canada. Our U.S. taxes as a
percentage of cash flow, assuming constant working capital, were 9% for the
year ended December 31, 2006 as compared to our guidance of 15%. The reduction
is mainly due to funds being retained in the U.S. for the 2007 development
capital program and acquisitions (see Note 13 describing the acquisition of
gross overriding royalty interests in the Jonah natural gas field in Wyoming).
We expect the current income and withholding taxes to average approximately
15% of cash flow from U.S. operations in 2007 assuming all funds are
repatriated to Canada after U.S. development capital spending.
Tax Pools
We estimate our tax pools at December 31, 2006 to be as follows:
Trust Operating Total
Pool Type ($ millions) entities
-------------------------------------------------------------------------
COGPE $ 450 $ 100 $ 550
CDE - 300 300
UCC - 500 500
Tax losses and other 50 400 450
Foreign tax pools - 100 100
-------------------------------------------------------------------------
Total $ 500 $ 1,400 $ 1,900
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Income
Net income for the year ended December 31, 2006 was $544.8 million or
$4.48 per trust unit compared to $432.0 million or $3.96 per trust unit for
the year ended December 31, 2005. The $112.8 million increase in net income
was primarily due to a $49.0 million increase in oil and gas sales (net of
transportation costs), reduced risk management costs of $106.7 million and an
increased future income tax recovery of $127.4 million, partially offset by
increased DDA&A charges of $95.1 million, operating costs of $34.4 million and
G&A costs of $19.6 million.
Cash Flow from Operating Activities
Cash flow from operating activities for the year ended December 31, 2006
was $863.7 million or $7.10 per trust unit compared to $774.6 million or
$7.10 per trust unit for 2005. Cash flow increased during the year as a result
of higher oil and gas sales and reduced cash risk management costs, offset in
part by increases in operating costs and G&A expenses.
Selected Financial Results
Per BOE of production (6:1) 2006 2005
-------------------------------------------------------------------------
Production per day 85,779 79,727
-------------------------------------------------------------------------
Weighted average sales price(1) $ 50.23 $ 52.36
Royalties (9.36) (10.21)
Financial contracts (0.11) (3.78)
Deduct: Non-cash financial contract gain (0.99) (1.12)
Operating costs (8.02) (7.45)
General and administrative (1.91) (1.39)
Add back: Non-cash G&A expense
(trust unit rights) 0.20 0.11
Interest expense, net of interest and
other income (0.95) (0.51)
Foreign exchange gain (loss) 0.02 (0.06)
Deduct: Non-cash foreign exchange gain - (0.07)
Capital taxes (0.11) (0.22)
Current income tax (0.59) (0.09)
Asset retirement obligations settled (0.37) (0.27)
-------------------------------------------------------------------------
Cash flow before changes in non-cash
working capital 28.04 27.30
Asset retirement obligations settled 0.37 0.27
Non-cash items:
Depletion, depreciation, amortization
and accretion (15.38) (13.27)
Financial contracts 0.99 1.12
G&A expense (trust unit rights) (0.20) (0.11)
Foreign exchange gain - 0.07
Future income tax recovery/(expense) 3.58 (0.53)
-------------------------------------------------------------------------
Total net income per BOE $ 17.40 $ 14.85
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Selected Canadian and U.S. Financial Results
The following table provides a geographical analysis of key financial
results for 2006.
($ millions, except 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
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 (241.0) (52.2)(2) (293.2)
Other financial contracts (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.
Quarterly Financial Information
Overall oil and gas sales increased during 2005 due to higher crude oil
production and higher crude oil and natural gas prices, and decreased during
2006 due to lower gas prices. Net income has been affected by fluctuating oil
and gas prices and risk management costs, the fluctuating Canadian dollar,
higher operating and G&A costs, changes in future tax provisions as well as
changes to accounting policies adopted during 2005. Furthermore, changes in
the fair value of our financial contracts, which are impacted by future
prices, continue to cause net income to fluctuate between quarters.
Quarterly Financial Information
Oil Net Income Per Trust Unit
($ millions, except per and Gas
trust unit amounts) Sales(1) Net Income Basic Diluted
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2005
Fourth Quarter $ 503.2 $ 150.9 $ 1.29 $ 1.28
Third Quarter 398.7 107.1 0.97 0.97
Second Quarter 320.0 108.8 1.04 1.04
First Quarter 301.8 65.2 0.63 0.62
-----------------------------------------------
Total $ 1,523.7 $ 432.0 $ 3.96 $ 3.95
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 2006 with the same period in 2005:
- Net income decreased 27% to $110.2 million due to decreased natural
gas prices and increased operating and G&A costs, partially offset by
reduced risk management costs.
- Cash flow decreased 28% to $207.1 million in 2006 compared to
$288.5 million in 2005.
- Average daily production increased 2% due to our development capital
program.
- The average selling price per BOE decreased 28% due to weaker natural
gas prices.
- Operating expenses increased 17% on a BOE basis to $8.52/BOE. Due to
the timing of well servicing and facility maintenance programs
additional costs were recorded in the fourth quarter of 2006.
- G&A expenses increased 29% on a BOE basis to $2.13/BOE due to
compensation costs.
- Development capital spending decreased 12% compared to the fourth
quarter of 2005 as a result of 2005 capital spending being weighted
towards the fourth quarter while 2006 capital spending was evenly
weighted between all four quarters.
Summary Fourth Quarter Three Months Three Months
Information Ended Ended
($ millions, except December 31, December 31,
per unit amounts) 2006 2005 % Change
-------------------------------------------------------------------------
Daily Production Volumes
Natural gas (Mcf/day) 277,715 269,443 3%
Crude oil (bbls/day) 36,339 35,167 3%
Natural gas liquids (bbls/day) 4,467 5,045 (11%)
Total daily sales (BOE/day) 87,092 85,119 2%
Average Selling Price(1)
Natural gas (per Mcf) $ 6.58 $ 11.65 (44%)
Crude oil (per bbl) 54.53 58.41 (7%)
Natural gas liquids (per bbl) 46.15 50.56 (9%)
Per BOE 46.11 64.26 (28%)
Revenue(1) 369.5 503.2 (27%)
Per BOE 46.11 64.26 (28%)
Operating Expenses 68.3 57.1 20%
Per BOE 8.52 7.29 17%
General and Administrative Expenses 17.1 12.9(2) 33%
Per BOE 2.13 1.65(2) 29%
Net Income 110.2 150.9 (27%)
Per BOE 13.75 19.27 (29%)
Cash flow 207.1 277.9 (25%)
Per BOE 25.85 35.49 (27%)
Development Capital Spending 123.1 139.1 (12%)
Acquisitions 4.8 112.5 (96%)
Divestments 0.1 0.4 (75%)
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) Certain prior year amounts have been restated to conform with
current year presentation.
Three Year Summary of Key Measures
Overall, increased production volumes have resulted in higher oil and gas
sales, net income and cash flow from operating activities over the last three
years. The rise in crude oil and natural gas prices during 2004 and 2005
contributed to higher oil and gas sales and cash flow, however the growth of
these measures moderated in 2006 as a result of lower natural gas prices. The
following table provides a summary of net income, cash flow and other key
measures.
($ millions, except per unit amounts) 2006 2005 2004
-------------------------------------------------------------------------
Oil and gas sales(1) $ 1,572.7 $ 1,523.7 $ 1,124.6
Net income 544.8 432.0 258.3
Per unit (Basic)(2) 4.48 3.96 2.60
Per unit (Diluted) 4.47 3.95 2.60
Cash flow from operating activities 863.7 774.6 555.1
Per unit (Basic)(2) 7.10 7.10 5.59
Cash distributions 614.3 498.2 423.3
Per unit (Basic)(2) 5.05 4.57 4.26
Payout ratio 71% 64% 76%
Total assets 4,203.8 4,130.6 3,180.7
Long-term debt, net of cash 679.7 649.8 585.0
-------------------------------------------------------------------------
(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 the
actual monthly distributions of $5.04 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 trust we have a declining asset base and therefore rely
on acquisitions and ongoing development activities to replace production and
add additional reserves. Our future oil and natural gas production and
reserves are highly dependent on our success in exploiting our asset base and
acquiring additional reserves. To the extent we are unsuccessful in these
activities our cash distributions could be reduced.
Acquisitions and development activities 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 will be reduced.
Should external sources of capital become limited or unavailable, our ability
to make the necessary acquisitions and development expenditures to maintain or
expand our asset base may be impaired and the amount of cash distributions may
be reduced.
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.
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 2006 cash distributions of $614.3 million were funded entirely
through cash flow of $863.7 million. Our payout ratio, which is calculated as
cash distributions divided by cash flow, was 71% for 2006 compared to 64% in
2005.
After consideration of cash distributions, the balance of our 2006 cash
flow of $249.4 million was used to fund approximately 47% of our net capital
expenditures. Our remaining net capital expenditures of $296.5 million were
financed from the proceeds of our March 2006 equity issue and through
additional debt. For more information, refer to the Capital Expenditures
section of the MD&A.
In aggregate, our 2006 cash distributions of $614.3 million and our net
capital expenditures of $526.4 million totaled $1,140.7 million, or
approximately 132% of our cash flow of $863.7 million. We rely on access to
capital markets to the extent cash distributions and net capital expenditures
exceed 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, especially when we are investing capital in opportunities
that do not immediately generate cash flow (such as our Joslyn oil sands
project) that this relationship will vary. In the oil and gas sector, because
of the nature of reserve reporting, the natural reservoir declines and the
risks involved in capital investment, it is difficult to distinguish between
capital spent on maintaining productive capacity and capital spent on growth
opportunities. Therefore we do not disclose maintenance capital separate from
development capital spending.
For the year ended December 31, 2006 our cash distributions exceeded our
net income by $69.5 million (2005 - $66.2 million). Net income includes
$318.9 million of non-cash items (2005 - $342.6 million) such as DDA&A and
future income taxes that do not reduce our cash flow from operations. Charges
such as DDA&A are not a good proxy for the cost of maintaining our productive
capacity as they are based on the historical costs of our PP&E and not the
fair market value of replacing those assets within the context of the current
commodity price environment. Future income taxes can fluctuate from period to
period as a result of changes in tax rates, or based on the royalty, interest
and dividends from our operating subsidiaries to the Fund, all of which are
not indicative of the productive capacity of our entity. The level of
investment in a given period may not be sufficient to replace productive
capacity given the natural declines associated with oil and natural gas
assets. In these instances a portion of the cash distributions paid to
unitholders would represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income.
($ millions, except per unit amounts) 2006 2005
-------------------------------------------------------------------------
Cash flow from operating activities: $ 863.7 $ 774.6
Use of cash flow:
Cash distributions $ 614.3 $ 498.2
Capital expenditures 249.4 276.4
-------------------------------------------------------------------------
$ 863.7 $ 774.6
Excess of cash flow over cash distributions $ 249.4 $ 276.4
Net income $ 544.8 $ 432.0
Shortfall of net income over cash
distributions $ (69.5) $ (66.2)
Cash distributions per weighted average
trust unit $ 5.05 $ 4.57
Payout ratio(1) 71% 64%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow from operating
activities.
Asset Retirement Costs
Actual asset retirement costs incurred in the period are deducted for
purposes of calculating cash flow. Differences between actual site restoration
costs incurred and the amortization of the capitalized asset retirement cost
and accretion of the asset retirement obligation are discussed in the Asset
Retirement Obligations section of the MD&A and Note 4.
Long-Term Debt
Long-term debt, net of cash, at December 31, 2006 was $679.7 million, an
increase of $29.8 million from December 31, 2005. Long-term debt at
December 31, 2006 is comprised of $348.5 million of bank indebtedness and
$331.3 million of senior unsecured notes.
Our working capital, excluding cash, at December 31, 2006 increased
$46.1 million compared to December 31, 2005. Current liabilities were higher
in 2005 primarily due to the recording of our commodity financial instruments
at fair value.
We continue to maintain a conservative balance sheet as demonstrated
below:
Year ended Year ended
Dec. 31, Dec. 31,
Financial Leverage and Coverage 2006 2005
-------------------------------------------------------------------------
Long-term debt to trailing cash flow 0.8 x 0.8 x
Cash flow to interest expense 26.8 x 30.0 x
Long-term debt to long-term debt plus equity 20% 21%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
Cash flow and interest expense are 12-months trailing.
Enerplus has an $850 million bank credit facility (the "Bank Credit
Facility") through its wholly-owned subsidiary EnerMark Inc. The Bank Credit
Facility is an unsecured, covenant-based, three-year committed credit
agreement with nine North American banks. We have the ability to extend the
facility each year or repay the entire balance at the end of the three-year
term. At December 31, 2006 we had $501.5 million of available borrowing
capacity under this facility, which currently extends to November, 2009. This
bank debt 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.
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 operating companies to make
payments to the Fund and consequently the Fund's ability to make distributions
to the unitholders may be restricted. As at December 31, 2006 we are in
compliance with our debt covenants. Refer to our 2006 Annual Information Form
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 2007 through a combination of cash
flow retained by the business and debt. A portion of our $410.0 million
development capital budget for 2007 is discretionary and could be revised
downward in the event of a commodity price downturn or similar economic event.
Commitments
We have contracted to transport natural gas with various pipelines
totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends until
2015. We also have a contract to transport a minimum of 2,480 bbls/day of
crude oil until 2010. These transportation contracts will cost approximately
$6.4 million in 2007.
Approximately 35% 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.
Our office lease commitments expire between November 2009 and January
2011. Annual costs of these lease commitments, which include rent and
operating fees, amount to approximately $6.7 million in 2007. The Fund's
commitments, contingencies, and guarantees are more fully described in
Note 11.
Enerplus has the following minimum annual commitments including long-
term debt:
Total
Minimum Annual Commitment Each Year Committed
------------------------------------------------ after
($ millions) Total 2007 2008 2009 2010 2011 2011
-------------------------------------------------------------------------
Bank credit
facility $348.5(1) $ - $ - $348.5 $ - $ - $ -
Senior
unsecured
notes 331.3(1) - - - 53.7 66.3 211.3
Pipeline
commitments 28.5 6.4 5.8 3.0 2.4 2.2 8.7
Office lease 20.9 6.7 6.8 6.7 0.6 0.1 -
-------------------------------------------------------------------------
Total
commit-
ments(2) $ 729.2 $ 13.1 $ 12.6 $358.2 $ 56.7 $ 68.6 $ 220.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Interest payments have not been included since future debt levels
and interest rates are not known at this time.
(2) Crown and surface royalties, lease rentals, mineral taxes, and
abandonment and reclamation costs (hydrocarbon production rights)
have not been included as amounts paid depend on future ownership,
production, prices and the legislative environment.
Accumulated Deficit
We have historically paid cash distributions in excess of accumulated
earnings as cash distributions are based on cash flow generated in the period
whereas accumulated earnings are based on net income which includes non-cash
items such as DDA&A charges, financial contract gains and losses, unit based
compensation charges and future income tax provisions.
Trust Unit Information
We had 123,151,000 trust units outstanding at December 31, 2006 compared
to 117,539,000 trust units at December 31, 2005. The weighted average number
of trust units outstanding during 2006 was 121,588,000 (2005 - 109,083,000).
At February 10, 2007 we had 123,253,000 trust units outstanding.
On March 20, 2006 we 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).
On August 9, 2005 we announced the closing of a subscription receipt
financing related to the Lyco acquisition. A total of 10,637,500 subscription
receipts were issued at a price of CDN$46.25 per receipt for gross proceeds of
approximately $492.0 million. With the closing of the Lyco acquisition on
August 30, 2005, subscription receipt holders received one trust unit for each
subscription receipt held along with the August 2005 cash distribution of
$0.37 per trust unit. The distribution paid to subscription receipt holders
has been included in cash distributions.
On July 1, 2005 we acquired all of the issued and outstanding shares of
TriLoch in exchange for 1,633,000 trust units, a value of approximately
$69.1 million after issuance costs.
In addition 1,242,000 trust units (2005 - 1,144,000) were issued pursuant
to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan
("DRIP") and the trust unit rights plans, net of redemptions. This resulted in
$55.9 million (2005 - $40.4 million) of additional equity to the Fund.
SUMMARY 2007 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 2007 outlook should be taken within the context of the
current commodity price environment.
The following summarizes Enerplus' 2007 guidance as provided throughout
this news release. 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 2007
Expectations Target Comments
-------------------------------------------------------------------------
Average annual production 85,000 BOE/day Assumes no new acquisitions
or dispositions
Exit rate December 86,000 BOE/day Assumes $410 million
2007 production development capital
spending
2007 production mix 54% gas, 42% oil,
4% NGL
Average royalty rate 19% Percentage of gross
unhedged sales
Operating costs $8.45/BOE
G&A costs $2.40/BOE Includes non-cash charges
of $0.30/BOE (unit rights
plan)
U.S. income and 15% Applied to net cash flow
withholding tax - generated by U.S.
cash costs operations and assumes
repatriation of the funds
to Canada after U.S.
development capital
spending
Average interest cost 5.0% Based on current fixed
rates and forward market
Payout ratio 60% -90%
Development capital $410 million Based on current plans and
spending price environment
-------------------------------------------------------------------------
Over time we have reduced our reliance on acquisitions to supplement
production declines by focusing our efforts on development capital
opportunities within our existing asset base. We expect to be able to
essentially maintain production in 2007 through internally generated
development efforts without relying on new acquisitions.
We expect our 2007 development capital spending to be $410 million, which
is 17% lower than our 2006 spending. We plan to continue to withhold a portion
of our cash flow to finance this capital program and we expect the payout
ratio to be within our 60-90% guidance range. We believe it is important to
maintain a conservative balance sheet as a defense against commodity price
changes and to be positioned to capture acquisition opportunities.
We will continue to focus on low-risk development opportunities and
review our risk management strategies in response to changing prices and the
economics of our acquisition and development projects.
For 2007, we estimate that 95% of cash distributions will be taxable and
5% will be a tax-deferred return of capital for our Canadian unitholders. For
our U.S. unitholders, we estimate that 90% of cash distribution will be
taxable and 10% will be a tax-deferred return of capital.
We are encouraged by the results from our 2005 acquisitions which have
been fully integrated with our existing staff and systems. The establishment
of an office in Denver continues to enhance our growing presence in the U.S.
oil and gas market.
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund is available
under our profile on the SEDAR website at www.sedar.com, on the EDGAR website
at www.sec.gov and at www.enerplus.com. Readers should review the risk factors
regarding our business and operations contained in our publicly filed
documents including our Annual Information Form.
UNAUDITED CONSOLIDATED BALANCE SHEETS
As at December 31 (CDN$ thousands) 2006 2005
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 124 $ 10,093
Accounts receivable 175,454 170,623
Deferred financial assets (Note 2) 23,612 49,874
Other current (Note 10) 6,715 26,751
-------------------------------------------------------------------------
205,905 257,341
Property, plant and equipment (Note 3) 3,726,097 3,650,327
Goodwill (Note 6) 221,578 221,234
Other assets (Notes 7 and 10) 50,224 1,721
-------------------------------------------------------------------------
$ 4,203,804 $ 4,130,623
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 284,286 $ 316,875
Distributions payable to unitholders 51,723 49,367
Deferred credits (Note 2) - 57,368
-------------------------------------------------------------------------
336,009 423,610
-------------------------------------------------------------------------
Long-term debt (Note 7) 679,774 659,918
Future income taxes (Note 9) 331,340 442,970
Asset retirement obligations (Note 4) 123,619 110,606
-------------------------------------------------------------------------
1,134,733 1,213,494
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 8)
Trust Units
Authorized: Unlimited
Issued and Outstanding: 2006 - 123,150,820
2005 - 117,539,331 3,713,126 3,410,614
Accumulated deficit (971,085) (901,527)
Cumulative translation adjustment (Note 1(j)) (8,979) (15,568)
-------------------------------------------------------------------------
2,733,062 2,493,519
-------------------------------------------------------------------------
$ 4,203,804 $ 4,130,623
-------------------------------------------------------------------------
-------------------------------------------------------------------------
UNAUDITED CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
For the year ended December 31 (CDN$ thousands) 2006 2005
-------------------------------------------------------------------------
Accumulated income, beginning of year $ 1,408,178 $ 976,137
Net income 544,782 432,041
-------------------------------------------------------------------------
Accumulated income, end of year $ 1,952,960 $ 1,408,178
Accumulated cash distributions, beginning
of year $(2,309,705) $(1,811,500)
Cash distributions (614,340) (498,205)
-------------------------------------------------------------------------
Accumulated cash distributions, end of year $(2,924,045) $(2,309,705)
-------------------------------------------------------------------------
Accumulated deficit, end of year $ (971,085) $ (901,527)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
UNAUDITED CONSOLIDATED STATEMENTS OF INCOME
For the year ended December 31
(CDN$ thousands except per trust unit amounts) 2006 2005
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 1,595,324 $ 1,550,569
Royalties (293,161) (296,983)
Derivative instruments (Notes 2 and 10)
Financial contracts - qualified hedges - (27,256)
Other financial contracts (3,226) (82,664)
Other income 2,465 11,064
-------------------------------------------------------------------------
1,301,402 1,154,730
-------------------------------------------------------------------------
Expenses
Operating 251,239 216,808
General and administrative (Note 8(b)) 59,937 40,375
Transportation 22,611 26,915
Interest on long-term debt (Note 7) 32,168 25,791
Foreign exchange (gain)/loss (528) 1,677
Depletion, depreciation, amortization
and accretion 481,598 386,545
-------------------------------------------------------------------------
847,025 698,111
-------------------------------------------------------------------------
Income before taxes 454,377 456,619
Capital taxes 3,393 6,486
Current taxes 18,236 2,764
Future income tax (recovery)/expense (Note 9) (112,034) 15,328
-------------------------------------------------------------------------
Net Income $ 544,782 $ 432,041
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 4.48 $ 3.96
Diluted $ 4.47 $ 3.95
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)
Basic 121,588 109,083
Diluted 121,858 109,371
-------------------------------------------------------------------------
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the year ended December 31 (CDN$ thousands) 2006 2005
-------------------------------------------------------------------------
Operating Activities
Net income $ 544,782 $ 432,041
Non-cash items add/(deduct):
Depletion, depreciation, amortization
and accretion 481,598 386,545
Non-cash financial contracts (Note 2) (31,106) (32,679)
Non-cash foreign exchange (32) (2,036)
Unit based compensation (Note 8) 6,323 3,040
Future income tax (Note 9) (112,034) 15,328
Asset retirement obligations settled (Note 4) (11,514) (7,829)
-------------------------------------------------------------------------
878,017 794,410
Increase in non-cash operating working capital (14,321) (19,777)
-------------------------------------------------------------------------
Cash flow from operating activities 863,696 774,633
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue costs (Note 8) 296,189 507,209
Cash distributions to unitholders (614,340) (498,205)
Increase in bank credit facilities (Note 7) 19,888 76,963
Decrease in non-cash financing working capital 2,356 12,924
-------------------------------------------------------------------------
Cash flow from financing activities (295,907) 98,891
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (496,201) (373,032)
Property acquisitions (Note 5) (51,313) (123,896)
Property dispositions 1,599 66,511
Corporate acquisitions, net of cash
acquired (Note 6) - (483,014)
Purchase of investments (29,172) -
(Increase)/Decrease in non-cash investing
working capital (3,535) 51,045
-------------------------------------------------------------------------
Cash flow from investing activities (578,622) (862,386)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash 864 (1,045)
-------------------------------------------------------------------------
Change in cash (9,969) 10,093
Cash, beginning of year 10,093 -
-------------------------------------------------------------------------
Cash, end of year $ 124 $ 10,093
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ 14,060 $ 2,669
Cash interest paid $ 34,924 $ 24,220
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The management of Enerplus Resources Fund ("Enerplus" or the "Fund")
prepares the financial statements in accordance with Canadian generally
accepted accounting principles ("GAAP"). A reconciliation between
Canadian GAAP and United States of America GAAP is disclosed in Note 14.
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. 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.
(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.
(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.
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 temporary differences
between the amounts reported in the financial statements of the Fund's
corporate subsidiaries and their respective tax bases, using
substantively enacted income tax rates. The effect of a change in these
income tax rates on future income tax liabilities and assets is
recognized in income during the period that the change occurs.
(i) Financial Instruments
The Fund is exposed to market risks resulting from fluctuations in
commodity prices and interest rates in the normal course of operations.
The Fund uses various types of financial instruments to manage these
market risks. Prior to December 31, 2005, the Fund designated certain
commodity contracts and interest rate swaps as qualified hedges.
Effective December 31, 2005, the Fund elected to stop designating
commodity contracts as qualified hedges. The fair value of the former
commodity hedges has been recorded as a financial liability with an
offset to deferred financial assets. The deferred financial asset will be
amortized over the remaining lives of the associated financial contracts.
The fair value of the financial liability will be determined at each
period end with any resulting change in fair value being taken into
income in that period.
The gain or loss in fair value of all financial contracts that had not
previously qualified for hedge accounting are taken into income during
the period of change and charged to deferred credits or deferred
financial assets on the balance sheet.
Proceeds or costs realized from holding interest rate swaps are
recognized at the time each transaction under a contract is settled and
is recorded in interest expense. The Fund has designated the interest
rate swaps as qualified hedges and these swaps are evaluated quarterly to
ensure they effectively hedge the underlying interest rate.
(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 as part of unitholders' equity.
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. DEFERRED FINANCIAL ASSETS AND DEFERRED CREDITS
The deferred financial assets of $23,612,000 at December 31, 2006 consist
of the fair value of the financial instruments of $49,268,000 less the
related deferred premiums of $25,656,000.
Deferred Financial Assets ($ thousands)
-------------------------------------------------------------------------
Fair value of financial instruments
Deferred financial assets as at December 31, 2005 $ 49,874
Deferred financial credits as at December 31, 2005 (57,368)
Change in fair value - other financial contracts(1) 80,980
Amortization of deferred financial assets(2) (49,874)
-------------------------------------------------------------------------
$ 23,612
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Changes in the fair value of financial contracts that do not qualify
for hedge accounting are taken into income during the period as
other financial contracts and reflected as an increase or decrease in
the deferred financial asset or liability.
(2) Represents the amortization of the fair value of financial contracts
on December 31, 2005 for which hedge accounting is no longer applied.
These deferred financial assets are fully amortized at December 31,
2006.
The following table summarizes the income statement effects of other
financial contracts:
Other Financial Contracts ($ thousands) 2006 2005
-------------------------------------------------------------------------
Change in fair value $ (80,980) $ (35,823)
Amortization of deferred financial assets 49,874 3,144
Realized cash costs, net 34,332 115,343
-------------------------------------------------------------------------
Other financial contracts $ 3,226 $ 82,664
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the year ended December 31, 2006, the Fund realized cash costs of
$nil from commodity financial contracts that qualified as hedges compared
to cash costs of $27,256,000 (net gains and losses) during 2005.
3. PROPERTY, PLANT AND EQUIPMENT
($ thousands) 2006 2005
-------------------------------------------------------------------------
Property, plant and equipment $ 5,855,511 $ 5,306,137
Accumulated depletion, depreciation and
accretion (2,129,414) (1,655,810)
-------------------------------------------------------------------------
Net property, plant and equipment $ 3,726,097 $ 3,650,327
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development G&A of $14,111,000 (2005 - $11,571,000) is
included in PP&E and the depletion and depreciation calculation includes
future capital costs of $472,567,000 (2005 - $464,423,000) included in
our reserve reports. Excluded from PP&E for the depletion and
depreciation calculation is $81,183,000 (2005 - $61,795,000) related to
the Joslyn development project that has not commenced commercial
production.
An impairment test calculation was performed on a country by country
basis on the PP&E values at December 31, 2006 in which the estimated
undiscounted future net cash flows associated with the proved reserves
exceeded the carrying amount of the Fund's PP&E.
The following table outlines benchmark prices and the exchange rate used
in the impairment tests for both Canadian and U.S. cost centres at
December 31, 2006:
Natural Gas
WTI Crude Exchange Edm Light 30 day spot
Oil(1) Rate Crude(1) @ AECO(1)
Year US$/bbl US$/CDN$ CDN$/bbl CDN$/Mcf
-------------------------------------------------------------------------
2007 $ 65.73 $ 0.87 $ 74.10 $ 7.72
2008 68.82 0.87 77.62 8.59
2009 62.42 0.87 70.25 7.74
2010 58.37 0.87 65.56 7.55
2011 55.20 0.87 61.90 7.72
Thereafter + 2.0% 0.87 + 2.0% + 2.0%
-------------------------------------------------------------------------
(1) Actual prices used in the impairment test were adjusted for commodity
price differentials specific to the Fund
4. ASSET RETIREMENT OBLIGATIONS
Total future asset retirement obligations were estimated by management
based on the Fund's net ownership interest in wells and facilities,
estimated costs to abandon and reclaim the wells and facilities and the
estimated timing of the costs to be incurred in future periods. The Fund
has estimated the net present value of its total asset retirement
obligations to be $123,619,000 at December 31, 2006 compared to
$110,606,000 at December 31, 2005 based on a total liability of
$436,663,000 and $422,045,000 respectively. These payments are expected
to be made over the next 66 years with the majority of costs incurred
between 2036 and 2045. To calculate the present value of the asset
retirement obligations for 2006 the Fund used a weighted credit-adjusted
rate of approximately 6.3% and an inflation rate of 2.0%, the same as for
2005. Settlements during the year approximated our estimates and as a
result, no gains or losses were recognized.
Following is a reconciliation of the asset retirement obligations:
($ thousands) 2006 2005
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year $ 110,606 $ 105,978
Changes in estimates 12,757 8,764
Acquisition and development activity 5,574 6,791
Dispositions (45) (9,413)
Asset retirement obligations settled (11,514) (7,829)
Accretion expense 6,241 6,315
-------------------------------------------------------------------------
Asset retirement obligations, end of year $ 123,619 $ 110,606
-------------------------------------------------------------------------
-------------------------------------------------------------------------
5. PROPERTY ACQUISITIONS
Assets of Sleeping Giant LLC ("Sleeping Giant")
On October 4, 2005 the Fund acquired all ownership interests and retired
the debt of Sleeping Giant, a private U.S. company holding additional
working interests in certain properties of Lyco Energy Corporation for
total cash consideration of $111,914,000 which was financed through
existing credit facilities. The fair value of this consideration was
allocated to cash and positive working capital assumed of $5,754,000 and
PP&E of $106,160,000. This acquisition has been accounted for as an asset
acquisition. The operating results of Sleeping Giant subsequent to
October 4, 2005 are included in the Fund's consolidated financial
statements.
6. CORPORATE ACQUISITIONS
The allocation to the fair value of the assets acquired and liabilities
assumed plus the future income tax cost are summarized as follows:
2005 2005
($ thousands) Lyco TriLoch
-------------------------------------------------------------------------
Property, plant and equipment $ 506,379 $ 77,786
Goodwill (with no tax base) 179,019 18,450
Future income taxes (179,019) (18,450)
-------------------------------------------------------------------------
506,379 77,786
Cash 27,231 -
Non-cash working capital deficiency (31,664) (399)
-------------------------------------------------------------------------
Net assets acquired $ 501,946 $ 77,387
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Goodwill is comprised of the following:
Goodwill ($ thousands) 2006 2005
-------------------------------------------------------------------------
Balance, beginning of year $ 221,234 $ 29,082
Lyco acquisition - 179,019
TriLoch acquisition - 18,450
Foreign exchange(1) 344 (5,317)
-------------------------------------------------------------------------
Balance, end of year $ 221,578 $ 221,234
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The foreign exchange results from the translation of Lyco goodwill at
the period end rate.
Lyco Energy Corporation ("Lyco")
On August 30, 2005 the Fund acquired all the outstanding common shares
and retired the debt including all outstanding mandatorily redeemable
preferred shares of Lyco, a private U.S. company operating in the states
of Montana and North Dakota. Total consideration was approximately
$501,946,000, and the Fund assumed a net working capital deficiency of
$4,433,000. Goodwill of $179,019,000 was recorded based on the excess of
the consideration paid over the value assigned to the identifiable assets
and liabilities including the future income tax liability. The
acquisition, which was financed through an equity offering and available
credit facilities, has been accounted for using the purchase method of
accounting for business combinations. Results from the operations of Lyco
subsequent to August 30, 2005 are included in the Fund's consolidated
financial statements.
TriLoch Resources Inc. ("TriLoch")
On July 1, 2005 the Fund acquired all the outstanding common shares of
TriLoch, a public Alberta corporation operating in southern Alberta, in
exchange for 1,632,516 trust units of the Fund with a recorded value of
$69,088,000. The trust unit value was based on the weighted average price
of the Fund's trust units on the Toronto Stock Exchange during the five
day trading period surrounding the announcement of the TriLoch
transaction. Total consideration was $77,387,000 consisting of units,
deal costs and the retirement of TriLoch's bank indebtedness. The Fund
also assumed a working capital deficiency of $399,000. Goodwill of
$18,450,000 has been recorded as a result of the excess of the
consideration paid over the value allocated to the identifiable assets
and liabilities including the future income tax liability. This
acquisition has been accounted for using the purchase method of
accounting for business combinations. Results from the operations of
TriLoch subsequent to July 1, 2005 are included in the Fund's
consolidated financial statements.
7. LONG-TERM DEBT
($ thousands) 2006 2005
-------------------------------------------------------------------------
Bank credit facilities(a) $ 348,520 $ 328,632
Senior notes(b)
US$175 million (issued June 19, 2002) 268,328 268,328
US$54 million (issued October 1, 2003) 62,926 62,958
-------------------------------------------------------------------------
Total long-term debt $ 679,774 $ 659,918
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus has an $850,000,000 unsecured covenant based three year term
facility and has the ability to extend the facility each year or repay
the entire balance at the end of the three year term. During 2006, the
facility was extended until November 2009. At December 31, 2006, Enerplus
had available credit of $501,480,000 under this facility. The facility is
extendible each year with a bullet payment required at the end of the
three year term. Various borrowing options are available under the
facility including prime rate based advances and bankers' acceptance
loans. This facility carries floating interest rates that are expected to
range between 55.0 and 110.0 basis points over bankers' acceptance rates,
depending on Enerplus' ratio of senior debt to earnings before interest,
taxes and non-cash items. The effective interest rate on the facility for
the year ended December 31, 2006 was 4.8% (2005 - 3.4%).
(b) Senior Unsecured Notes
On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes
that mature October 1, 2015. The notes have a coupon rate of 5.46% priced
at par with interest paid semi-annually on April 1 and October 1 of each
year. Principal payments are required in five equal installments
beginning October 1, 2011 and ending October 1, 2015. Costs incurred in
connection with issuing the notes in the amount of $475,000 are
classified as deferred charges on the balance sheet and are being
amortized as a part of depletion, depreciation, amortization and
accretion ("DDA&A") over the term of the notes. At December 31, 2006, the
amount remaining to be amortized associated with these costs was $346,000
(2005 - $386,000). The notes are subject to fluctuations in foreign
exchange rates.
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. Costs incurred in
connection with issuing the notes in the amount of $1,892,000 are
classified as deferred charges on the balance sheet and are being
amortized to DDA&A over the term of the notes. At December 31, 2006, the
amount remaining to be amortized was $1,177,000 (2005 - $1,335,000).
Concurrent with the issuance of the notes on June 19, 2002, the Fund
entered into a cross currency swap 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%.
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. FUND CAPITAL
(a) Unitholders' Capital
Trust Units
Authorized: Unlimited number of trust units
(thousands) 2006 2005
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance before
Contributed Surplus,
beginning of year 117,539 $ 3,407,567 104,124 $ 2,826,641
Issued for cash:
Pursuant to public
offerings 4,370 240,287 10,638 466,885
Pursuant to rights
plans 640 22,974 805 24,737
Trust unit rights
incentive plan
(non-cash) -
exercised - 3,065 - 4,629
DRIP(*), net of
redemptions 602 32,928 339 15,613
Issued for acquisition
of corporate and
property interests
(non-cash) - - 1,633 69,062
-------------------------------------------------------------------------
123,151 3,706,821 117,539 3,407,567
Contributed Surplus
(Trust Unit Rights
Plan) - 6,305 - 3,047
-------------------------------------------------------------------------
Balance, end of year 123,151 $ 3,713,126 117,539 $ 3,410,614
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Distribution Reinvestment and Unit Purchase Plan
Contributed surplus ($ thousands) 2006 2005
-------------------------------------------------------------------------
Balance, beginning of year $ 3,047 $ 4,636
Trust unit rights incentive plan
(non-cash) - exercised (3,065) (4,629)
Trust unit rights incentive plan
(non-cash) - expensed 6,323 3,040
-------------------------------------------------------------------------
Balance, end of year $ 6,305 $ 3,047
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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).
On August 9, 2005 the Fund completed a Canadian equity offering of
10,637,500 subscription receipts at a price of $46.25 per subscription
receipt for gross proceeds of $491,984,000 ($466,885,000 net of issuance
costs). The subscription receipts were exchanged for an equal number of
trust units on August 30, 2005 upon the closing of the Lyco transaction.
On July 1, 2005 the Fund issued 1,632,516 trust units pursuant to the
acquisition of TriLoch valued at $42.32 per trust unit, being the
weighted average trading price of the Fund's trust units on the Toronto
Stock Exchange during the five day trading period surrounding the
announcement of the TriLoch transaction, for a recorded value of
$69,088,000 ($69,062,000 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, 2006 a total of 3,079,000 rights issued pursuant to
the Trust Unit Rights Incentive Plan ("Rights Plan") were outstanding at
an average exercise price of $48.53. This represents 2.5% of the total
trust units outstanding of which 809,000 rights, with an average exercise
price of $39.81, were exercisable. Under the Rights 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, 2006 reduced
the exercise price of the outstanding rights by $2.02 per trust unit of
which a $0.51 reduction is effective January 2007 and a $0.50 reduction
is effective April 2007. 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:
2006 2005
-------------------------------------------------------------------------
Dividend yield 9.26% 8.97%
Right's exercise price reduction $ 1.61 $ 1.43
Volatility 25.61% 21.46%
Risk-free interest rate 4.13% 3.70%
Forfeiture rate 2.80% 4.60%
-------------------------------------------------------------------------
The fair value of the rights granted under the plan during 2006 ranged
between 12% and 14% (2005 - 9% and 10%) of the underlying market price of
a trust unit on the grant date.
During the year the Fund expensed $6,323,000 or $0.05 per unit (2005 -
$3,040,000 or $0.03 per unit) of unit based compensation expense using
the fair value method. The remaining future fair value of the rights of
$10,113,000 at December 31, 2006 (2005 - $6,380,000) will be recognized
in earnings over the remaining vesting period of the rights. Activity for
the rights issued pursuant to the Rights Plan is as follows:
2006 2005
-------------------------------------------------------------------------
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 2,621 $ 42.80 2,401 $ 34.33
Granted 1,473 54.49 1,125 53.07
Exercised (640) 35.94 (805) 30.72
Cancelled (375) 46.35 (100) 37.15
-------------------------------------------------------------------------
End of year 3,079 48.53 2,621 42.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable at
the end of the year 809 $ 39.81 643 $ 32.46
-------------------------------------------------------------------------
(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, 2006. Rights vest between one and three years
and expire between four and six years.
Rights
Rights Exercise Exercisable
Outstanding Original Price at
at December 31, Exercise after Price Expiry Date December 31,
2006 (000's) Price Reductions December 31 2006 (000's)
-------------------------------------------------------------------------
10 $ 24.50 $ 18.41 2007 10
1 26.40 20.43 2008 1
38 26.09 20.33 2008 38
6 27.70 22.14 2009 6
23 33.00 27.75 2009 23
19 36.00 31.13 2009 19
192 37.62 33.14 2009 192
14 40.70 36.61 2010 1
30 37.25 33.53 2010 8
58 38.83 35.51 2010 40
387 40.80 37.83 2010 208
80 45.55 42.90 2011 9
92 44.86 42.56 2011 16
143 49.75 47.85 2011 46
566 56.93 55.44 2011 192
178 56.55 55.54 2012 -
436 54.21 53.70 2012 -
320 56.00 56.00 2012 -
486 52.90 52.90 2012 -
-------------------------------------------------------------------------
3,079 $ 50.10 $ 48.53 809
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(b) Basic and Diluted per Trust Unit Calculations
Net income per trust unit has been determined based on the following:
(thousands) 2006 2005
-------------------------------------------------------------------------
Weighted average units 121,588 109,083
Dilutive impact of rights 270 288
-------------------------------------------------------------------------
Diluted trust units 121,858 109,371
-------------------------------------------------------------------------
-------------------------------------------------------------------------
No rights were excluded in calculating the weighted average number of
diluted units for the year ended December 31, 2006. In 2005 we excluded
132,511 rights because their exercise price was greater than the annual
average unit market price of $48.08. During the last two years,
outstanding rights were the only potential dilutive instrument.
9. INCOME TAXES
(a) Enerplus Resources Fund
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 2006, the Fund had taxable income of $588,000,000 (2005 -
$451,000,000) or $4.81 per trust unit (2005 - $4.05 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.
The amounts of COGPE and issue costs remaining in the Fund at
December 31, 2006 are $466,700,000 and $35,543,000 respectively (2005 -
$466,700,000 and $40,109,000).
Proposed Tax on Income Trusts
On October 31, 2006, the Federal Government announced a new tax on
publicly traded flow through entities including Enerplus. The tax would
be applicable beginning in 2011 at the rate of 31.5% provided that
Enerplus does not exceed the guidance provided on normal growth. Enerplus
can issue up to $7.5 billion of new equity before 2011 without exceeding
the guidance on normal growth. In addition, we understand that a trust
will be able to issue equity to retire debt existing on October 31, 2006
without eroding their safe harbour equity limits.
At the present time, the proposed changes to tax legislation are not
substantively enacted. Further, the timing of the enactment or the exact
content of the proposed changes is difficult to predict. Therefore, no
amounts in respect of this matter are reflected in the future tax
liability presented on the balance sheet.
If substantively enacted, the Fund would be treated as a taxable entity
resulting in the recording of future income tax assets and liabilities.
Enerplus' future tax liability would be adjusted to include differences
between the accounting and tax bases of the trust's assets and
liabilities at the substantively enacted tax rates.
(b) Corporate Subsidiaries
The future income tax liability on the balance sheet arises as a result
of the following temporary differences:
($ 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)
Deferred hedging and other 6,963 (807) 6,156
-------------------------------------------------------------------------
Future income tax liability $ 149,066 $ 182,274 $ 331,340
-------------------------------------------------------------------------
-------------------------------------------------------------------------
($ thousands) Canadian Foreign 2005 Total
-------------------------------------------------------------------------
Excess of net book value of
property, plant and equipment
over the underlying tax bases $ 302,610 $ 183,355 $ 485,965
Asset retirement obligations (37,976) - (37,976)
Deferred hedging and other (1,925) (3,094) (5,019)
-------------------------------------------------------------------------
Future income tax liability $ 262,709 $ 180,261 $ 442,970
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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) 2006 2005
-------------------------------------------------------------------------
Income before taxes $ 454,377 $ 456,619
-------------------------------------------------------------------------
Computed income tax expense at the enacted
rate of 34.88% (38.01% for 2005) $ 158,487 $ 173,564
Increase (decrease) resulting from:
Net income attributed to the Fund (197,694) (172,463)
Non-deductible crown royalties 11,878 30,652
Resource allowance (11,998) (37,047)
Amended returns and pool balances (21,446) 16,544
Change in tax rate (35,500) -
Other 2,475 6,842
-------------------------------------------------------------------------
$ (93,798) $ 18,092
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax (recovery)/expense $ (112,034) $ 15,328
Current tax $ 18,236 $ 2,764
-------------------------------------------------------------------------
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, 2006 ($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Future income (recovery)/expense $ (113,643) $ 1,609 $ (112,034)
Current income tax - 18,236 18,236
-------------------------------------------------------------------------
For the year ended
December 31, 2005 ($ thousands) Canadian Foreign Total
-------------------------------------------------------------------------
Future income expense $ 8,708 $ 6,620 $ 15,328
Current income tax - 2,764 2,764
-------------------------------------------------------------------------
10. FINANCIAL INSTRUMENTS
The Fund's financial instruments presented on the balance sheet consist
of cash, accounts receivable, deferred financial assets, other current
assets, other assets, accounts payable, distributions payable to
unitholders, deferred credits and long-term debt.
The carrying value of cash, accounts receivable, deferred financial
assets, other assets, current liabilities and the outstanding bank credit
facility balances approximate their fair value. Other current assets are
comprised of prepaid expenses and marketable securities and other assets
are comprised of long-term investments. Marketable securities and long-
term investments are carried on the balance sheet at the lower of cost
and fair value. The fair value of the marketable securities at
December 31, 2006 exceeded the cost of these securities by $14,493,000.
The book value of other assets at December 31, 2006 of $48,700,000 was
lower than the fair value of these assets by $3,231,000.
The Fund carried US$54,000,000 of fixed rate debt. In addition, it
carried US$175,000,000 of fixed rate debt that was converted to
CDN$268,328,000 floating rate debt through a cross-currency swap with a
syndicate of financial institutions. At December 31, 2006 the fair value
of the senior unsecured notes was $62,990,000 (for the US$54,000,000
notes) and $208,217,000 (for the US$175,000,000 notes), see Note 7.
The estimated fair values have been determined based on available market
information and appropriate valuation methods. The actual amounts
realized may differ from these estimates.
(a) Credit Risk
Most of the Fund's accounts receivable relate to oil and natural gas
sales and are exposed to typical industry credit risks. The Fund manages
this credit risk by entering into sales contracts with only credit-worthy
counterparties and reviewing its exposure to individual entities on a
regular basis. The Fund is also exposed to certain losses in the event of
non-performance by counterparties to derivative financial instruments.
This credit risk is managed by the Fund by selecting financially sound
counterparties.
In 2006, approximately 15% of the Fund's oil and gas sales were made to a
AA+ rated counterparty.
(b) Interest Rate Risk
The Fund is exposed to movements in interest rates. Long-term debt is
comprised of both variable rate bank facilities and fixed rate senior
notes. The Fund monitors the interest rate forward market and through the
use of interest rate swaps along with the fixed-rate notes has fixed the
interest rate on approximately 20% of its debt. See part (d) below.
(c) Currency Risk
The Fund is exposed to fluctuations in foreign currency as a result of
its U.S. operations and the issuance of senior unsecured notes
denominated in U.S. dollars. Through the use of a financial swap, the
exposure on our US$175,000,000 senior unsecured notes has been converted
to Canadian dollar debt. As well, the Fund has indirect exposure to
fluctuations in foreign currency as crude oil sales and a portion of
natural gas sales are based on U.S. dollar indices. We have not entered
into any foreign currency derivatives with respect to oil and natural gas
sales.
(d) Derivative Financial Instruments
The Fund uses certain derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures. The fair
values of these instruments are based on an approximation of the amounts
that would have been paid to or received from counterparties to settle
the instruments outstanding as at December 31, 2006 with reference to
forward prices and market valuations provided by third party sources.
The fair values of derivative financial instruments are as follows:
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 January 2007 and January 2012. The fair value of the
$75,000,000 interest rate swaps as at December 31, 2006 represents an
unrealized cost of $673,000. These swaps have been designated as a cash
flow hedge for accounting purposes.
Cross Currency Interest Rate Swap
The fair value of the cross currency interest rate swap related to the
US$175,000,000 senior unsecured notes as at December 31, 2006 represents
an unrealized cost of $65,002,000 whereas the fair value of the
underlying debt instrument as at December 31, 2006 represents an
unrealized gain of $60,111,000. The cross currency swap has been
designated as a fair value hedge for accounting purposes.
Crude Oil Instruments
Enerplus has entered into the following financial option contracts to
reduce the impact of a downward movement in crude oil prices. The net
premium cost of the crude oil instruments entered into as of December 31,
2006 is $20,108,000.
The following table summarizes the Fund's crude oil risk management
positions at February 13, 2007:
WTI US$/bbl
-------------------------
Daily Fixed
Volumes Purchased Price
bbls/day Put and Swaps
-------------------------------------------------------------------------
Term
January 1, 2007 - December 31, 2007
Put 5,000 $ 71.00 -
Put 2,500 $ 68.00 -
Put(1) 2,500 $ 65.70 -
Swap(1) 2,500 - $ 66.24
-------------------------------------------------------------------------
(1) Financial contracts entered into during the fourth quarter of 2006.
Natural Gas Instruments
Enerplus has physical and financial contracts in place on its natural gas
production as described below. The net premium cost of the natural gas
instruments entered into as of December 31, 2006 is $5,548,000.
The following table summarizes the Fund's natural gas risk management
positions at February 13, 2007:
AECO CDN$/Mcf
-------------------------------------------
Daily Fixed
Volumes Purchased Sold Price
MMcf/day Sold Call Put Put and Swaps
-------------------------------------------------------------------------
Term
January 1, 2007 -
March 31, 2007
Collar 6.6 $ 11.45 $ 9.00 - -
Collar(1) 9.5 $ 9.50 $ 7.00 - -
Collar(1) 9.5 $ 10.66 $ 7.00 - -
Costless Collar 6.6 $ 11.45 $ 7.70 - -
Put(1) 6.6 - $ 7.50 - -
Put(1) 4.7 - $ 7.39 - -
January 1, 2007 -
June 30, 2007
Put(1) 4.7 - $ 7.50 - -
April 1, 2007 -
October 31, 2007
Collar 6.6 $ 10.02 $ 7.50 - -
Collar 6.6 $ 9.00 $ 7.50 - -
Collar(1) 9.5 $ 9.10 $ 7.10 - -
Collar(1) 9.5 $ 9.15 $ 7.14 - -
Collar(1) 9.5 $ 9.50 $ 7.20 - -
Costless Collar(2) 4.7 $ 8.02 $ 7.17 - -
Costless Collar(2) 4.7 $ 8.23 $ 7.28 - -
Costless Collar(2) 4.7 $ 8.20 $ 7.50
3-Way option(1) 4.7 $ 9.50 $ 7.75 $ 5.49 -
Put(1) 4.7 - $ 7.28 - -
Swap(1) 6.6 - - - $ 7.60
Swap(1) 4.7 - - - $ 7.33
Swap(1) 2.4 - - - $ 7.84
Swap(1) 2.4 - - - $ 7.96
Swap(2) 7.1 - - - $ 7.17
Swap(2) 2.4 - - - $ 7.70
Swap(2) 2.4 - - - $ 7.53
Swap(2) 2.4 - - - $ 8.35
November 1, 2007 -
March 31, 2008
Collar(1) 2.4 $ 9.95 $ 8.00 - -
3-Way option(1) 4.7 $ 10.50 $ 8.20 $ 5.70 -
Swap(1) 4.7 - - - $ 8.70
2007 - 2010
Physical (escalated
pricing) 2.0 - - - $ 2.52
-------------------------------------------------------------------------
(1) Financial contracts entered into during the fourth quarter of 2006.
(2) Financial contracts entered into during the first quarter of 2007.
Electricity Instrument
The Fund has entered into electricity swap contracts that fix the price
of electricity. These contracts have been designated as cash flow hedges
and the fair value of these instruments as at December 31, 2006
represents an unrealized gain of $1,494,000. Proceeds or costs realized
from the electricity contracts are recognized as operating costs.
The following table summarizes the Fund's electricity management
positions at February 13, 2007:
Price
Term Volumes MWh CDN$/MWh
-------------------------------------------------------------------------
January 1, 2007 - December 31, 2007 5.0 $ 61.50
January 1, 2007 - December 31, 2007 4.0 $ 62.90
January 1, 2008 - September 30, 2008 4.0 $ 63.00
-------------------------------------------------------------------------
The Fund did not enter into any new electricity contracts in the
fourth quarter of 2006.
11. COMMITMENTS AND CONTINGENCIES
(a) Pipeline Transportation
Enerplus has contracted to transport natural gas with various pipelines
totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends
until 2015. 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 until 2010.
(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, 2006 of $1,379,000.
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 November 2009 and January 2011. Annual
costs of these lease commitments, which include rent and operating fees,
amount to approximately $6,700,000.
(d) Guarantees
(i) Corporate indemnities have been provided by the Fund to all
directors and certain officers of its subsidiaries and affiliates for
various items including, but not limited to, all costs to settle
suits or actions due to their association with the Fund and its
subsidiaries and/or affiliates, subject to certain restrictions. The
Fund has purchased directors' and officers' liability insurance to
mitigate the cost of any potential future suits or actions. Each
indemnity, subject to certain exceptions, applies for so long as the
indemnified person is a director or officer of one of the Fund's
subsidiaries and/or affiliates. The maximum amount of any potential
future payment cannot be reasonably estimated.
(ii) The Fund may provide indemnifications in the normal course of
business that are often standard contractual terms to counterparties
in certain transactions such as purchase and sale agreements. The
terms of these indemnifications will vary based upon the contract,
the nature of which prevents the Fund from making a reasonable
estimate of the maximum potential amounts that may be required to be
paid. Management believes the resolution of these matters would not
have a material adverse impact on the Fund's liquidity, consolidated
financial position or results of operations.
Enerplus has the following minimum annual commitments including long-term
debt:
Total
Minimum Annual Commitment Each Year Committed
-------------------------------------------- after
($thousands) Total 2007 2008 2009 2010 2011 2011
-------------------------------------------------------------------------
Bank
credit
facility $348,520 $ - $ - $348,520 $ - $ - $ -
Senior
unsecured
notes 331,254 - - - 53,666 66,251 211,337
Pipeline
commit-
ments 28,543 6,364 5,788 2,952 2,444 2,275 8,720
Office
lease 20,917 6,745 6,828 6,702 592 50 -
-------------------------------------------------------------------------
Total
commit-
ments $729,234 $ 13,109 $ 12,616 $358,174 $ 56,702 $ 68,576 $220,057
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In addition, the Fund is involved in claims and litigation arising in the
normal course of business. The resolution of these claims is uncertain
and there can be no assurance they will be resolved in favour of the
Fund; however, management believes the resolution of these matters would
not have a material adverse impact on the Fund's liquidity, consolidated
financial position or results of operations.
12. GEOGRAPHICAL INFORMATION
As at December 31, 2006
($ 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
-------------------------------------------------------------------------
As at December 31, 2005
($ thousands) Canada U.S. Total
-------------------------------------------------------------------------
Oil and gas revenue $ 1,471,473 $ 79,096 $ 1,550,569
Capital assets 3,054,078 596,249 3,650,327
Goodwill 47,532 173,702 221,234
-------------------------------------------------------------------------
13. EVENTS SUBSEQUENT TO DECEMBER 31, 2006
On January 31, 2007, Enerplus closed the acquisition of gross overriding
royalty ("GORR") interests in the Jonah natural gas field in Wyoming for
total consideration of US$52,000,000 (CDN$60,000,000). The full amount of
the purchase price will be recorded to PP&E in 2007. This represents a
GORR of approximately 0.5% on about 650 producing natural gas wells in
the Jonah field.
5 YEAR DETAILED STATISTICAL REVIEW
($ thousands,
except per
unit amounts) 2006 2005 2004 2003 2002
-------------------------------------------------------------------------
Financial
Oil and gas
sales(1) $1,569,487 $1,413,734 $ 989,266 $ 890,011 $ 621,450
Cash
distributions
to
unitholders 614,340 498,205 423,311 372,576 237,621
Per unit 5.04 4.47 4.20 4.29 3.25
Net income 544,782 432,041 258,316 248,046 116,621
Per unit 4.48 3.96 2.60 2.88 1.62
Total net
capital
expenditures 526,387 1,010,549 813,636 312,073 361,702
Total assets 4,203,804 4,130,623 3,180,748 2,661,765 2,517,976
Long-term
debt, net of
cash 679,650 649,825 584,991 257,701 361,011
Net debt/cash
flow ratio 0.8x 0.8x 1.1x 0.6x 1.2x
-------------------------------------------------------------------------
Average
Benchmark
Pricing
AECO
natural gas
(per Mcf) $ 6.99 $ 8.48 $ 6.79 $ 6.70 $ 4.07
NYMEX
natural gas
(US$ per
Mcf) 7.26 8.55 6.09 5.54 3.25
WTI crude
oil (US$
per bbl) 66.22 56.56 41.40 31.04 26.08
CDN$/US$
exchange
rate 0.88 0.83 0.77 0.72 0.64
-------------------------------------------------------------------------
($ per BOE
except
percentage
data)
-------------------------------------------------------------------------
Oil and Gas
Economics
Net royalty
rate 19% 19% 21% 20% 21%
Weighted
average
price(2) $ 50.23 $ 52.36 $ 40.90 $ 36.94 $ 27.49
Hedging(3) (1.10) (4.90) (3.50) (1.81) (0.38)
-------------------------------------------------------------------------
Weighted
average
price(1) 49.13 47.46 37.40 35.13 27.11
Net royalty
expense 9.36 10.21 8.40 7.51 5.75
Operating
expense 8.02 7.45 7.14 6.73 5.86
-------------------------------------------------------------------------
Operating
netback 31.75 29.80 21.86 20.89 15.50
General and
adminis-
trative
expense(3) 1.71 1.28 1.06 0.95 0.70
Management fee - - - 2.29 0.94
Interest
expense, net
of interest
and other
income 0.95 0.51 0.68 0.74 0.78
Foreign
exchange(3) (0.02) 0.13 (0.01) 0.08 -
Taxes 0.70 0.31 0.24 0.26 0.23
Restoration
and
abandonment
cash costs 0.37 0.27 0.25 0.26 0.20
-------------------------------------------------------------------------
Cash flow
before
changes in
non-cash
working
capital $ 28.04 $ 27.30 $ 19.64 $ 16.31 $ 12.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of commodity derivative instruments and transportation.
(2) Net of transportation and before commodity derivative instruments.
(3) 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.
2006(1) 2005(1) 2004(1) 2003(1) 2002
-------------------------------------------------------------------------
Daily
Production
Oil Sands n/a n/a n/a n/a n/a
Crude Oil
(bbls/day) 36,134 29,315 25,550 24,597 23,288
NGLs (bbls/day) 4,483 4,689 4,398 4,666 4,410
Natural Gas
(Mcf/day) 270,972 274,336 271,091 240,907 210,517
-------------------------------------------------------------------------
BOE per day 85,779 79,727 75,130 69,414 62,784
-------------------------------------------------------------------------
Proved
Reserves
Oil Sands 8,730 9,453 n/a n/a n/a
Crude Oil
(Mbls) 125,048 129,745 104,408 91,063 105,247
NGLs (Mbbls) 12,690 13,084 12,776 13,571 16,035
Natural Gas
(MMcf) 920,061 965,776 971,598 867,204 1,001,913
-------------------------------------------------------------------------
MBOE 299,812 313,245 279,117 249,168 288,267
-------------------------------------------------------------------------
Probable
Reserves(2)
Oil Sands 47,998 43,700 47,747 n/a n/a
Crude Oil
(Mbls) 34,421 31,567 26,783 27,807 16,725
NGLs (Mbbls) 3,777 3,539 3,292 3,742 2,319
Natural Gas
(MMcf) 344,025 342,518 295,698 284,096 138,789
-------------------------------------------------------------------------
MBOE 143,533 135,892 127,105 78,898 42,175
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves
Oil Sands 56,728 53,153 47,747 n/a n/a
Crude Oil
(Mbls) 159,469 161,312 131,191 118,870 121,972
NGLs (Mbbls) 16,467 16,623 16,068 17,313 18,354
Natural Gas
(MMcf) 1,264,086 1,308,294 1,267,296 1,151,300 1,140,702
-------------------------------------------------------------------------
MBOE 443,345 449,137 406,222 328,066 330,442
-------------------------------------------------------------------------
Reserve Life
Index(3)
Without Oil
Sands:
Proved (years) 9.8 9.6 10.1 10.6 12.0
Proved Plus
Probable
(years) 12.2 12.0 12.4 13.3 13.8
-------------------------------------------------------------------------
With Oil Sands:
Proved (years) 10.1 9.9 10.1 10.6 12.0
Proved Plus
Probable
(years) 14.0 13.5 14.0 13.3 13.8
-------------------------------------------------------------------------
(1) 2003 - 2006 reserve information reflects NI 51-101 reporting
methodology. Year 2002 information has not been restated for
NI 51-101.
(2) Probable reserves for year 2002 have been risked by 50%.
(3) The Reserve Life Indices (RLI) are based upon year-end proved plus
probable reserves (established reserves for the year 2002) divided by
the following year's proved and proved plus probable production
volumes as determined in the independent reserve engineering reports
for 2003 forward and management's estimate for 2002.
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"
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 amount, timing and tax treatment of cash distributions to
unitholders; future payout ratios; future tax treatment of income trusts such
as the Fund; the volumes and estimated value of the Fund's future oil and gas
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, cost estimates and
royalty rates; future development, exploration, acquisition and development
activities, and related expenditures, including with respect to both our
conventional and oil sands activities.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
the Fund including, without limitation: that the Fund will continue to conduct
its operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing (and
in certain circumstances, proposed) tax and royalty regimes; the accuracy of
the estimates of the Fund's reserve volumes; and certain commodity price and
other cost assumptions. The Fund believes the material factors, expectations
and assumptions reflected in the forward-looking information and statements
are reasonable but no assurance can be given that these factors, expectations
and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
unanticipated operating results or production declines; changes in tax or
environmental laws or royalty rates; increased debt levels or debt service
requirements; inaccurate estimation of the Fund's oil and gas reserves
volumes; limited, unfavourable or no access to capital markets; increased
costs; 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
For further information: Enerplus Resources Fund, The Dome Tower, 3000,
333-7th Avenue SW, Calgary, Alberta T2P 2Z1, Tel (403) 298-2200, Fax (403)
298-2211, Toll Free (800) 319-6462, www.enerplus.com
To request a free copy of this organization's annual report, please go to
http://www.newswire.ca and click on Tools for Investors.
Emergency Number
