Enerplus Resources Fund
TSX - ERF.un
NYSE - ERF
CALGARY, May 4 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased to
announce our results from operations for the period ending March 31, 2007.
Highlights are as follows:
- Our efforts during the first quarter were focused on the execution
of our internal development program and the expansion of our
operations through the acquisition of over $240 million of
additional assets in the Alberta oil sands and the United States.
- We are pleased to report that our operating and financial results to
date are essentially meeting our expectations. Production volumes
averaged approximately 86,000 BOE/day, up slightly over the first
quarter of 2006 and in line with our 2007 full year guidance of
85,000 BOE/day.
- Cash flow from operations was slightly ahead of last year at
$193.2 million compared to $189.3 million in the first quarter of
2006.
- Monthly cash distributions to unitholders were $0.42 per unit, a
level that has been maintained over the past 19 months, and totaled
$1.26 per unit for the quarter.
- Through our development capital program, we invested $110 million
during the first quarter with the majority of our spending focused
on crude oil. We drilled 106 gross wells, (39.7 net), which was lower
compared to the same quarter last year due to the deferral of our
shallow gas and coalbed methane drilling programs. Despite the
reduction in the total number of wells drilled, our capital spending
is in line with expectations as the costs associated with drilling
oil wells are higher than those for shallow natural gas.
- Our total capital spending for the year will increase marginally to
approximately $415 million ($410 million as per our original
guidance plus $5 million associated with the Kirby acquisition) as
we will shift $30 million from our other Canadian conventional oil
and gas projects to increase our U.S. program given the robust
economics associated with our Sleeping Giant project.
- With the decrease in capital spending programs across the industry
this year, we are starting to see deflationary pressures on the cost
of drilling and oil field services. At this point, it is premature
to indicate what savings we may see throughout 2007, but we will
continue to actively manage our costs and may see greater capital
efficiencies this year. Our operating costs at $8.53 per BOE were
slightly ahead of guidance however we continue to expect full year
operating costs to be $8.45 per BOE.
- Our payout ratio for the quarter was 82% compared to the first
quarter of 2006 at 79%. This payout ratio is calculated using GAAP
measures "cash flow from operating activities" versus the previous
non-GAAP measure "funds flow from operations". The difference is
that cash flow from operating activities includes changes in non-
cash working capital, which can introduce volatility in reported
cash flow and payout ratios. For example, during the first quarter,
we had a working capital adjustment of approximately $26 million
which reduced our cash flow from operating activities relative to
funds flow and increased our payout ratio relative to our previous
methodology.
- Our debt-to-cash flow remains at a conservative 0.8 times.
SUMMARY FINANCIAL AND OPERATING HIGHLIGHTS
All amounts are stated in Canadian dollars unless otherwise specified. In
accordance with Canadian practice, production volumes, reserve volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Where applicable, natural gas has been
converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE
rate is based on an energy equivalent conversion method primarily applicable
at the burner tip and does not represent a value equivalent at the wellhead.
Use of BOE in isolation may be misleading. Certain prior year amounts have
been restated to reflect current year presentation. Readers are also urged to
review the Management's Discussion & Analysis (MD&A) and Audited Financial
Statements for more fulsome disclosure on our operations. These reports can be
found on our website at www.enerplus.com, our SEDAR profile at www.sedar.com
and as part of our SEC filings available on www.sec.gov.
SELECTED FINANCIAL RESULTS
For the three months ended March 31, 2007 2006
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Financial (000's)
Net Income $ 107,873 $ 127,292
Cash Flow from Operating Activities 193,181 189,281
Cash Distributions to Unitholders(1) 157,671 150,245
Cash Withheld for Acquisitions and Capital
Expenditures 35,510 39,036
Debt Outstanding (net of cash) 716,860 525,864
Development Capital Spending 109,952 128,748
Acquisitions 63,423 30,027
Divestments - 19,717
Financial per Unit(2)
Net Income $ 0.88 $ 1.08
Cash Flow from Operating Activities 1.57 1.60
Cash Distributions to Unitholders(1) 1.28 1.26
Cash Withheld for Acquisitions and Capital
Expenditures 0.29 0.51
Payout Ratio(3) 82% 79%
Selected Financial Results per BOE(4)
Oil & Gas Sales(5) $ 49.08 $ 52.27
Royalties (9.12) (10.40)
Commodity Derivative Instruments 1.01 (2.98)
Operating Costs (8.55) (7.57)
General and Administrative (1.94) (1.58)
Interest and Foreign Exchange (1.32) (0.90)
Taxes (0.38) (0.68)
Restoration and Abandonment (0.42) (0.40)
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Cash Flow from Operating Activities before
changes in non-cash working capital $ 28.36 $ 27.76
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Weighted Average Number of Trust Units
Outstanding (thousands) 123,282 118,221
Debt/Trailing 12 Month Cash Flow Ratio 0.8x 0.6x
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SELECTED OPERATING RESULTS
For the three months ended March 31, 2007 2006
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Average Daily Production
Natural gas (Mcf/day) 275,714 270,765
Crude oil (bbls/day) 35,567 35,853
NGLs (bbls/day) 4,509 4,411
Total (BOE/day) 86,028 85,392
% Natural gas 53% 53%
Average Selling Price(5)
Natural gas (per Mcf) $ 7.21 $ 8.33
Crude oil (per bbl) 57.26 55.20
NGLs (per bbl) 44.09 50.57
US$ exchange rate 0.85 0.87
Net Wells drilled 40 124
Success Rate 98% 100%
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(1) Calculated based on distributions paid or payable. Cash distributions
to unitholders per unit will not correspond to the actual monthly
distributions of $1.26 as a result of using the weighted average
trust units outstanding for the period.
(2) Based on weighted average trust units outstanding for the period.
(3) Calculated as Cash Distributions to Unitholders divided by Cash Flow
from Operating Activities.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
TRUST UNIT TRADING SUMMARY TSX - ERF.un NYSE - ERF
for the three months ended March 31, 2007 (CDN$) (US$)
----------------------------------------------------------- ------------
High 52.99 44.67
Low 46.50 39.53
Close 48.70 42.22
2007 CASH DISTRIBUTIONS PER TRUST UNIT CDN$ US$
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Production Month Payment Month
January March $ 0.42 $ 0.36
February April 0.42 0.37
March May 0.42 0.38(*)
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First Quarter Total $ 1.26 $ 1.11
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(*) Calculated using an exchange rate of 1.12
OPERATIONS ACTIVITY
2007 DEVELOPMENT ACTIVITY
Three months ended
------------------
March 31, 2007
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Wells Drilled
Capital Spending
PLAY TYPE ($ millions) Gross Net
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Shallow Natural Gas & CBM 3.2 16 7.6
Crude Oil Waterfloods 17.2 16 13.3
Bakken Oil 37.8 9 6.6
Oil Sands 10.1 - -
Other Conventional Oil & Gas 41.7 65 12.2
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Total $ 110.0 106.0 39.7
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Drilling success rate - 98%
Our highest concentration of capital spending during the quarter occurred
at our Sleeping Giant Bakken oil property in the U.S. We drilled 9 gross wells
(6.6 net wells) completing our original two wells per section drilling program
in the heart of the field and continuing with our third well per section pilot
program. Successful initial results from this pilot have resulted in an
additional 9 wells being added to this program for a total of 16 wells in
2007. In addition, we acquired seismic over the eastern portion of the field
and are currently interpreting it to evaluate other opportunities in the
deeper Red River formation. We completed 5 refracs during the quarter and
added an additional 9 refracs in the latter part of the year for a total of 16
planned for 2007. Results continue to be very positive in terms of increased
rates and recovery. Given the increased opportunity and robust economics
associated with the Sleeping Giant project, we are increasing our capital
spending from $70 million to $100 million in 2007. Our total capital spending
for the year will increase marginally to approximately $415 million
($410 million as per our original guidance plus $5 million associated with the
Kirby acquisition) as we will shift $30 million from our other Canadian
conventional oil and gas projects to increased our U.S. program.
ACQUISITIONS
On January 31, we acquired additional assets in the United States with
the purchase of a gross-overriding royalty interest in the Jonah natural gas
field in Wyoming for $61.3 million. This is a modest increase to our U.S.
portfolio and establishes a new area with significant gas development
potential. The attractiveness of this asset relates to the high cash flow per
BOE as the gross-overriding royalty is not subject to deductions for operating
costs, royalties or any future development capital. This acquisition also
comes with an RLI of 15.9 years and significant future development
opportunities from which Enerplus will benefit but will not be required to
fund.
On March 22, we announced the acquisition of a 90% interest in the Kirby
Oil Sands Partnership located in the heart of the Athabasca oil sands fairway
of Alberta for $182.5 million. This strategic acquisition provides Enerplus
with additional long-term oil sands assets with steam assisted gravity
drainage ("SAGD") development potential that we believe will add significant
value for our unitholders in the years to come. Oil sands assets are a key
resource play for Enerplus given their lower geologic risk and the scalable
development associated with these types of assets. The addition of an operated
SAGD project compliments our existing portfolio of non-operated oil sands
assets which include the mining and SAGD projects on the Joslyn lease.
The Kirby oil sands leases cover a large land block of 43,360 gross acres
(over 67 sections of land) near several other major SAGD development projects
currently on production. An independent engineering assessment conducted by
GLJ Petroleum Consultants Ltd. ("GLJ") indicates a "best estimate" of
contingent resources of 244 million barrels of bitumen (approximately
220 million barrels net to Enerplus). Our initial development plans include a
10,000 bbl/day SAGD project (9,000 bbls/day net) starting in 2011 with further
expansion capability to a total of 30,000 - 40,000 bbls/day of gross bitumen
production (27,000 - 36,000 bbls/day net to Enerplus) over time. We expect the
project life of these SAGD developments to be in the order of 25 years. Our
initial capital requirements to bring the first 10,000 bbls/day of production
on stream are expected to be approximately $320 million net to Enerplus
including estimates for cost inflation and contingencies. Further sustaining
capital will be required over the remaining life of the projects.
The combined cost of these acquisitions was $243.8 million and was
initially funded through our existing credit facilities. In conjunction with
the Kirby transaction, we announced an equity offering of trust units which
closed April 10, 2007 raising net proceeds of $200 million in addition to a
private placement of 1.1 million units with the vendor representing
consideration of $54.7 million. This total financing of $254.7 million
maintains our healthy balance sheet and positions us to execute other
potential merger and acquisition ("M&A") opportunities through the year.
CANADIAN FEDERAL GOVERNMENT TRUST TAX PROPOSAL
We have continued our lobby efforts against the federal government's
proposal to implement a tax on income trusts as announced on October 31, 2006.
Despite recommendations from the Federal Finance Committee released in
February which offered suggestions that would have reduced the impact of this
proposal, the Conservative government has not adjusted their original proposal
and unfortunately elected to include the proposal as it existed together with
the federal budget, which was passed in the House of Commons on March 19,
2007, into an implementation bill. This bill has received first reading in the
House of Commons with the second reading and debate currently underway. Three
readings in the House of Commons are required before a bill is voted upon. We
encourage unitholders to continue to voice their concerns to their Member of
Parliament and the Prime Minister.
FEDERAL AND PROVINCIAL GREENHOUSE GAS EMISSION REDUCTION PROPOSALS
On March 8th, the Alberta government introduced amendments to the
provincial Climate Change and Emissions Management Act ("CCEMA") that would
impose facility-specific targets intended to reduce greenhouse gas emissions.
In addition, on April 26th, the Canadian federal government announced its
proposed plan to reduce emissions. Both of these plans reflect intensity based
reductions (expressed as a percentage of the facility's volume of emissions
per unit of production) versus absolute reductions and will initially impact
large, final emitters (LFEs). Under the Alberta proposal, a LFE is defined as
those facilities that are producing in excess of 100,000 tonnes of greenhouse
gases per year.
The targets are designed to reduce emission intensity measured from
different starting points under the two proposals but no earlier than 2003 for
individual LFEs. A number of mechanisms have been proposed to allow producers
to mitigate the impact where the targeted reductions are not met including
contributions to technology funds, offsetting credits earned at other outside
covered sources and credit trading. Clarification and further detail
surrounding regulations are still to come and the federal government has
stated that they will work to harmonize the federal proposals with the
provincial proposals such that they are not additive to the provincial
obligations but rather incremental.
Early assessments are that the costs to producers will be well below
$1.00 per produced barrel at targeted LFEs. We do not anticipate a significant
immediate impact on our existing operations and factored in a provision for
emission-related costs in making our Kirby acquisition that we believe
adequately reflects the impact of the proposals as put forward.
FUTURE FOCUS
We continue to focus on the business of running a successful oil and gas
operation which will serve us well regardless of structure or commodity price
environment. We have built a technically-driven organization that is creating
value for our unitholders by maximizing the potential within our existing
assets and adding strategic assets to our portfolio. We have a high quality,
long-life asset base and a robust opportunity set which supports our yield
oriented model. Approximately 50% of our production and 70% of our reserves
are resource play oriented. Our conventional oil and natural gas assets offer
approximately $2 billion of future development potential across a diverse mix
of quality assets and equates to between 4 and 5 years of development activity
based upon our current spending levels providing us with the opportunity to
maintain our production volumes over this period.
In addition to our conventional opportunity set we have the ability to
grow via our oil sands assets and future M&A activity. We have a positive long-
term price view for commodities and the acquisition of oil sands assets
supports this view. Through our recent acquisition of Kirby and our existing
interest in the Joslyn lease, we have over 443 million barrels of "best
estimate" contingent resource potential net to Enerplus as well as 57 million
barrels of proven plus probable reserves. Together these projects represent $3
billion of attractive future development potential including both initial and
sustaining capital. These projects provide us with a clear strategic advantage
over many other operators given their low geologic risk and the production and
reserve profile that lies ahead. In aggregate, our current oil sands
opportunities have the potential to add over 60,000 bbls/day of production net
to Enerplus over the next 10+ years.
Our healthy balance sheet and developments in the M&A market are
supportive of additional acquisitions this year. The Canadian M&A market is
improving for buyers and we are watching the U.S. market develop as U.S.
upstream master limited partnerships enter the market. Our acquisition
priorities this year were to acquire an operated SAGD project and to build our
U.S. business.
We believe that investor demographics, the current low interest rate
environment, the demand for yield product and our asset base will continue to
support a yield-oriented business model with a premium valuation over a
traditional exploration and production model. Our lower risk approach to the
energy business, resource play focus, and our disciplined acquisition strategy
will serve us well regardless of structure. In the event that the proposed tax
on trusts is implemented, we believe there is significant value in the four-
year tax exemption period and would utilize our tax pools and adopt the most
advantageous structure to minimize our tax liabilities beyond that time.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated
May 3, 2007 and is to be read in conjunction with:
- the MD&A and audited consolidated financial statements as at and for
the years ended December 31, 2006 and 2005; and
- the unaudited interim consolidated financial statements as at and for
the three months ended March 31, 2007 and 2006.
All amounts are stated in Canadian dollars unless otherwise specified.
All references to GAAP refer to Canadian generally accepted accounting
principles. All note references relate to the notes included with the
consolidated financial statements. In accordance with Canadian practice,
production volumes, reserve volumes and revenues are reported on a gross
basis, before deduction of crown and other royalties, unless otherwise stated.
Oil and natural gas reserves and production are presented on a company
interest basis which is not a term defined or recognized under NI 51- 101.
Therefore, our company interest reserves may not be comparable to similar
measures presented by other issuers. Where applicable, natural gas has been
converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE
rate is based on an energy equivalent conversion method primarily applicable
at the burner tip and does not represent a value equivalent at the wellhead.
Use of BOE in isolation may be misleading. Certain prior year amounts have
been restated to reflect current year presentation.
The following MD&A contains forward-looking information and statements.
We refer you to the end of the MD&A for our disclaimer on forward-looking
statements.
NON-GAAP MEASURES
Historically we used the non-GAAP measure funds flow from operations to
analyze operating performance, leverage and liquidity. We are now utilizing
the GAAP measure cash flow from operating activities ("cash flow") instead of
funds flow from operating activities. The difference is that cash flow from
operating activities includes changes in non-cash working capital and appears
on our Consolidated Statements of Cash Flows.
We also historically used the non-GAAP measure cash available for
distribution. We are now using cash distributions to unitholders ("cash
distributions") which also appears on our Consolidated Statements of Cash
Flows. Cash available for distribution was based on the twelve month
production period January through December wherein the related distributions
were paid with a two month lag or March through February respectively. Cash
distributions include amounts paid or declared during the calendar year which
relate to the twelve month production period December through November wherein
the related distributions are paid February through January.
Our payout ratio was previously calculated as cash available for
distribution divided by funds flow; however, as a result of the above-
mentioned changes, our payout ratio is now calculated as cash distributions
divided by cash flow from operating activities. This reflects the proportion
of cash flow paid out to investors and not reinvested in the business. The
term payout ratio does not have a standardized meaning as prescribed by GAAP
and therefore may not be comparable with the calculation of a similar measure
by other entities.
Refer to the Liquidity and Capital Resources section of the MD&A for
further information on cash flow, cash distributions and payout ratio.
ACCOUNTING CHANGES
Our financial statements for the first quarter of 2007 reflect a number
of new accounting standards introduced by the Canadian Institute of Chartered
Accountants ("CICA"). The implementation of these new standards impacts the
comparability of our financial results.
On January 1, 2007 we prospectively adopted CICA Handbook Sections 3855
"Financial Instruments - Recognition and Measurement", Section 3865 "Hedges"
and Section 1530 "Comprehensive Income". These standards generally require a
greater portion of the balance sheet to be measured at fair value with changes
in fair value recorded in either net income or a new earnings measurement
called other comprehensive income ("OCI"). The standards also provide new
guidance on the accounting for derivatives in hedging relationships in that
all derivatives are required to be recorded at fair value on the balance
sheet. The impact of these accounting changes on our financial statements is
summarized below:
- Previously we designated our cross currency interest rate swap
("CCIRS") as a fair value hedge. On January 1, 2007 we elected to
stop designating the CCIRS as a qualified hedge and as a result we
recorded the swap on our Consolidated Balance Sheet at fair value
with an increase of $56.0 million recorded to opening accumulated
deficit. Subsequent changes in the fair value of the interest
component of the CCIRS will be recorded in interest expense and
subsequent changes in the fair value of the foreign exchange
component of the CCIRS will be recorded in foreign exchange
gain/loss. In addition, the carrying value of the underlying
US$175,000,000 senior unsecured notes was adjusted to the January 1,
2007 fair value of $208.2 million, with a decrease of $51.3 million
recorded to opening accumulated deficit. Going forward these
debentures will be reported at amortized cost and will be translated
into Canadian dollars at the period end foreign exchange rate.
- Historically, deferred charges associated with issuing our senior
unsecured notes were being amortized to income over the term of the
debentures. On January 1, 2007 these deferred charges of $1.0 million
were recorded to the opening accumulated deficit balance.
- Previously our interest rate and electricity swaps were designated as
cash flow hedges. On January 1, 2007 we elected to stop designating
these swaps as cash flow hedges and recorded these items on our
Consolidated Balance Sheet at fair values of $(0.7) million and
$1.5 million respectively, resulting in an increase of $0.7 million
recorded to opening accumulated other comprehensive income ("AOCI").
This amount will be amortized and recorded in interest expense and
operating expense over the term of the contracts. Subsequent changes
in the fair value of the interest rate swaps will be recorded in
interest expense while subsequent changes in the fair value of the
electricity swaps will be recorded in operating expenses.
- Previously our investments in publicly traded marketable securities
were recorded on our Consolidated Balance Sheets at cost. On
January 1, 2007 these investments were recorded on our Consolidated
Balance Sheet at a fair value of $30.0 million, with an increase of
$14.3 million recorded to opening AOCI. Subsequent changes in fair
value will be recorded in OCI. The cumulative gains and losses
recorded in AOCI will be reclassified to income upon disposition of
the marketable securities.
- Amounts previously recorded in the cumulative translation adjustment
of $9.0 million at January 1, 2007 were reclassified as a decrease to
opening AOCI. Subsequent changes in the cumulative translation
adjustment will be recorded in OCI.
Upon adoption of these standards, our total assets increased by
$17.7 million and our total liabilities increased by $8.5 million.
UPDATE ON CANADIAN GOVERNMENT ANNOUNCEMENT ON INTENTION TO TAX TRUSTS
Bill C-52 "an act to implement certain provisions of the budget tabled in
Parliament on March 19, 2007" and certain other proposals including the
proposal to tax trusts, was introduced into the House of Commons on March 29,
2007 and is currently in second reading and debate. Bill C-52 would amend the
Income Tax Act such that commencing January 1, 2011 (provided that the Fund
only experiences "normal growth" and no "undue expansion") certain
distributions from the Fund will be characterized as dividends and the Fund
will be subject to tax at the same effective rate as Canadian corporations.
If Bill C-52 is "substantively enacted" as put forward, at that time a
one-time non-cash charge to earnings and a corresponding increase to the
future tax liability will be recorded. In addition, at that time we would also
present our December 31, 2006 reserves on both a pre-tax and an after- tax
basis.
See the Annual Information Form "General development of Enerplus
Resources Fund - Federal Government Pronouncements on Income Trusts" (page 4)
for further information.
OVERVIEW
During the quarter we achieved a modest increase in production to 86,028
BOE/day and increased our cash flow to $193.2 million despite decreased
natural gas prices. Development capital spending totaled $110.0 million and
remains on target with our annual guidance. On January 31, 2007, we acquired
gross-overriding royalty interests in the Jonah natural gas field in Wyoming
("Jonah") for total consideration of $61.3 million. We also entered into an
agreement to acquire a 90% interest in the Kirby Oil Sands Partnership
("Kirby"), a privately held partnership operating in the Athabasca oil sands
fairway of Alberta, for total consideration of $182.5 million ($127.8 million
in cash and $54.7 million in equity). This acquisition closed subsequent to
the quarter on April 10, 2007 concurrent with the closing of an equity
offering of 4.25 million trust units at a price of $49.55 per unit for gross
proceeds of $210.6 million.
RESULTS OF OPERATIONS
Production
During the first quarter of 2007 production volumes averaged 86,028
BOE/day representing a 1% increase over 2006 first quarter volumes of 85,392
BOE/day. For the three months ended March 31, 2007 production volumes were
weighted 53% natural gas and 47% crude oil and natural gas liquids on a BOE
basis, unchanged compared to the first quarter of 2006. Average production
volumes for the three months ended March 31, 2007 and 2006 are outlined below:
Three months ended March 31,
Daily Production Volumes 2007 2006 % Change
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Natural gas (Mcf/day) 275,714 270,765 2%
Crude oil (bbls/day) 35,567 35,853 (1%)
Natural gas liquids (bbls/day) 4,509 4,411 2%
Total daily sales (BOE/day) 86,028 85,392 1%
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Based on the results of our first quarter we are maintaining our annual
production estimate of 85,000 BOE/day and 2007 exit rate of 86,000 BOE/day.
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 the three months ended March 31, 2007
and 2006. It also compares the benchmark price indices for the same periods.
Three months ended March 31,
Average Selling Price(1) 2007 2006 % Change
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Natural gas (per Mcf) $ 7.21 $ 8.33 (13%)
Crude oil (per bbl) 57.26 55.20 4%
Natural gas liquids (per bbl) 44.09 50.57 (13%)
Per BOE $ 49.08 $ 52.27 (6%)
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(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments
Three months ended March 31,
Average Benchmark Pricing 2007 2006 % Change
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AECO natural gas - monthly
index (CDN$/Mcf) $ 7.46 $ 9.27 (20%)
AECO natural gas - daily index
(CDN$/Mcf) 7.41 7.56 (2%)
NYMEX natural gas - monthly
NX3 index (US$/Mcf) 6.96 9.07 (23%)
NYMEX natural gas - monthly
NX3 index CDN$ equivalent
(CDN$/Mcf) 8.19 10.43 (21%)
WTI crude oil (US$/bbl) 58.23 63.48 (8%)
WTI crude oil: CDN$ equivalent
(CDN$/bbl) 68.51 72.99 (6%)
US$/CDN$ exchange rate $ 0.85 $ 0.87 (2%)
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We realized an average price on our natural gas of $7.21/Mcf (net of
transportation costs) during the three months ended March 31, 2007, a decrease
of 13% from $8.33/Mcf for the same period in 2006. A warmer winter through to
February, strong industry production and high storage inventories reduced
industry pricing year-over-year. In comparison to the first quarter of 2006,
the AECO monthly index price for natural gas decreased 20% and the AECO daily
index price decreased 2%. We sell our natural gas under both month and day
AECO index contracts. Our realized natural gas price decrease of 13% during
the first quarter was comparable to the 11% average decrease of the combined
indices.
The average price we received for our crude oil during the three months
ended March 31, 2007 increased 4% to $57.26/bbl (net of transportation costs)
from $55.20/bbl during the same period in 2006. In comparison, the West Texas
Intermediate ("WTI") crude oil benchmark price, after adjusting for the change
in the US$ exchange rate, decreased 6% from the corresponding period in 2006.
The relative strength in our sales price can be attributed to improved pricing
differentials year-over-year relative to WTI for the majority of our crude oil
production.
The Canadian dollar weakened 2% against the U.S. dollar, based on the
average quarterly exchange rate, during the first quarter of 2007 compared to
the same period in 2006. As most of our crude oil and a portion of our natural
gas is priced in reference to U.S. dollar denominated benchmarks, this
movement in the exchange rate increased the Canadian dollar prices that we
realized.
Price Risk Management
While the overall energy outlook remains generally bullish long term,
there remains uncertainty as to the direction prices might move for the
remainder of 2007. Natural gas prices have the potential to fall during the
summer of 2007 given current levels of inventory, aggressive drilling in the
U.S. and increased liquefied natural gas imports to North America. Current
forecasts for a hot summer and an active hurricane season along with the
potential for lower Canadian production could offset these risks. With respect
to crude oil prices, global supply and demand are well balanced however
geopolitical events continue to strongly influence prices.
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 first quarter of 2007. Considering all of the
financial contracts transacted to date we have protected a portion of our
natural gas and crude oil sales for the period April 2007 through December
2008. We have also entered into electricity contracts for the period April
2007 through September 2008 to protect against rising electricity costs in the
Alberta power market. See Note 9 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 April 26, 2007 as a percentage of our forecasted net production
volumes:
Natural Gas Crude Oil
(CDN$/Mcf) (US$/bbl)
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April November January January
1, 2007 1, 2007 1, 2007 1, 2008
- October - March - December - December
31, 2007 31, 2008 31, 2007 31, 2008
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Floor Protection
Price (puts) $ 7.32 $ 8.60 $ 68.93 $ 67.00
% (net of
royalties) 32% 10% 33% 3%
Upside Capped
Price (calls) $ 9.07 $ 11.05 $ - $ 77.00
% (net of
royalties) 28% 10% -% 3%
Fixed Price
(swaps) $ 7.58 $ 8.70 $ 66.24 $ -
% (net of
royalties) 13% 2% 8% -%
-------------------------------------------------------------------------
Based on weighted average price (before premiums), average annual
production of 85,000 BOE/day and assuming a 19% royalty rate.
Accounting for Price Risk Management
During the first quarter of 2007, we experienced a loss of $25.6 million
on our commodity derivative instruments compared to a $0.9 million loss in the
first quarter of 2006. The $25.6 million loss experienced in the first quarter
of 2007 consisted of realized cash gains of $7.9 million and non-cash losses
of $33.5 million on our crude oil and natural gas contracts, compared to cash
costs of $22.9 million and non-cash gains of $22.0 million during the first
quarter of 2006.
The decrease in crude oil cash costs of $21.3 million is a result of the
expiration of contracts that existed during the first quarter of 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 of $9.5 million is the result of lower
natural gas prices experienced during the first quarter of 2007 combined with
fewer natural gas contracts outstanding compared to same period in 2006.
At March 31, 2007 the fair value of our commodity derivative instruments,
net of premiums, was a loss position of $9.9 million and recorded on our
balance sheet as a deferred financial liability. In comparison at December 31,
2006 the fair value of our commodity derivative instruments was a gain
position of $23.6 million and recorded on our balance sheet as a deferred
financial asset. This change in fair value (an unrealized loss on commodity
derivative instruments of $33.5 million) reflects an increase in forward
prices over this time period. As the forward markets for natural gas and crude
oil fluctuate, and new contracts are executed and existing contracts are
realized, changes in fair value are reflected as a non-
cash charge or increase to earnings. See Note 3 for details.
The following table summarizes the effects of our commodity derivative
instruments on income for the periods ended March 31, 2007 and 2006.
Risk Management
(Gains)/Losses
($ millions, Three months ended Three months ended
except per unit March 31, March 31,
amounts) 2007 2006
-------------------------------------------------------------------------
Cash (gains)/
losses:
Crude oil $ (8.4) $(2.63)/bbl $ 12.9 $ 4.00/bbl
Natural Gas 0.5 $ 0.02/Mcf 10.0 $ 0.41/Mcf
------------ ------------
Total Cash
(gains)/losses $ (7.9) $(1.01)/BOE $ 22.9 $ 2.98/BOE
Non-cash
(gains)/losses:
Change in fair
value -
financial
contracts $ 33.5 $ 4.32/BOE $ (40.3) $(5.24)/BOE
Amortization of
deferred
financial
assets - $ -/BOE 18.3 $ 2.38/BOE
------------ ------------
Total Non-cash
(gains)/losses $ 33.5 $ 4.32/BOE $ (22.0) $(2.86)/BOE
------------ ------------
Total losses $ 25.6 $ 3.31/BOE $ 0.9 $ 0.12/BOE
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenues
Crude oil and natural gas revenues for the three months ended March 31,
2007 were $380.0 million ($385.9 million, net of $5.9 million of
transportation costs) compared to $401.7 million ($407.8 million, net of
$6.1 million of transportation costs) for the same period in 2006. The
decrease of $21.7 million, or 5%, is primarily due to lower natural gas
prices, partially offset by higher crude oil prices and natural gas volumes.
Analysis of Sales
Revenue(1)
($ millions) Crude oil NGLs Natural Gas Total
-------------------------------------------------------------------------
Quarter ended
March 31, 2006 $ 178.1 $ 20.1 $ 203.5 $ 401.7
Price variance(1) 6.6 (2.7) (28.4) (24.5)
Volume variance (1.4) 0.5 3.7 2.8
-------------------------------------------------------------------------
Quarter ended
March 31, 2007 $ 183.3 $ 17.9 $ 178.8 $ 380.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Other Income
Other income for the three months ended March 31, 2007 was $14.2 million
compared to $1.1 million for the first quarter of 2006. During the first
quarter of 2007 we sold certain marketable securities which resulted in a gain
of $14.1 million. These marketable securities were historically recorded in
other current assets at a cost of $2.4 million.
Royalties
Royalties are paid to various government entities and other land and
mineral rights owners. For the three months ended March 31, 2007 royalties
decreased to $70.6 million from $80.0 million during 2006, or to 19% from 20%
of oil and gas sales, net of transportation costs, respectively. The decrease
is consistent with the lower natural gas prices during the first quarter of
2007 compared to the same period in 2006.
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 total royalties
incurred during the first quarter of 2007.
Operating Expenses
Operating expenses for the three months ended March 31, 2007 were
$8.53/BOE or $66.0 million, representing a 13% increase over $7.57/BOE in the
first quarter of 2006 and slightly higher than our annual guidance of
$8.45/BOE. Operating costs have increased primarily in the areas of repairs
and maintenance, well servicing and labour due to inflationary pressures and
certain unanticipated expenses such as $1.8 million to repair and replace
pipelines in our non-operated Mitsue area.
We continue to forecast annual operating costs of approximately
$8.45/BOE.
General and Administrative Expenses
General and administrative ("G&A") expenses were $17.1 million or
$2.21/BOE for the first quarter of 2007 compared to $13.3 million or $1.73/BOE
for the first quarter of 2006. Cash G&A expenses were $1.94/BOE in the first
quarter of 2007 compared to $1.58/BOE in the first quarter of 2006. As
expected, the increase was primarily compensation costs related to retaining
and recruiting skilled professionals and technical staff.
For the three months ended March 31, 2007 our G&A expenses included non-
cash charges for our trust unit rights incentive plan of $2.1 million or
$0.27/BOE compared to $1.2 million or $0.15/BOE for the first quarter of 2006.
These amounts are determined using a binomial lattice option-pricing model.
The increased volatility of our trust unit price combined with the increased
number of rights outstanding as a result of an increase in the number of
employees, have increased the non-cash cost of the plan.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and Administrative Costs
Three months ended March 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
Cash $ 15.0 $ 12.1
Trust unit rights incentive plan (non-cash) 2.1 1.2
-------------------------------------------------------------------------
Total G&A $ 17.1 $ 13.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Per BOE) 2007 2006
-------------------------------------------------------------------------
Cash $ 1.94 $ 1.58
Trust unit rights incentive plan (non-cash) 0.27 0.15
-------------------------------------------------------------------------
Total G&A $ 2.21 $ 1.73
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We are maintaining our guidance for G&A expenses at $2.40/BOE, including
non-cash G&A costs of approximately $0.30/BOE.
Interest Expense
Interest expense increased to $8.1 million for the first quarter of 2007
from $7.9 million during the same period of 2006. The increase was due to
higher average indebtedness due to the Jonah acquisition and higher interest
rates offset by non-cash gains.
Due to the adoption of new accounting standards (see Notes 3 and 6), our
first quarter interest expense includes a non-cash gain of $1.6 million. This
non-cash gain results from the mark-to-market changes on our interest rate
swaps, the mark-to-market change on the interest component on our CCIRS and
the amortization of the premium on our US$175 million senior unsecured notes.
At March 31, 2007 approximately 19% of our debt was based on fixed
interest rates while 81% was floating.
Capital Expenditures
During the three months ended March 31, 2007 we spent $110.0 million on
development drilling and facilities compared to $128.7 million during the same
period in 2006. We achieved a 98% success rate drilling 40 net wells during
the quarter focusing primarily on Bakken Oil, crude oil waterfloods and our
other conventional oil and gas properties.
Our property acquisitions during the first quarter of 2007 were
$63.4 million, compared to $30.0 million in 2006. The first quarter of 2007
included the Jonah acquisition for total consideration of $61.3 million. This
represented a gross-overriding royalty of approximately 0.5% on about 650
producing gas wells in the Jonah natural gas field in Wyoming. Our 2006
acquisitions primarily consisted of additional interests in the Gleneath area
for $11.7 million and additional interests in the Sleeping Giant project in
Montana for $14.6 million.
Total net capital expenditures of $174.8 million for the first quarter of
2007 compared to $139.8 million for the first quarter of 2006 are outlined
below.
Three months ended March 31,
Capital Expenditures ($ millions) 2007 2006
-------------------------------------------------------------------------
Development expenditures $ 90.8 $ 97.7
Plant and facilities 19.2 31.0
-------------------------------------------------------------------------
Development Capital 110.0 128.7
Office 1.4 0.8
-------------------------------------------------------------------------
Sub-total 111.4 129.5
Acquisitions of oil and gas properties(1) 63.4 30.0
Dispositions of oil and gas properties(1) - (19.7)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 174.8 $ 139.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Capital Expenditures financed with
cash flow $ 35.5 $ 39.1
Total Capital Expenditures financed with
debt and equity 139.3 120.2
Total non-cash consideration for 1% sale of
Joslyn project - (19.5)
-------------------------------------------------------------------------
Total Net Capital Expenditures $ 174.8 $ 139.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of post-closing adjustments.
Subsequent to March 31, 2007 we closed the acquisition of a 90% interest
in the Kirby Oil Sands Partnership, a privately held partnership operating in
the Athabasca oil sands fairway of Alberta, for total consideration of
$182.5 million consisting of $127.8 million in cash and the issuance of
1.1 million trust units at a deemed price of $49.55.
We are increasing our 2007 annual guidance by $5.0 million to
$415.0 million for development capital spending to reflect additional capital
spending associated with our Kirby acquisition.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
DDA&A of property, plant and equipment is recognized using the unit-of-
production method based on proved reserves. For the three months ended
March 31, 2007 DDA&A increased to $119.1 million or $15.38/BOE compared to
$111.6 million or $14.52/BOE during the corresponding period in 2006. The
increase in DDA&A per BOE is due to higher capital costs experienced in recent
years combined with the effect of a greater share of our production
attributable to our U.S. operations which has a higher depletion cost base.
No impairment of the Fund's assets existed at March 31, 2007 using year-
end reserves updated for acquisitions, divestitures and management's estimates
of future prices.
Asset Retirement Obligations
The following chart compares the amortization of the asset retirement
costs, accretion of the asset retirement obligation, and actual site
restoration costs incurred.
Three months ended March 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
Amortization of the asset retirement cost $ 3.4 $ 3.0
Accretion of the asset retirement obligation 1.7 1.5
-------------------------------------------------------------------------
Total Amortization and Accretion $ 5.1 $ 4.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset Retirement Obligations Settled $ 3.3 $ 3.1
-------------------------------------------------------------------------
The timing of actual asset retirement costs will differ from the timing
of amortization and accretion charges. Actual asset retirement costs will be
incurred over the next 66 years with the majority between 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 three months ended March 31, 2007 a future income tax recovery of
$23.7 million was recorded in income compared to a future income tax recovery
of $1.7 million during the same period in 2006. The increase is due to greater
taxable income being transferred through interest and royalties to the Fund
and the consequential impact of the change in accounting policy (see Note 2
for details).
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 three months ended March 31, 2007 our U.S. operations incurred
taxes (income and withholding) in the amount of $2.0 million compared to
$3.9 million for the same period in 2006. The amount of current taxes recorded
throughout the year is dependant upon the timing of both capital expenditures
and repatriation of funds to Canada. Although U.S. taxes as a percentage of
cash flow were lower in the first quarter, 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.
Net Income
Net income for the first quarter of 2007 was $107.9 million or $0.88 per
trust unit compared to $127.3 million or $1.08 per trust unit for the first
quarter of 2006. The $19.4 million decrease in net income was primarily due to
a decrease in the combined oil and gas sales (net of transportation costs) of
$21.7 million, increased risk management costs of $24.7 million, and higher
operating costs and depletion expense, partially offset by a $22.0 million
increase in future income tax recovery and an increase of $13.1 million in
other income.
Cash Flow from Operating Activities
Cash flow for the three months ended March 31, 2007 was $193.2 million or
$1.57 per trust unit compared to $189.3 million or $1.60 per trust unit for
the three months ended March 31, 2006. The increase in cash flow was primarily
a result of lower cash risk management costs offset in part by lower gas sales
along with higher operating and G&A costs. On a per unit basis it was lower
due to the issue of additional trust units associated with our acquisition
activities.
Selected Financial Results
Three months ended March 31, Three months ended March 31,
2007 2006
Non- Non-
Per BOE of Operating Cash & Operating Cash &
production Cash Other Cash Other
(6:1) Flow(1) Items Total Flow(1) Items Total
-------------------------------------------------------------------------
Production
per day 86,028 85,392
-------------------------------------------------------------------------
Weighted
average
sales
price(2) $ 49.08 $ - $ 49.08 $ 52.27 $ - $ 52.27
Royalties (9.12) - (9.12) (10.40) - (10.40)
Commodity
derivative
instruments 1.01 (4.32) (3.31) (2.98) 2.86 (0.12)
Operating
costs (8.55) 0.02 (8.53) (7.57) - (7.57)
General and
administrative (1.94) (0.27) (2.21) (1.58) (0.15) (1.73)
Interest
expense, net
of interest
income (1.25) 0.21 (1.04) (0.89) - (0.89)
Foreign
exchange
gain/(loss) (0.07) 0.01 (0.06) (0.01) (0.01) (0.02)
Capital taxes (0.12) - (0.12) (0.18) - (0.18)
Current income
tax (0.26) - (0.26) (0.50) - (0.50)
Restoration and
abandonment
cash costs (0.42) 0.42 - (0.40) 0.40 -
Depletion,
depreciation,
amortization
and accretion - (15.38) (15.38) - (14.52) (14.52)
Future income
tax recovery - 3.06 3.06 - 0.22 0.22
Gain on sale of
marketable
securities(3) - 1.82 1.82 - - -
-------------------------------------------------------------------------
Total per BOE $ 28.36 $(14.43) $ 13.93 $ 27.76 $(11.20) $ 16.56
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash Flow from Operating Activities before changes in non-cash
working capital.
(2) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(3) Gain on sale of marketable securities was a cash item however it is
included in cash flow from investing activities not cash flow from
operating activities.
Selected Canadian and U.S. Results
The following table provides a geographical analysis of key operating and
financial results for the three months ended March 31, 2007 and 2006.
Three months ended Three months ended
(CDN$ millions, March 31, March 31,
except per 2007 2006
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily
Production
Volumes
Natural gas
(Mcf/day) 266,050 9,664 275,714 265,354 5,411 270,765
Crude oil
(bbls/day) 25,330 10,237 35,567 26,339 9,514 35,853
Natural gas
liquids
(bbls/day) 4,509 - 4,509 4,411 - 4,411
Total Daily
Sales
(BOE/day) 74,180 11,848 86,028 74,976 10,416 85,392
Pricing(1)
Natural gas
(per Mcf) $ 7.21 $ 7.29 $ 7.21 $ 8.32 $ 8.61 $ 8.33
Crude oil
(per bbl) 54.94 62.99 57.26 51.69 64.93 55.20
Natural gas
liquids
(per bbl) 44.09 - 44.09 50.57 - 50.57
Capital
Expenditures
Development
capital and
office $ 73.6 $ 37.8 $ 111.4 $ 102.0 $ 27.5 $ 129.5
Acquisitions
of oil
and gas
properties 2.1 61.3 63.4 15.4 14.6 30.0
Dispositions
of oil
and gas
properties - - - (19.7) - (19.7)
Revenues
Oil and gas
sales(1) $ 315.6 $ 64.4 $ 380.0 $ 341.9 $ 59.8 $ 401.7
Royalties (57.9) (12.7)(2) (70.6) (68.6) (11.4)(2) (80.0)
Financial
contracts (25.6) - (25.6) (0.9) - (0.9)
Expenses
Operating $ 63.9 $ 2.1 $ 66.0 $ 56.5 $ 1.7 $ 58.2
General and
adminis-
trative 14.8 2.3 17.1 12.5 0.8 13.3
Depletion,
depreciation,
amortization
and accretion 91.5 27.6 119.1 85.7 25.9 111.6
Current
income taxes - 2.0 2.0 - 3.9 3.9
-------------------------------------------------------------------------
(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
Oil and gas sales, for the first quarter of 2007 increased over the
fourth quarter of 2006 as natural gas prices began to increase. Overall oil
and gas sales increased during 2005 due to increased crude oil production and
higher commodity prices, but decreased during 2006 as a result of softening
natural gas prices throughout the year. Net income has been affected by
fluctuating commodity prices and risk management costs, the fluctuating
Canadian dollar, higher operating and G&A costs, changes in future tax
provisions as well as changes to accounting policies adopted during 2005 and
2007. Furthermore, changes in the fair value of our commodity derivative
instruments along with changes in fair value of other financial instruments
cause net income to fluctuate between quarters.
Quarterly Financial Information
($ millions, except per trust unit amounts)
Net Income per trust unit
Oil and Gas ---------------------------
Sales(1) Net Income Basic Diluted
-------------------------------------------------------------------------
2007
First quarter $ 380.0 $ 107.9 $ 0.88 $ 0.87
-------------------------------------------------------------------------
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.
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 ongoing development activities and acquisitions 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.
Development activities and acquisitions may be funded internally by
withholding a portion of cash flow or through external sources of capital such
as debt or the issuance of equity. To the extent that we withhold cash flow to
finance these activities, the amount of cash distributions will be reduced.
Should external sources of capital become limited or unavailable, our ability
to make the necessary development expenditures and acquisitions to maintain or
expand our asset base may be impaired and 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.
At December 31, 2006 we changed our methodology for calculating payout
ratio to: cash distributions to unitholders divided by cash flow from
operating activities (after changes in non-cash working capital) as presented
on our Consolidated Statements of Cash Flows. As a result, fluctuations in non-
cash changes in operating working capital will continue to impact our payout
ratio from quarter to quarter.
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 the first quarter of 2007
cash distributions of $157.7 million were funded entirely through cash flow of
$193.2 million. Our payout ratio, which is calculated as cash distributions
divided by cash flow, was 82% for the three months ended March 31, 2007
compared to 79% for the same period in 2006. Cash distributions for the first
quarter of 2007 were higher as a result of the 4.25 million additional units
we issued on April 10, 2007 and the 1.1 million units issued in conjunction
with our acquisition of Kirby. Although the additional units were issued
subsequent to March 31, 2007 these units were eligible to receive the
distribution announced in March for unitholders of record at April 10, 2007.
After consideration of cash distributions, the balance of our first
quarter cash flow of $35.5 million was used to fund approximately 32% of our
$110.0 million development capital expenditures. The balance of our
development capital expenditures and our property acquisitions (which
primarily related to the Jonah acquisition of $61.3 million), were financed
initially through debt and subsequently through our equity issue of
$210.6 million which closed April 10, 2007. As a result, our debt levels were
higher throughout the first quarter of 2007 and at March 31, 2007 compared to
the previous year.
In aggregate, our 2007 first quarter cash distributions of $157.7 million
and our development capital of $110.0 million totaled $267.7 million, or
approximately 139% of our cash flow of $193.2 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 and Kirby oil
sands projects) 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 not possible 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 three months ended March 31, 2007 our cash distributions exceeded
our net income by $49.8 million (2006 - $22.9 million). Net income includes
$129.0 million of non-cash items (2006 - $89.1 million) that do not impact our
cash flow. Non-cash charges such as DDA&A are not a good proxy for the cost of
maintaining our productive capacity as they are based on the historical costs
of our PP&E and not the fair market value of replacing those assets within the
context of the current commodity price environment. Future income taxes can
fluctuate from period to period as a result of changes in tax rates, or based
on the royalty, interest and dividends from our operating subsidiaries to the
Fund, all of which are not indicative of the productive capacity of our
entity. The level of investment in a given period may not be sufficient to
replace productive capacity given the natural declines associated with oil and
natural gas assets. In these instances a portion of the cash distributions
paid to unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income.
Three months ended
March 31,
($ millions, except per unit amounts) 2007 2006
-------------------------------------------------------------------------
Cash flow from operating activities: $ 193.2 $ 189.3
Use of cash flow:
Cash distributions $ 157.7 $ 150.2
Capital expenditures 35.5 39.1
-------------------------------------------------------------------------
$ 193.2 $ 189.3
Excess of cash flow over cash distributions $ 35.5 $ 39.1
Net income $ 107.9 $ 127.3
Shortfall of net income over cash
distributions $ (49.8) $ (22.9)
Cash distributions per weighted average
trust unit $ 1.28 $ 1.27
Payout ratio(1) 82% 79%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow from operating
activities.
Long-Term Debt
Overall long-term debt at March 31, 2007 was $717.0 million, an increase
of $37.2 million from December 31, 2006. With the adoption of the financial
instrument accounting standards (see Note 2), on January 1, 2007 we adjusted
the carrying value of our US$175 million senior unsecured notes to fair value
of $208.2 million from their previous carrying value of $268.3 million, a
decrease of $60.1 million. Subsequent to this adoption entry, our total long
term debt increased by approximately $97.3 million from December 31, 2006.
Long-term debt at March 31, 2007 is comprised of $448.9 million of bank
indebtedness and $268.1 million of senior unsecured notes. Our debt levels are
higher at March 31, 2007 compared to March 31, 2006 as a result of an equity
issue in March 2006 which closed prior to the end of the first quarter. In
comparison our 2007 equity issue closed subsequent to the end of the quarter.
We continue to maintain a conservative balance sheet with a long-
term debt to trailing cash flow ratio of 0.8 times as demonstrated below:
March 31, December 31,
Financial Leverage and Coverage 2007 2006
-------------------------------------------------------------------------
Long-term debt to trailing cash flow 0.8x 0.8x
Cash flow to interest expense 26.8x 26.8x
Long-term debt to long-term debt plus equity 21% 20%
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
Cash flow and interest expense are 12-months trailing.
There has been no change to our $850 million bank credit facility or our
senior unsecured notes during the quarter. 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. At March 31, 2007 we are in compliance with our debt
covenants; the most restrictive of which allows us to have a ratio of long
term debt to trailing cash flow of 3 to 1. 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 6.
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 $415.0 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.
Trust Unit Information
We had 123,434,000 trust units outstanding at March 31, 2007 compared to
122,232,000 trust units at March 31, 2006 and 123,151,000 at December 31,
2006. The weighted average basic number of trust units outstanding during the
first quarter of 2007 was 123,282,000 (2006 - 118,221,000).
During the three months ended March 31, 2007 283,000 trust units (2006 -
323,000) were issued pursuant to the Trust Unit Monthly Distribution
Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit rights plan.
This resulted in $13.0 million (2006 - $13.4 million) of additional equity to
the Fund. For further details see Note 8.
Canadian and U.S. Taxpayers
Enerplus estimates that approximately 95% of cash distributions paid to
Canadian unitholders and 90% of cash distributions paid to U.S. unitholders
will be taxable and the remaining 5% and 10% respectively will be treated as a
tax deferred return of capital. Actual taxable amounts may vary depending on
actual distributions that are dependent upon production, commodity prices and
cash flow experienced throughout the year.
For U.S. taxpayers the taxable portion of the cash distribution is
considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers
this should be a "Qualified Dividend" eligible for the reduced tax rate. This
preferential rate of tax for "Qualified Dividends" is set to expire at the end
of 2010. On March 24, 2007, Bill 1672 was introduced into the U.S. House of
Representatives which, if enacted as presented, would make dividends from
Canadian income funds such as Enerplus ineligible for treatment as a
"Qualified Dividend". The dividends would then become a "non-qualified
dividend from a foreign corporation" subject to the normal rates of tax
commencing with dividends received after the date of enactment. The proposed
bill still requires the approval of the House of Representatives, the Senate
and the President prior to it being enacted. Therefore, we are unable to
determine when or even if the bill will become enacted as presented.
In April 2007, Enerplus estimated its non-resident ownership to be
approximately 73%.
RECENT CANADIAN ACCOUNTING PRONOUNCEMENTS
CICA Section 3862 - Financial Instruments - Disclosures
This standard requires entities to provide disclosures in their financial
statements that enable users to evaluate the significance of financial
instruments to the entity's financial position and performance. It also
requires that entities disclose the nature and extent of risks arising from
financial instruments and how the entity manages those risks.
This standard is effective for January 1, 2008 and will result in
additional disclosures for our financial instruments.
CICA Section 3863 - Financial Instruments - Presentation
This standard establishes presentation guidelines for financial
instruments and non-financial derivatives and deals with the classification of
financial instruments, from the perspective of the issuer, between liabilities
and equity, the classification of related interest, dividends, losses and
gains, and the circumstances in which financial assets and financial
liabilities are offset.
This standard is effective for January 1, 2008 and should have a minimal
impact on our reporting.
DISCLOSURE CONTROLS AND PROCEDURES
There were no changes in our internal control over financial reporting
during the quarter ended March 31, 2007 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund, including the
Fund's Annual Information Form, is available under the Fund's profile on the
SEDAR website at www.sedar.com and at www.enerplus.com.
FORWARD-LOOKING STATEMENTS
This management's discussion and analysis ("MD&A") 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 MD&A 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 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, and acquisition and development activities and related
expenditures, including with respect to both our conventional and oil sands
activities.
The forward-looking information and statements contained in this MD&A
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 MD&A 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 MD&A and in the Fund's annual information form.
The forward-looking information and statements contained in this MD&A
speak only as of the date of this MD&A, 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.
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
(CDN$ thousands) (Unaudited) 2007 2006
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 94 $ 124
Accounts receivable 190,622 175,454
Deferred financial assets (Note 3) 1,441 23,612
Other current 5,083 6,715
-------------------------------------------------------------------------
197,240 205,905
Property, plant and equipment (Note 4) 3,777,665 3,726,097
Goodwill 219,726 221,578
Other assets 47,469 50,224
-------------------------------------------------------------------------
$ 4,242,100 $ 4,203,804
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 279,556 $ 284,286
Distributions payable to unitholders 54,092 51,723
Deferred financial credits (Note 3) 76,857 -
-------------------------------------------------------------------------
410,505 336,009
-------------------------------------------------------------------------
Long-term debt (Note 6) 716,954 679,774
Future income taxes 304,421 331,340
Asset retirement obligations (Note 5) 124,095 123,619
-------------------------------------------------------------------------
1,145,470 1,134,733
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 8) 3,728,257 3,713,126
Accumulated deficit (1,026,607) (971,085)
Accumulated other comprehensive
income (Note 2) (15,525) (8,979)
-------------------------------------------------------------------------
2,686,125 2,733,062
-------------------------------------------------------------------------
$ 4,242,100 $ 4,203,804
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2007 2006
-------------------------------------------------------------------------
Accumulated income, December 31 $ 1,952,960 $ 1,408,178
Adjustment for adoption of financial
instruments standards (Note 2) (5,724) -
-------------------------------------------------------------------------
Revised opening balance, beginning of period 1,947,236 1,408,178
Net income 107,873 127,292
-------------------------------------------------------------------------
Accumulated income, end of period $ 2,055,109 $ 1,535,470
Accumulated cash distributions,
beginning of year $(2,924,045) $(2,309,705)
Cash distributions (157,671) (150,245)
-------------------------------------------------------------------------
Accumulated cash distributions,
end of period $(3,081,716) $(2,459,950)
-------------------------------------------------------------------------
Accumulated deficit, end of period $(1,026,607) $ (924,480)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2007 2006
-------------------------------------------------------------------------
Balance, beginning of period $ (8,979) $ (15,568)
Transition adjustments (Note 2):
Cash flow hedges 660 -
Marketable securities available for sale 14,252 -
Other comprehensive income (21,458) 3,059
-------------------------------------------------------------------------
Balance, end of period $ (15,525) $ (12,509)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
Three months ended
(CDN$ thousands except per trust unit amounts) March 31,
(Unaudited) 2007 2006
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 385,871 $ 407,838
Royalties (70,647) (79,971)
Commodity derivative instruments
(Notes 3 and 9) (25,606) (895)
Other income 14,160 1,068
-------------------------------------------------------------------------
303,778 328,040
-------------------------------------------------------------------------
Expenses
Operating 66,030 58,165
General and administrative (Note 8) 17,110 13,305
Transportation 5,864 6,112
Interest on long-term debt 8,115 7,896
Foreign exchange loss (Note 7) 482 154
Depletion, depreciation, amortization
and accretion 119,091 111,551
-------------------------------------------------------------------------
216,692 197,183
-------------------------------------------------------------------------
Income before taxes 87,086 130,857
Capital taxes 918 1,435
Current taxes 2,047 3,862
Future income tax recovery (23,752) (1,732)
-------------------------------------------------------------------------
Net Income $ 107,873 $ 127,292
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 0.88 $ 1.08
Diluted $ 0.87 $ 1.07
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)
Basic 123,282 118,221
Diluted 123,363 118,725
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2007 2006
-------------------------------------------------------------------------
Net income $ 107,873 $ 127,292
-------------------------------------------------------------------------
Other comprehensive income, net of tax:
Unrealized losses on marketable
securities, net of tax of $1,305 (3,156) -
Realized gains on marketable securities
included in net income, net of tax
of $2,839 (11,654) -
Gains and losses on derivatives designated
as hedges in prior periods included in net
income, net of tax of $50 (204) -
Change in cumulative translation adjustment (6,444) 3,059
-------------------------------------------------------------------------
Other comprehensive income (21,458) 3,059
-------------------------------------------------------------------------
Comprehensive income (Note 2) $ 86,415 $ 130,351
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended
March 31,
(CDN$ thousands) (Unaudited) 2007 2006
-------------------------------------------------------------------------
Operating Activities
Net income $ 107,873 $ 127,292
Non-cash items add/(deduct):
Depletion, depreciation, amortization
and accretion 119,091 111,551
Change in fair value of derivative
instruments (Note 3) 34,847 (21,985)
Unit based compensation (Note 8) 2,111 1,187
Foreign exchange on translation of
senior notes (Note 7) (2,882) 65
Future income tax (23,752) (1,732)
Amortization of senior notes premium (169) -
Reclassification adjustments from AOCI
to net income (204) -
Gain on sale of marketable securities (14,055) -
Asset retirement obligations settled
(Note 5) (3,314) (3,063)
-------------------------------------------------------------------------
219,546 213,315
Increase in non-cash operating
working capital (26,365) (24,034)
-------------------------------------------------------------------------
Cash flow from operating activities 193,181 189,281
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue
costs (Note 8) 13,020 253,680
Cash distributions to unitholders (157,671) (150,245)
Increase/(decrease) in bank
credit facilities 100,342 (132,854)
Decrease in non-cash financing
working capital 2,369 2,000
-------------------------------------------------------------------------
Cash flow from financing activities (41,940) (27,419)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (111,354) (129,560)
Property acquisitions (63,423) (30,027)
Property dispositions - 189
Proceeds on sale of marketable securities 16,467 -
Decrease/(increase) in non-cash investing
working capital 6,130 (11,433)
-------------------------------------------------------------------------
Cash flow from investing activities (152,180) (170,831)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash 909 141
-------------------------------------------------------------------------
Change in cash (30) (8,828)
Cash, beginning of period 124 10,093
-------------------------------------------------------------------------
Cash, end of period $ 94 $ 1,265
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ 3,241 $ 254
Cash interest paid $ 6,086 $ 4,523
ENERPLUS RESOURCES FUND
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars and thousands of
units except per unit amounts) (Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements of Enerplus Resources Fund
("Enerplus" or the "Fund") have been prepared by management following the
same accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2006, except
as identified in Note 2. The note disclosure requirements for annual
statements provide additional disclosure to that required for these
interim statements. Accordingly, these interim statements should be read
in conjunction with the Fund's consolidated financial statements for the
year ended December 31, 2006. The disclosures provided below are
incremental to those included in the 2006 annual consolidated financial
statements of the Fund.
2. CHANGES IN ACCOUNTING POLICIES
Financial Instruments
Effective January 1, 2007, the Fund adopted three new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook section 1530, Comprehensive Income,
Handbook Section 3855, Financial Instruments - Recognition and
Measurement, and Handbook Section 3865, Hedges. These standards were
adopted prospectively pursuant to their respective adoption provisions,
and therefore there is no effect on prior periods.
Comprehensive Income
CICA Handbook section 1530 introduces comprehensive income, which
consists of net income and other comprehensive income ("OCI"). OCI
represents changes in equity during a period arising from
transactions and other events with non-owner sources and includes
unrealized gains and losses on marketable securities classified as
available-for-sale along with unrealized foreign currency translation
gains or losses arising from self-sustaining foreign operations,
among other things. The Consolidated Statements of Comprehensive
Income include a calculation of comprehensive income for the first
quarter of 2007, while the cumulative changes in OCI are included in
the Statements of Accumulated Other Comprehensive Income (AOCI).
Financial Instruments - Recognition and Measurement
CICA Handbook section 3855 establishes the criteria for recognizing
and measuring financial assets, financial liabilities and non-
financial derivatives. Under this standard, all financial instruments
are required to be measured at fair value on recognition except for
certain related party transactions. Measurement in subsequent periods
depends on whether the financial instrument has been classified as
held-for-trading, available-for-sale, held-to-maturity, loans and
receivables, or other financial liabilities.
Financial assets and financial liabilities classified as held-for-
trading are measured at fair value with changes in fair value
recognized in net income. Financial assets classified as loans and
receivables along with financial liabilities classified as other
liabilities are measured at amortized cost using the effective
interest rate method. Financial assets classified as available-for-
sale are measured at fair value with changes in fair value recognized
in OCI. Investments in equity instruments classified as available-
for-sale that do not have a quoted price in an active market are
measured at cost. Transaction costs or fees attributable to the
acquisition, issue, or disposal of a financial asset or liability
are expensed immediately to net income.
Derivative instruments are recorded on the consolidated balance
sheets at fair value, including those derivatives that are embedded
in financial or non-financial contracts that are not closely related
to the host contracts. Changes in the fair values of derivative
instruments are recognized in net income with the exception of
derivatives that are designated as effective cash flow hedges. Refer
to the Hedges section for further detail.
Hedges
CICA Handbook section 3865 specifies the criteria and method of
accounting for each of the designated hedging strategies.
When hedge accounting is discontinued for a cash flow hedge, the
amounts previously recognized in AOCI are reclassified to net income
over the remaining term of the derivative instrument.
When hedge accounting is discontinued for a fair value hedge, the
carrying value of the hedged item is no longer adjusted. Any
difference between the carrying value and the face value or principle
amount of the hedged item is amortized to net income over the
remaining term of the original hedging relationship using the
effective interest method.
Impact upon Adoption of Sections 1530, 3855 and 3865
As a result of the adoption of these standards on January 1, 2007 the
Fund elected to stop designating its interest rate and electricity swaps
as cash flow hedges and recorded these items on the consolidated balance
sheet at their fair values with the offset recorded to opening
accumulated other comprehensive income. In addition, the Fund elected to
stop designating its cross currency and interest rate swap ("CCIRS") as a
fair value hedge and recorded the CCIRS on the consolidated balance sheet
at fair value with the offset recorded to opening accumulated deficit. In
conjunction, the underlying US$175,000,000 senior unsecured notes were
recorded at fair value with the offset recorded to opening accumulated
deficit.
The Fund's investments in marketable securities have been classified as
available-for-sale and were therefore recorded on the consolidated
balance sheet at fair value with the offset recorded to opening AOCI.
Deferred charges of $1,523,000 associated with issuance of the senior
unsecured notes were recorded to the opening accumulated deficit.
Amounts previously recorded in the cumulative translation adjustment were
reclassified into opening AOCI. Our prior year comparative statements
have been restated to reflect this change.
The Fund has recorded the following transition adjustments as of
January 1, 2007 in the Consolidated Financial Statements: (a) an increase
of $1,494,000 to deferred financial assets to record the electricity
swaps at fair value; (b) an increase to other current assets of
$14,493,000 to record publicly traded marketable securities at fair
value; (c) an increase of $1,708,000 to other assets, consisting of
$3,231,000 to record publicly traded marketable securities at fair value
less $1,523,000 to write-off the deferred charges associated with the
issuance of the senior unsecured notes; (d) an increase of $65,675,000 to
deferred financial credits to record the CCIRS and interest rates swaps
at fair value; (e) a decrease to long-term debt of $60,111,000 to record
the US$175,000,000 senior unsecured note at fair value; (f) an increase
to future income taxes of $ 2,943,000 to reflect the tax impact of the
adoption entries; (g) an increase of $5,724,000, net of taxes, to
the opening accumulated deficit; (h) recognition in AOCI of $14,912,000,
net of taxes, related to the net gains on marketable securities
classified as available-for-sale along with the fair value of the
interest rate and power swaps formerly designated as cash flow hedges. In
addition, the Fund reclassified to AOCI $8,979,000 of net unrealized
foreign currency losses that were previously presented as a separate
item in equity. These transition adjustments are summarized below.
Impact of transition adjustment on selected consolidated balance sheets
line items:
Transition adjustment
(CDN$ thousands) as at January 1, 2007
-------------------------------------------------------------------------
Deferred financial assets $ 1,494
Other current assets 14,493
Other assets 1,708
Deferred credits 65,675
Long-term debt (60,111)
Future income taxes 2,943
Accumulated deficit (5,724)
Cumulative translation adjustment 8,979
Accumulated other comprehensive income 5,933
-------------------------------------------------------------------------
As a result of these changes, net income increased by $864,000
($1,221,000 before future income taxes of $357,000) for the first quarter
of 2007. Basic and diluted per trust unit calculations for the three
months ended March 31, 2007 both increased by $0.01 as a result of the
new standards.
3. DEFERRED FINANCIAL ASSETS AND CREDITS
The deferred financial assets and credits result from recording our
derivative financial instruments at fair value. The deferred financial
credit relating to crude oil and natural gas instruments of $9,870,000 at
March 31, 2007 consists of the fair value of the financial instruments of
$9,568,000 less the related deferred premiums of $19,438,000.
Cross
Currency
Interest Interest Electricity
($ thousands) Rate Swap Rate Swaps Swaps
-------------------------------------------------------------------------
Deferred financial assets/
(credits) as at
December 31, 2006 $ - $ - $ -
Adoption of financial
instruments standards(1) (673) (65,002) 1,494
Change in fair value 181(2) (1,493)(3) (53)(4)
-------------------------------------------------------------------------
Deferred financial assets/
(credits) as at
March 31, 2007 $ (492) $(66,495) $ 1,441
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commodity
Derivative
($ thousands) Instruments Total
------------------------------------------------------------
Deferred financial assets/
(credits) as at
December 31, 2006 $ 23,612 $ 23,612
Adoption of financial
instruments standards(1) - (64,181)
Change in fair value (33,482)(5) (34,847)
------------------------------------------------------------
Deferred financial assets/
(credits) as at
March 31, 2007 $ (9,870) $(75,416)
------------------------------------------------------------
------------------------------------------------------------
(1) The adoption of the financial instruments standards on
January 1, 2007 resulted in a decrease to the deferred financial
assets balance. See Note 2 for further details.
(2) Recorded in interest expense.
(3) Recorded in foreign exchange expense (loss of $2,776) and interest
expense (gain of $1,283).
(4) Recorded in operating expense.
(5) Recorded in commodity derivative instruments (see below).
The following table summarizes the income statement effects of commodity
derivative instruments:
Three months ended
Commodity Derivative Instruments March 31,
($ thousands) 2007 2006
-------------------------------------------------------------------------
Change in fair value $ 33,482 $ (40,281)
Amortization of deferred financial assets - 18,296
Realized cash (gains) / costs, net (7,876) 22,880
-------------------------------------------------------------------------
Net cost (cash and non-cash) of commodity
derivative instruments $ 25,606 $ 895
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. PROPERTY, PLANT AND EQUIPMENT
March 31, December 31,
($ thousands) 2007 2006
-------------------------------------------------------------------------
Property, plant and equipment $ 6,022,328 $ 5,855,511
Accumulated depletion, depreciation
and accretion (2,244,663) (2,129,414)
-------------------------------------------------------------------------
Net property, plant and equipment $ 3,777,665 $ 3,726,097
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development G&A of $4,019,000 (2006 - $3,208,000) is included
in property, plant and equipment ("PP&E") for the three months ended
March 31, 2007. Excluded from PP&E for the purpose of the depletion and
depreciation calculation is $90,678,000 (2006 - $49,328,000) related to
the Joslyn development project that has not yet commenced commercial
production.
5. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the Fund's asset retirement obligations:
Three months
ended Year ended
March 31, December 31,
($ thousands) 2007 2006
-------------------------------------------------------------------------
Asset retirement obligations,
beginning of period $ 123,619 $ 110,606
Changes in estimates 1,645 12,757
Acquisition and development activity 476 5,574
Dispositions - (45)
Asset retirement obligations settled (3,314) (11,514)
Accretion expense 1,669 6,241
-------------------------------------------------------------------------
Asset retirement obligations, end of period $ 124,095 $ 123,619
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. LONG-TERM DEBT
March 31, December 31,
($ thousands) 2007 2006
-------------------------------------------------------------------------
Bank credit facilities(a) $ 448,862 $ 348,520
Senior notes(b)
US$175 million (issued June 19, 2002) 205,835 268,328
US$54 million (issued October 1, 2003) 62,257 62,926
-------------------------------------------------------------------------
Total long-term debt $ 716,954 $ 679,774
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus has an $850,000,000 unsecured covenant based three year term
facility with a bullet payment required at the end of the term, which is
currently November 18, 2009. The facility may be extended each year so
that Enerplus retains the three year term and extends its payment
obligation accordingly. 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 three months ended March 31, 2007 was 4.9% (2006 - 4.2%).
(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. The notes are
subject to fluctuations in foreign exchange rates and are translated into
Canadian dollars using the period end foreign exchange rate.
On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes
that mature June 19, 2014. The notes have a coupon rate of 6.62% priced
at par, with interest paid semi-annually on June 19 and December 19 of
each year. Principal payments are required in five equal installments
beginning June 19, 2010 and ending June 19, 2014. Concurrent with the
issuance of the notes on June 19, 2002, the Fund entered into a cross
currency interest rate swap ("CCIRS") with a syndicate of financial
institutions. Under the terms of the swap, the amount of the notes was
fixed for purposes of interest and principal repayments at a notional
amount of CDN$268,328,000. Interest payments are made on a floating rate
basis, set at the rate for three-month Canadian bankers' acceptances,
plus 1.18%.
On January 1, 2007 in conjunction with the adoption of CICA Sections 3855
and 3865, the Fund elected to stop designating the CCIRS as a fair value
hedge on the US$175,000,000 senior notes. As a result, the Fund recorded
the senior notes at their fair value of US$178,681,000 (CDN $208,217,000)
with the offset to opening accumulated deficit. In addition, the Fund
recorded a liability of $65,002,000 with the offset to opening
accumulated deficit, which represented the fair value of the CCIRS. The
premium amount of US$3,681,000, representing the difference between the
January 1, 2007 fair value and the face amount of the senior notes, will
be amortized to net income over the remaining term of the notes using the
effective interest method. The effective interest rate over the remaining
term of the senior notes is 6.16%. The senior notes are carried at
amortized cost and are translated into Canadian dollars using the period
end foreign exchange rate. At March 31, 2007 the amortized cost of the
US$175,000,000 senior notes was US$178,537,000.
7. FOREIGN EXCHANGE
Three months ended
March 31,
($ thousands) 2007 2006
-------------------------------------------------------------------------
Unrealized foreign exchange (gain)/loss on
translation of U.S. dollar denominated
senior notes $ (2,882) $ 65
Cross currency interest rate swap 2,776 -
Realized foreign exchange loss 588 89
-------------------------------------------------------------------------
Foreign exchange loss $ 482 $ 154
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The US$54,000,000 and US$175,000,000 senior unsecured notes are exposed
to foreign currency fluctuations and are translated into Canadian dollars
at the exchange rate in effect at the balance sheet date. Foreign
exchange gains and losses are included in the determination of net income
for the period.
8. FUND CAPITAL
(a) Unitholders' Capital
Trust Units
Authorized: Unlimited number of trust units
Three months ended Year ended
Issued: March 31, 2007 December 31, 2006
(thousands) Units Amount Units Amount
-------------------------------------------------------------------------
Balance before
Contributed
Surplus,
beginning of
period 123,151 $ 3,706,821 117,539 $ 3,407,567
Issued for cash:
Pursuant to
public
offerings - - 4,370 240,287
Pursuant to
rights plans 24 820 640 22,974
Trust unit rights
incentive plan
(non-cash)
- exercised - 452 - 3,065
DRIP(*), net of
redemptions 259 12,200 602 32,928
-------------------------------------------------------------------------
123,434 3,720,293 123,151 3,706,821
Contributed
Surplus (Trust
Unit Rights Plan) - 7,964 - 6,305
-------------------------------------------------------------------------
Balance,
end of period 123,434 $ 3,728,257 123,151 $ 3,713,126
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Distribution Reinvestment and Unit Purchase Plan
Three months
ended Year ended
March 31, December 31,
Contributed surplus ($ thousands) 2007 2006
-------------------------------------------------------------------------
Balance, beginning of period $ 6,305 $ 3,047
Trust unit rights incentive plan (non-cash)
- exercised (452) (3,065)
Trust unit rights incentive plan (non-cash)
- expensed 2,111 6,323
-------------------------------------------------------------------------
Balance, end of period $ 7,964 $ 6,305
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Subsequent to the quarter ended March 31, 2007 the Fund closed an equity
offering on April 10, 2007 of 4,250,000 units at a price of $49.55 per
unit for gross proceeds of $210,588,000 ($200,058,000 net of issuance
costs). These trust units were eligible for the April 20, 2007 cash
distribution paid to unitholders of record at the close of business on
April 10, 2007.
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).
(b) Trust Unit Rights Incentive Plan
As at March 31, 2007, a total of 3,160,000 rights pursuant to the Trust
Unit Rights Incentive Plan ("Rights Plan") at an average exercise price
of $48.23 were outstanding. This represents 2.6% of the total trust units
outstanding of which 950,000 rights with an average exercise price of
$41.22 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 three months ended March 31, 2007 reduced the
exercise price of the outstanding rights by $0.51 per trust unit
effective July 2007.
Activity for the rights issued pursuant to the Rights Plan is as follows:
Three months ended Year ended
March 31, 2007 December 31, 2006
------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Rights Exercise Rights Exercise
(000's) Price(1) (000's) Price(1)
-------------------------------------------------------------------------
Trust unit rights
outstanding
Beginning of
period 3,079 $ 48.53 2,621 $ 42.80
Granted 182 48.86 1,473 54.49
Exercised (24) 34.21 (640) 35.94
Cancelled (77) 50.17 (375) 46.35
-------------------------------------------------------------------------
End of period 3,160 48.23 3,079 48.53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights
exercisable at
the end of
the period 950 $ 41.22 809 $ 39.81
-------------------------------------------------------------------------
(1) Exercise price reflects grant prices less reduction in strike price
discussed above.
The Fund uses a binomial option-pricing model to calculate the estimated
fair value of rights under the plan. Non-cash compensation costs of
$2,111,000 ($0.02 per unit) related to rights issued were charged to
general and administrative expense during the three months ended
March 31, 2007 (2006 - $1,187,000, $0.01 per unit).
(c) Basic and Diluted per Trust Unit Calculations
Net income per trust unit has been determined based on the following:
Three months ended
March 31,
($ thousands) 2007 2006
-------------------------------------------------------------------------
Weighted average units 123,282 118,221
Dilutive impact of rights 81 504
-------------------------------------------------------------------------
Diluted trust units 123,363 118,725
-------------------------------------------------------------------------
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9. FINANCIAL INSTRUMENTS
(a) Fair Value of Financial Instruments
As a result of the adoption of the new financial instrument and hedging
accounting standards described in Note 2, certain financial instruments
are now measured and reported on the balance sheet at fair value which
were previously reported at amortized cost.
The fair value of a financial instrument is the amount of consideration
that would be agreed upon in an arm's-length transaction between
knowledgeable, willing parties who are under no compulsion to act. Fair
values are determined by reference to quoted bid or ask prices, as
appropriate, in the most advantageous active market for that instrument
to which we have immediate access. Where bid and ask prices are
unavailable, we would use the closing price of the most recent
transaction for that instrument. In the absence of an active market, we
determine fair values based on prevailing market rates for instruments
with similar characteristics or internal and external valuation models,
such as option pricing models and discounted cash flow analysis, that use
observable market based inputs and assumptions.
(b) Carrying Value and Fair Value of Financial Instruments
i. Cash
Cash is classified as held-for-trading and is reported at fair value.
ii. Accounts Receivable
Accounts receivable are classified as loans and are reported at amortized
cost. At March 31, 2007 the carrying value of accounts receivable
approximated their fair value.
iii. Marketable Securities
Marketable securities with a quoted market price in an active market are
classified as available-for-sale and are reported at fair value. As at
March 31, 2007 the Fund reported investments in marketable securities of
publicly traded marketable securities at a fair value of $8,769,000.
Marketable securities without a quoted market price in an active market
are reported at amortized cost. As at March 31, 2007 the Fund reported
investments in marketable securities of private companies at an amortized
cost of $38,700,000.
Marketable securities are included in other current assets or other
assets on the Consolidated Balance Sheet. Realized gains and losses on
marketable securities are included in other income.
iv. Accounts Payable & Distributions Payable to Unitholders
Accounts payable as well as Distributions payable to unitholders are
classified as other liabilities and are reported at amortized cost. At
March 31, 2007 the carrying value of these accounts approximated their
fair value.
v. Long-term debt
Bank Credit Facilities
The bank credit facilities are classified as other liabilities and are
reported at amortized cost. At March 31, 2007 the carrying value of the
bank credit facilities approximated their fair value.
US$54 million senior notes
The US$54,000,000 million senior notes, which are classified as other
liabilities, are reported at their amortized cost of US$54,000,000 and
are translated into Canadian dollars at the period end exchange rate. At
March 31, 2007 the Canadian dollar amortized cost of the senior notes was
approximately $62,257,000.
US$175 million senior notes
The US$175,000,000 million senior notes, which are classified as other
liabilities, are reported at amortized cost of $178,537,000 and are
translated into Canadian dollars at the period end exchange rate. At
March 31, 2007 the Canadian dollar amortized cost of the senior notes was
approximately $205,835,000.
vi. Derivative Financial Instruments
Interest Rate Swaps
The Fund has entered into interest rate swaps on $75,000,000 of notional
debt at rates varying from 4.10% to 4.61% before banking fees that are
expected to range between 0.55% and 1.10%. These interest rate swaps
mature between June 2011 and January 2012. The interest rate swaps are
classified as held-for-trading and are reported at fair value. At
March 31, 2007 the fair value of the interest rate swaps represented a
liability of $492,000. For the three months ended March 31, 2007, the
change in fair value of these contracts represented an unrealized gain of
$181,000.
Cross Currency Interest Rate Swap (CCIRS)
Concurrent with the issuance of the notes on June 19, 2002, the Fund
entered into a CCIRS with a syndicate of financial institutions. Under
the terms of the swap, the amount of the notes was fixed for purposes of
interest and principal 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 CCIRS is classified as held-for-trading and is reported at fair
value. At March 31, 2007 the fair value of the CCIRS represented a
liability of $66,495,000. For the three months ended March 31, 2007, the
change in fair value of the CCIRS represented an unrealized loss of
$1,493,000.
Crude Oil Instruments
Enerplus has entered into the following financial option contracts to
reduce the impact of a downward movement in crude oil prices. These
contracts are classified as held-for-trading and are reported at fair
value. At March 31, 2007 the fair value of these contracts represented a
liability of $1,958,000. For the three months ended March 31, 2007, the
change in fair value of these contracts represented an unrealized loss of
$12,880,000.
The net premium cost of the crude oil instruments entered into as of
March 31, 2007 is $15,622,000.
The following table summarizes the Fund's crude oil risk management
positions at April 26, 2007:
WTI US$/bbl
----------------------------------------
Daily
Volumes Purchased Fixed Price
bbls/day Sold Call Put and Swaps
-------------------------------------------------------------------------
Term
April 1, 2007 -
December 31, 2007
Put 5,000 - $ 71.00 -
Put 2,500 - $ 68.00 -
Put 2,500 - $ 65.70 -
Swap 2,500 - - $ 66.24
January 1, 2008 -
December 31, 2008
Collar(1) 750 $ 77.00 $ 67.00 -
-------------------------------------------------------------------------
(1) Financial contracts entered into during the first quarter of 2007.
Natural Gas Instruments
Enerplus has certain physical and financial contracts outstanding as at
April 26, 2007 on its natural gas production that are detailed below. In
addition, the Fund has outstanding physical natural gas contracts that
provide the Fund a premium of $0.50/Mcf on 19.4MMcf/day for April 2007
and a premium of $0.02/Mcf on 2.4MMcf/day for April through June 2007.
These contracts are classified as held-for-trading and are reported at
fair value. At March 31, 2007 the fair value of these contracts
represented a liability of $7,912,000. For the three months ended
March 31, 2007, the change in fair value of these contracts represented
an unrealized loss of $20,602,000.
The net premium cost of the financial natural gas instruments entered
into as of March 31, 2007 is $3,816,000.
AECO CDN$/Mcf
----------------------------------------
Daily Fixed
Volumes Sold Purchased Sold Price
MMcf/day Call Put Put and Swaps
-------------------------------------------------------------------------
Term
April 1, 2007 -
June 30, 2007
Put 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 9.5 $ 9.10 $ 7.10 - -
Collar 9.5 $ 9.15 $ 7.14 - -
Collar 9.5 $ 9.50 $ 7.20 - -
Costless
Collar(1) 4.7 $ 8.02 $ 7.17 - -
Costless
Collar(1) 4.7 $ 8.23 $ 7.28 - -
Costless
Collar(1) 4.7 $ 8.20 $ 7.50
3-Way option 4.7 $ 9.50 $ 7.75 $ 5.49 -
Put 4.7 - $ 7.28 - -
Swap 6.6 - - - $ 7.60
Swap 4.7 - - - $ 7.33
Swap 2.4 - - - $ 7.84
Swap 2.4 - - - $ 7.96
Swap(1) 7.1 - - - $ 7.17
Swap(1) 2.4 - - - $ 7.70
Swap(1) 2.4 - - - $ 7.53
Swap(1) 2.4 - - - $ 8.35
November 1, 2007 -
March 31, 2008
Collar 2.4 $ 9.95 $ 8.00 - -
3-Way option 4.7 $ 10.50 $ 8.20 $ 5.70 -
3-Way option(1) 4.7 $ 11.61 $ 8.97 $ 6.33 -
3-Way option(2) 4.7 $ 11.61 $ 8.97 $ 6.33 -
3-Way option(2) 4.7 $ 11.08 $ 8.55 $ 6.01 -
Swap 4.7 - - - $ 8.70
2007 - 2010
Physical
(escalated
pricing) 2.0 - - - $ 2.52
-------------------------------------------------------------------------
(1) Financial contracts entered into during the first quarter of 2007.
(2) Financial contracts entered into during the second quarter of 2007.
Electricity Instruments
The Fund has entered into electricity swaps that fix the price of
electricity. These contracts are classified as held-for-trading and are
reported at fair value. At March 31, 2007 the fair value of these
contracts represented an asset of $1,441,000. For the three months ended
March 31, 2007, the change in fair value of these contracts represented
an unrealized loss of $53,000.
Unrealized gains or losses resulting from changes in fair value along
with realized gains or losses on settlement of the electricity contracts
are recognized as operating costs.
The following table summarizes the Fund's electricity management
positions at April 26, 2007.
Volumes Price
Term MWh CDN$/MWh
-------------------------------------------------------------------------
April 1, 2007 - December 31, 2007 5.0 $ 61.50
April 1, 2007 - December 31, 2007 4.0 $ 62.90
April 1, 2008 - September 30, 2008 4.0 $ 63.00
-------------------------------------------------------------------------
The Fund did not enter into any new electricity contracts in the first
quarter of 2007.
10. EVENTS SUBSEQUENT TO MARCH 31, 2007
Kirby Acquisition
On April 10, 2007 the Fund closed the acquisition of a 90% interest in
the Kirby Oil Sands Partnership, a privately held partnership operating
in the Athabasca oil sands fairway of Alberta, for total consideration of
$182,500,000 consisting of $127,750,000 in cash and the issuance of
1,104,945 trust units at a deemed price of $49.55. As part of the
acquisition, Enerplus will become the managing partner and the operator
of the project.
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
About EnerplusEnerplus is an independent North American energy company with a diversified asset base of oil and gas properties across a variety of resource plays. We are focused on creating value for our investors by providing organic growth in production and reserves complemented by a monthly dividend. more
