TSX: ERF.UN
NYSE: ERF
CALGARY, May 8 /CNW/ - Enerplus Resources Fund ("Enerplus") is pleased to
report our first quarter results for 2009. Although the first quarter of 2009
was a continuation of one of the most economically challenging times in recent
history, we are pleased to report that our operating and financial results
were in line with expectations. We continue to enjoy the benefits of one of
the strongest balance sheets in our sector, allowing us to remain focused on
our operations and our plans to improve our overall business. We are on target
with our production volumes, development capital spending, operating and
general and administrative costs.
- Production in the quarter averaged approximately 95,000 BOE/day, 7%
higher than the first quarter of 2008 and in line with our
expectations. As a result of reduced capital spending in 2009, we are
expecting production volumes to be lower throughout the remainder of
the year. We continue to anticipate average daily production volumes
of 91,000 BOE/day with an exit rate of approximately 88,000 BOE/day
based upon development capital spending of $300 million.
- We realized an average selling price of $5.13/Mcf for our natural
gas, a 32% decrease from the first quarter of 2008. Our crude oil
production realized an average price of $42.41/bbl, down over 50%
from the first quarter of 2008.
- As a result of lower commodity prices, cash flow from operations
during the quarter was $169.4 million, 34% lower than during the same
period last year. In conjunction with the drop in prices and cash
flows, we reduced our monthly cash distributions to unitholders in
February to $0.18/unit in order to preserve our financial
flexibility. Approximately 53% of our cash flow was distributed to
unitholders during the quarter versus 75% last year.
- When we combine cash distributions paid to unitholders with
development capital spending, our adjusted payout ratio for the
quarter was 112% or 107% before adjustments for working capital.
- We continued to invest in our asset base with approximately
$99 million spent on development drilling and optimization activities
during the quarter. We drilled 123 net wells with a 99% success rate
this quarter with approximately 84% of our capital spent on operated
properties.
- We realized cash gains of $14.3 million on our natural gas hedges and
$31.6 million on our crude oil hedges. We hold downside protection on
approximately 27% of our crude oil production for the remainder of
the year at an effective price of over US$93.00/bbl, and
approximately 26% downside protection on our natural gas production
at an effective price of over $7.50/Mcf based on current forward
market prices.
- Our balance sheet remains very strong with a debt to 12 month
trailing cash flow of 0.6x.
SELECTED FINANCIAL RESULTS
This news release contains certain forward-looking information and
statements. We refer you to the end of the news release for our disclaimer on
forward-looking information and statements. For information on the use of the
term "BOE" see "Information Regarding Disclosure in this News Release and Oil
and Gas Reserves, Resources and Operational Information" at the conclusion of
this news release.
For the three months ended March 31, 2009 2008
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Financial (000's)
Cash Flow from Operating Activities $ 169,388 $ 256,216
Cash Distributions to Unitholders(1) 89,537 192,358
Cash Withheld for Acquisitions and
Capital Expenditures 79,851 63,858
Net Income 51,786 121,394
Debt Outstanding (net of cash) 739,170 1,097,821
Development Capital Spending 99,243 126,262
Acquisitions 1,977 1,765,069
Divestments 13 2,122
Actual Cash Distributions paid to Unitholders $ 0.61 $ 1.26
Financial per Weighted Average Trust Units(2)
Cash Flow from Operating Activities $ 1.02 $ 1.74
Cash Distributions per Unit(1) 0.54 1.30
Cash Withheld for Acquisitions and
Capital Expenditures 0.48 0.44
Net Income 0.31 0.82
Payout Ratio(3) 53% 75%
Adjusted Payout Ratio(3) 112% 125%
Selected Financial Results per BOE(4)
Oil & Gas Sales(5) $ 35.24 $ 62.10
Royalties (6.43) (11.57)
Commodity Derivative Instruments 5.38 (1.35)
Operating Costs (9.95) (8.96)
General and Administrative (2.05) (1.85)
Interest and Other Income and Foreign Exchange (0.91) (0.84)
Taxes (0.10) (1.18)
Asset retirement obligations settled (0.43) (0.50)
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Cash Flow from Operating Activities before
changes in non-cash working capital $ 20.75 $ 35.85
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Weighted Average Number of Trust Units
Outstanding Including Equivalent Exchangeable
Partnership Units (thousands) 165,716 147,482
Debt/Trailing 12 Month Cash Flow Ratio(6) 0.6x 1.0x
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SELECTED OPERATING RESULTS
For the three months ended March 31, 2009 2008
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Average Daily Production
Natural gas (Mcf/day) 338,857 307,746
Crude oil (bbls/day) 34,427 33,256
Natural gas liquids (bbls/day) 4,059 4,603
Total daily sales (BOE/day) 94,962 89,150
% Natural gas 59% 58%
Average Selling Price(5)
Natural gas (per Mcf) $ 5.13 $ 7.52
Crude oil (per bbl) 42.41 86.02
NGLs (per bbl) 40.59 69.75
CDN$/US$ exchange rate 0.80 1.00
Net Wells drilled 123 125
Success Rate(7) 99% 100%
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(1) Calculated based on distributions paid or payable.
(2) Based on weighted average trust units outstanding for the period,
including exchangeable partnership units.
(3) Payout ratio is calculated as cash distributions to unitholders
divided by cash flow from operating activities. Adjusted payout ratio
is calculated as cash distributions to unitholders plus development
capital and office expenditures divided by cash flow from operating
activities. See "Non-GAAP Measures" in the following Management's
Discussion and Analysis.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(6) Including the trailing 12 month cash flow of Focus Energy Trust for
2008.
(7) Based on wells drilled and cased.
Trust Unit Trading Summary TSX - ERF.un NYSE - ERF
for the three months ended March 31, 2009 (CDN$) (US$)
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High $ 28.00 $ 23.65
Low $ 16.75 $ 12.85
Close $ 20.80 $ 16.37
2009 Cash Distributions Per Trust Unit
Payment Month CDN$ US$
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January $ 0.25 $ 0.20
February 0.18 0.14
March 0.18 0.15
First Quarter Total $ 0.61 $ 0.49
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2009 PRODUCTION AND DEVELOPMENT ACTIVITY
As at March 31, 2009 Production Capital Wells Drilled
Volumes Spending --------------------
Play Type (BOE/day) ($millions) Gross Net
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Shallow Gas 24,411 29.2 117 103
Crude Oil Waterfloods 16,166 8.3 2 1
Tight Gas 15,387 29.1 20 11
Bakken Oil/Tight Oil 10,794 11.1 1 1
Other Conventional
Oil & Gas 28,204 13.2 30 7
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Total Conventional 94,962 90.9 170 123
Oil Sands - 8.3 - -
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Total 94,962 99.2 170 123
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Our development capital program in the first quarter was primarily
focused on our natural gas assets and accounted for close to 75% of our
conventional development spending. Our capital spending program will remain
sensitive to the current pricing environment, and if we continue to see weak
natural gas prices we may shift more of our capital program into oil projects
throughout the remainder of the year.
Tommy Lakes received the majority of the capital spent in the quarter in
our tight gas resource play. Tommy Lakes is a winter access only property in
northeastern British Columbia and we completed our 14 well winter drilling
program including the successful drilling of our first horizontal well on
these lands. We are evaluating the results of the horizontal drilling to
determine what additional opportunities may exist in this area. We also
drilled 103 net wells on our shallow gas resource play properties in the first
quarter, with the majority of this capital focused at Shackleton where we
drilled 49 wells and tied in 80. The remainder of our capital was spent
between our Sleeping Giant Bakken oil play in the U.S., our crude oil
waterflood resource plays and other conventional assets in Canada.
DEFERRAL OF KIRBY OIL SANDS PROJECT
On April 17, 2009 we announced the deferral of our Kirby Oil Sands
project. While we believe there is long-term value in the Kirby project, the
current cost structures, commodity price environment and our cost of capital
do not offer a sufficient economic return for additional investment at this
time. We plan to complete an updated resource assessment this summer based on
new data resulting from our seismic program which began in late 2008 and to
complete the regulatory application process by this fall as originally
planned. We will not, however, continue the advance engineering work which
would have led to a sanctioning decision later in 2009. As we had already
significantly reduced our spending plans on Kirby for 2009 to $25 million, we
only expect a modest decrease in the order of $5 million this year. We expect
to redeploy this capital into our growth budget, focusing on tight oil and
tight gas development opportunities. We will continue to monitor economic,
regulatory, market and technical developments which impact oil sands
development and will revisit our plans for Kirby as circumstances warrant.
2009 STRATEGIC FOCUS
Our strategic focus for this year has not changed. We are fortunate to
possess one of the strongest balance sheets in our sector, affording us the
flexibility to pursue acquisitions in tight gas and tight oil. The continued
deterioration of the North American economy and reduced access to credit has
resulted in an increase in assets for sale. However, there still remains some
disparity between buyers and sellers expectations. In addition, we continue to
assess our portfolio of assets to identify those that may not be core to our
long-term business strategy and would look to sell these assets at the
appropriate time.
We are also working on our plans to convert to a corporation with the
implementation of the SIFT tax beginning in 2011. We continue to believe there
is value in keeping our trust structure and preserving our tax pools during
the exemption period. Converting to a corporation would be a change in our
legal structure only and would not change our business strategy. Our assets
are well- suited to a distribution-oriented business model and we continue to
expect a significant portion of our cash flow will be paid directly to our
investors if we were to convert to a corporation.
Finally, we are committed to managing our business prudently and
responsibly in these difficult economic times. We are continually reviewing
our operations for ways to improve our business and drive efficiencies
throughout our organization. We are also carefully monitoring both our
development capital spending and our distribution levels to ensure that we are
minimizing any increases in debt and preserving our balance sheet for
acquisition opportunities. Our experience has shown that opportunities arise
in times of uncertainty. We have a proven track record of acquiring quality
assets at opportune times and we expect to be able to utilize our financial
strength and skills to position ourselves to add assets that will continue to
sustain our business model.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated May
7, 2009 and is to be read in conjunction with:
- the audited consolidated financial statements as at and for the years
ended December 31, 2008 and 2007; and
- the unaudited interim consolidated financial statements as at and for
the three months ended March 31, 2009 and 2008.
The following MD&A contains forward-looking information and statements.
We refer you to the end of this news release for our disclaimer on forward-
looking information and statements.
NON-GAAP MEASURES
Throughout the MD&A we use the term "payout ratio" and "adjusted payout
ratio" to analyze operating performance, leverage and liquidity. We calculate
payout ratio by dividing cash distributions to unitholders ("cash
distributions") by cash flow from operating activities ("cash flow"), both of
which appear on our consolidated statements of cash flows. "Adjusted payout
ratio" is calculated as cash distributions plus development capital and office
expenditures divided by cash flow. The terms "payout ratio" and "adjusted
payout ratio" do not have a standardized meaning or definition as prescribed
by GAAP and therefore may not be comparable with the calculation of similar
measures by other entities. Refer to the Liquidity and Capital Resources
section of the MD&A for further information.
OVERVIEW
Our first quarter operating results were in-line with expectations with
production averaging 94,962 BOE/day, operating expenses of $9.84/BOE and
development capital spending of $99.2 million. Despite increased production
levels, cash flow from operating activities decreased 34% to $169.4 million
compared to the first quarter of 2008 due to lower realized crude oil and
natural gas prices. As a result of lower commodity price levels our price risk
management program generated cash gains of $45.9 million and non-cash gains of
$12.7 million.
We continue to focus on cost control across all areas of our
organization, including our development capital spending, operating expenses
and general & administrative expenses. Our 2009 development capital program is
still anticipated to total $300 million however we are closely evaluating all
projects and may look to shift some spending from gas to oil projects if
natural gas prices remain at current levels. On April 17, 2009 we announced
that we are deferring further development of our Kirby oil sands project as
current cost structures, the commodity price environment and our cost of
capital do not offer a sufficient return for this project at this time.
At March 31, 2009 we continue to have a conservative balance sheet with
over $950 million of available credit capacity and a debt to 12 month trailing
cash flow ratio of 0.6x. We believe we are well positioned to capitalize on
potential acquisition opportunities given our track record of strategic
acquisitions and the strength of our balance sheet.
RESULTS OF OPERATIONS
Production
Production in the first quarter of 2009 was in-line with our expectations
averaging 94,962 BOE/day, an increase of 7% from 89,150 BOE/day in the first
quarter of 2008. This increase reflects a full quarter of production from the
Focus assets that were acquired in February 2008 along with incremental
production from the 2008 winter drilling program at Tommy Lakes.
Average production volumes for the three months ended March 31, 2009 and
2008 are outlined below:
Three months ended March 31,
Daily Production Volumes 2009 2008 % Change
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Natural gas (Mcf/day) 338,857 307,746 10%
Crude oil (bbls/day) 34,427 33,256 4%
Natural gas liquids (bbls/day) 4,059 4,603 (12%)
Total daily sales (BOE/day) 94,962 89,150 7%
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We continue to expect production to decline through 2009 as a result of
our reduced capital spending and are maintaining our guidance of annual
average production of 91,000 BOE/day and exit rate of 88,000 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, 2009
and 2008. It also compares the benchmark price indices for the same periods.
Three months ended March 31,
Average Selling Price(1) 2009 2008 % Change
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Natural gas (per Mcf) $ 5.13 $ 7.52 (32%)
Crude oil (per bbl) 42.41 86.02 (51%)
Natural gas liquids (per bbl) 40.59 69.75 (42%)
Per BOE 35.24 62.09 (43%)
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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 2009 2008 % Change
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AECO natural gas - monthly index
(CDN$/Mcf) $ 5.63 $ 7.13 (21%)
AECO natural gas - daily index
(CDN$/Mcf) 4.92 7.90 (38%)
NYMEX natural gas - monthly NX3
index (US$/Mcf) 4.79 8.07 (41%)
NYMEX natural gas - monthly NX3
index CDN$ equivalent (CDN$/Mcf) 5.99 8.07 (26%)
WTI crude oil (US$/bbl) 43.08 97.92 (56%)
WTI crude oil: CDN$ equivalent
(CDN$/bbl) 53.85 97.92 (45%)
CDN$/US$ exchange rate 0.80 1.00 (20%)
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Natural gas prices continued to drop during the first quarter. Winter
weather this year was colder than normal across most of North America and
imports of LNG into the U.S. remained low. However, the combination of demand
destruction from the weak economy and continued over-supply from U.S. domestic
natural gas production led to continued downward pressure on price throughout
the first quarter of 2009.
We realized an average price on our natural gas of $5.13/Mcf (net of
transportation costs) during the first quarter of 2009, a decrease of 32% from
$7.52/Mcf for the same period in 2008. The majority of our natural gas sales
are priced with reference to the monthly and daily AECO indices. The decrease
in our realized natural gas price during the first quarter is comparable to
the average change in the combined indices.
West Texas Intermediate ("WTI") crude oil prices stabilized in the first
quarter of 2009 after falling dramatically in the previous quarter. During the
quarter WTI prices fluctuated between US$33.98/bbl and US$54.34/bbl and closed
the quarter at US$49.66/bbl. Key drivers supporting crude oil prices at this
level are a reduction in OPEC supply, falling rig counts and a long term
demand outlook which has resulted in a strong forward market. However, current
fundamentals show crude oil storage at historically high levels with
continuing weak global demand.
The average price we received for our crude oil during the first quarter
of 2009 decreased 51% to $42.41/bbl (net of transportation costs) from
$86.02/bbl during the same period in 2008. In comparison, the WTI crude oil
benchmark price, in Canadian dollars, decreased 45% from the corresponding
period in 2008. The difference between the change in the benchmark and our
average price can be attributed to our light sweet oil produced in the U.S.
and the light/medium blends in Canada, both of which were subject to wider
price differentials due to reduced refinery demand for lighter crudes.
The Canadian dollar averaged $0.80 per U.S. dollar during the first
quarter of 2009 versus being near par during the first quarter of 2008. As
most of our crude oil and a portion of our natural gas is priced in reference
to U.S. dollar denominated benchmarks, this movement in the exchange rate
helped offset, in part, the decrease in prices we realized overall.
Price Risk Management
We continue to adjust our price risk management program with
consideration given to our overall financial position together with the
economics of our development capital program and potential acquisitions.
Consideration is also given to the upfront and potential costs of our risk
management program as we seek to limit our exposure to price downturns. Hedge
positions for any given term are transacted across a range of prices and time.
We did not enter into any new natural gas or crude oil contracts during the
first quarter of 2009.
Our existing commodity contracts are designed to protect a portion of our
natural gas sales through October 2010 and a portion of our crude oil sales
through December 2009. We have also hedged a portion of our electricity
consumption through December 2010 to protect against rising electricity costs
in the Alberta power market. See Note 8 for a detailed list of our current
price risk management positions.
The following is a summary of the financial contracts in place at April
29, 2009 expressed as a percentage of our anticipated net production volumes:
Natural Gas Crude Oil
(CDN$/Mcf) (US$/bbl)
------------------------------------- ------------
April 1, November 1, April 1, April 1,
2009 - 2009 - 2010 - 2009 -
October 31, March 31, October 31, December 31,
2009 2010 2010 2009
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Purchased Puts $ 8.30 $ 8.99 $ - $ 98.08
(floor prices)
% 18% 9% - 25%
Sold Puts (limiting
downside protection) $ 7.85 $ - $ - $ 66.17
% 4% - - 11%
Swaps (fixed price) $ 7.41 $ 7.33 $ 7.33 $100.05
% 11% 10% 9% 2%
Sold Calls (capped
price) $ - $ 12.13 $ - $ 92.98
% - 2% - 11%
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Based on weighted average price (before premiums), estimated average
annual production of 91,000 BOE/day and assuming an 18% royalty rate.
Accounting for Price Risk Management
During the first quarter of 2009 our commodity price risk management
program generated cash gains of $14.3 million on our natural gas contracts and
$31.6 million on our crude oil contracts. These gains are due to contracts in
place that provided floor protection that was above market prices. In
comparison, our commodity price risk management program resulted in cash gains
of $4.3 million on our natural gas contracts and cash losses of $15.2 million
on our crude oil contracts in the first quarter of 2008.
At March 31, 2009 the fair value of our natural gas and crude oil
derivative instruments, net of premiums, represented gains of $57.3 million
and $76.3 million respectively. These gains are recorded as current deferred
financial assets on our balance sheet. In comparison, at December 31, 2008 the
fair value of our natural gas and crude oil derivative instruments represented
gains of $24.3 million and $96.6 million respectively, which were also
recorded as current deferred financial assets on our balance sheet. The change
in the fair value of our commodity derivative instruments during the quarter
resulted in an unrealized gain of $33.0 million for natural gas and an
unrealized loss of $20.3 million for crude oil. As the forward markets for
natural gas and crude oil fluctuate, new contracts are executed and existing
contracts are realized, changes in fair value are reflected as a non-cash
charge or non-cash gain in earnings. See Note 8 for details.
The following table summarizes the effects of our financial contracts on
income.
Risk Management Gains/
(Losses)
($ millions, except per Three months ended Three months ended
unit amounts) March 31, 2009 March 31, 2008
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Cash gains/(losses):
Natural Gas $14.3 $0.47/Mcf $4.3 $0.15/Mcf
Crude Oil 31.6 $10.21/bbl (15.2) $(5.03)/bbl
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Total Cash gains/
(losses) $45.9 $5.38/BOE $(10.9) $(1.35)/BOE
Non-cash gains/(losses)
on financial contracts:
Change in fair value -
natural gas $33.0 $1.08/Mcf $(58.3) $(2.08)/Mcf
Change in fair value -
crude oil (20.3) $(6.56)/bbl (21.1) $(6.98)/bbl
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Total non-cash gains/
(losses) $12.7 $1.48/BOE $(79.4) $(9.79)/BOE
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Total gains/(losses) $58.6 $6.86/BOE $(90.3) $(11.14)/BOE
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Revenues
Crude oil and natural gas revenues in the first quarter of 2009 were
$301.2 million ($307.5 million, net of $6.3 million of transportation costs),
a decrease of 40% or $202.5 million compared to $503.7 million ($510.0
million, net of $6.3 million of transportation costs) in the first quarter
2008. Although production was higher in the first quarter of 2009, the
significant decrease in commodity prices resulted in lower overall revenues.
Analysis of Sales Crude Natural
Revenue(1) ($ millions) oil NGLs Gas Total
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Quarter ended March 31, 2008 $260.3 $ 29.2 $214.2 $503.7
Price variance(1) (135.1) (10.6) (77.9) (223.6)
Volume variance 6.2 (3.8) 18.7 21.1
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Quarter ended March 31, 2009 $131.4 $ 14.8 $155.0 $301.2
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(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Other Income
Other income for the first quarter of 2009 was $0.1 million compared to
$15.1 million for the first quarter of 2008. During the first quarter of 2008
we realized a gain of $8.3 million on the sale of certain marketable
securities, as well as interim business interruption insurance proceeds of
$6.4 million related to the Giltedge fire.
Royalties
Royalties are paid to various government entities and other land and
mineral rights owners. For the three months ended March 31, 2009 and 2008,
royalties were $55.0 million and $93.8 million, representing approximately 18%
and 19% of oil and gas sales, net of transportation costs, respectively.
On January 1, 2009 a new royalty regime came into effect in the province
of Alberta where approximately 60% of our production is located. This new
regime has provisions for escalating royalty rates depending on production and
product price levels. The Alberta government modified the new regime with
programs to encourage the drilling of medium and deeper wells and on March 3,
2009, announced a short-term incentive program to further encourage the
drilling of new wells over the next 12 months. With our reduced 2009
development capital spending plans we do not expect any material impact from
these incentive programs.
Operating Expenses
Operating expenses for the first quarter of 2009 were in-line with
expectations at $9.84/BOE or $84.1 million, compared to $8.88/BOE or $72.0
million for the same period in 2008. The increase is mainly due to additional
spending to meet regulatory requirements and higher repairs and maintenance
charges. Excluding non-cash gains related to our electricity swaps, operating
costs were $9.95/BOE compared to $8.96/BOE in the first quarter of 2008. We
are continuing to focus our efforts on reducing our operating costs.
We are maintaining our annual guidance for operating costs of
approximately $10.65/BOE which includes an expectation of costs savings but
also reflects expected production declines during the year.
General and Administrative Expenses ("G&A")
During the first quarter of 2009 G&A expenses increased 9% to $2.21/BOE
or $18.9 million compared to $2.03/BOE or $16.4 million in the first quarter
of 2008. The year-over-year increase was primarily due to higher compensation
costs associated with the increased number of employees along with increased
office space. G&A for the quarter was in line with expectations and on a BOE
basis we expect it will increase during the year as our production is
anticipated to decline. We are maintaining our guidance for G&A expenses at
$2.45/BOE, which includes non-cash G&A costs of approximately $0.20/BOE.
During the quarter our G&A expenses included non-cash charges for our
trust unit rights incentive plan of $1.4 million or $0.16/BOE compared to $1.5
million or $0.18/BOE for 2008. These amounts relate solely to our trust unit
rights incentive plan and are determined using a binomial lattice option-
pricing model. See Note 7 for further details.
The following table summarizes the cash and non-cash expenses recorded in
G&A:
General and Administrative Costs Three months ended March 31,
($ millions) 2009 2008
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Cash $ 17.5 $ 14.9
Trust unit rights incentive plan (non-cash) 1.4 1.5
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Total G&A $ 18.9 $ 16.4
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(Per BOE) 2009 2008
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Cash $ 2.05 $ 1.85
Trust unit rights incentive plan (non-cash) 0.16 0.18
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Total G&A $ 2.21 $ 2.03
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Interest Expense
Interest expense includes interest on long-term debt, the premium
amortization on our US$175 million senior unsecured notes, unrealized gains
and losses resulting from the change in fair value of our interest rate swaps
as well as the interest component on our cross currency interest rate swap
("CCIRS"). See Note 5 for further details.
Interest on long-term debt for the three months ended March 31, 2009
totaled $5.6 million, a $7.7 million decrease from $13.3 million during the
same quarter of 2008. The decrease is due to lower average indebtedness and a
lower average interest rate of 2.3% during the first three months of 2009
compared to 4.3% in the same period in 2008.
For the three months ended March 31, 2009 we recorded unrealized losses
of $6.4 million compared to gains of $6.3 million in 2008. The changes in the
fair value of our interest rate swaps and CCIRS that result from movements in
forward market interest rates cause non-cash interest to fluctuate between
periods.
The following table summarizes the cash and non-cash interest expense
recorded.
Interest Expense Three months ended March 31,
($ millions) 2009 2008
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Interest on long-term debt $ 5.6 $ 13.3
Unrealized loss/(gain) 6.4 (6.3)
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Total Interest Expense $ 12.0 $ 7.0
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At March 31, 2009 approximately 25% of our debt was based on fixed
interest rates while 75% had floating interest rates. In comparison, at March
31, 2008 approximately 12% of our debt was based on fixed interest rates and
88% was based on floating interest rates.
Capital Expenditures
During the first quarter of 2009 we spent $99.2 million on development
capital which was in line with our expectations. These expenditures included
the completion and tie-in of shallow natural gas wells drilled in the fourth
quarter of 2008 at Bantry, Verger and Shackleton, as well as the successful
completion of our winter drilling program at Tommy Lakes. In 2009 we have
achieved a 99% success rate with our drilling program on 123 net wells.
Property acquisitions during the three months ended March 31, 2009 were
$2.0 million compared to $7.5 million during the three months ended March 31,
2008. Corporate acquisitions for the first quarter of 2008 totaled
approximately $1.7 billion and represented the Focus acquisition which closed
on February 13, 2008.
Total net capital expenditures for the first quarter of 2009 and 2008 are
outlined below:
Three months ended March 31,
Capital Expenditures ($ millions) 2009 2008
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Development expenditures $ 79.2 $ 109.3
Plant and facilities 20.0 17.0
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Development Capital 99.2 126.3
Office 0.6 1.6
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Sub-total 99.8 127.9
Acquisitions of oil and gas properties(1) 2.0 7.5
Corporate acquisitions - 1,757.5
Dispositions of oil and gas properties(1) - (2.1)
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Total Net Capital Expenditures $ 101.8 $ 1,890.8
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Total Capital Expenditures financed with cash
flow $ 79.9 $ 63.9
Total Capital Expenditures financed with debt
and equity 21.9 1,826.9
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Total Net Capital Expenditures $ 101.8 $ 1,890.8
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(1) Net of post-closing adjustments.
We are maintaining our 2009 guidance of $300 million for annual
development capital spending, however we may direct more of our spending to
oil projects should natural gas prices remain at current levels.
Oil Sands
Our current oil sands portfolio includes the 100% owned and operated
Kirby steam assisted gravity drainage ("SAGD") project and a 12% minority
equity ownership interest in Laricina Energy Ltd., a private oil sands company
focused on SAGD development in the Athabasca oil sands.
On April 17, 2009 we announced we are deferring further development of
the Kirby oil sands project. Several key activities will be completed in order
to wrap up current efforts and position the project such that it could be
efficiently reinitiated at a later date. Our original 2009 activities were
directed at providing additional information to regulators and stakeholders to
advance our application, completing a seismic program which began in late 2008
and advancing detailed engineering. We plan to complete an updated resource
assessment this summer based on new seismic data and to complete the
regulatory application process by this fall as originally planned. We will
not, however, continue the advance engineering work which would have led to a
sanctioning decision later in 2009. We now expect our spending on Kirby for
2009 to total approximately $20 million, compared to our original guidance of
$25 million.
Since inception the capitalized costs related to our oil sands projects
are $266.7 million. As these projects have not commenced commercial
production, all associated costs inclusive of acquisition expenditures are
capitalized and excluded from our depletion calculation.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
DDA&A of property, plant and equipment ("PP&E") is recognized using the
unit-of-production method based on proved reserves.
For the three months ended March 31, 2009 DDA&A increased to $162.6
million or $19.02/BOE compared to $139.8 million or $17.23/BOE during the same
period in 2008. The increase is primarily due to a full quarter of Focus
production in 2009.
No impairment of the Fund's assets existed at March 31, 2009 using year-
end reserves updated for development activity and management's estimates of
future prices.
Goodwill
The goodwill balance of $639.3 million arose as a result of previous
corporate acquisitions and represents the excess of the total purchase price
over the fair value of the net identifiable assets and liabilities acquired.
Accounting standards require the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. No goodwill impairment existed as at March 31, 2009.
Asset Retirement Obligations
In connection with our operations, we anticipate we will incur
abandonment and reclamation costs for surface leases, wells, facilities and
pipelines. Total future asset retirement obligations are estimated by
management based on the Fund's net ownership interest in wells and facilities,
estimated costs to abandon and reclaim the wells and facilities and the
estimated timing of the costs to be incurred in future periods. The Fund has
estimated the net present value of its total asset retirement obligations to
be approximately $211.2 million at March 31, 2009 compared to $207.4 million
at December 31, 2008.
The following table compares the amortization of the asset retirement
cost, accretion of the asset retirement obligation and asset retirement
obligations settled during the period.
Three months ended March 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
Total Amortization and Accretion
of Asset Retirement Obligations $ 8.6 $ 7.2
-------------------------------------------------------------------------
Asset Retirement Obligations Settled $ 3.7 $ 4.0
-------------------------------------------------------------------------
The timing of actual asset retirement costs will differ from the timing
of amortization and accretion charges. We expect that actual asset retirement
costs will be incurred over the next 66 years with the majority between 2039
and 2048. For accounting purposes, the asset retirement cost is amortized
using a unit-of-production method based on proved reserves before royalties
while the asset retirement obligation accretes until the time the obligation
is settled.
Taxes
Future Income Taxes
Future income taxes arise from differences between the accounting and tax
basis of assets and liabilities. A portion of the future income tax liability
that is recorded on the balance sheet will be recovered through earnings
before 2011. The balance will be realized when future income tax assets and
liabilities are realized or settled.
Our future income tax recovery was $26.1 million for the quarter ended
March 31, 2009 compared to a recovery of $35.2 million for the same period in
2008. The decreased recovery in the first quarter of 2009 is mainly due to
lower taxable income, partially offset by a $8.4 million recovery related to
the enactment of specified investment flow through ("SIFT") legislation, as
well as a reduction in the province of British Columbia's corporate income tax
rate.
Current Income Taxes
In our current structure, payments are made by our crude oil and natural
gas operating entities to the Fund which ultimately transfers both the income
and future tax liability to our unitholders. As a result, we expect minimal
cash income taxes to be paid by our Canadian operating entities. Effective
January 1, 2011 we will be subject to the SIFT tax should we remain a trust.
However with the enactment of legislation in March 2009 defining the
provincial component of the SIFT tax, the effective tax rate for a trust will
now be similar to a corporation. The legislation allowing for the conversion
of a SIFT entity into a corporation on a tax deferred basis and the
acceleration of the recognition of the "safe harbour" limit was also enacted
in March 2009.
The amount of current taxes overall recorded throughout the year with
respect to our U.S. operations is dependent upon income levels and the timing
of both capital expenditures and the repatriation of funds to Canada. For the
first quarter of 2009 we recorded current income taxes $0.8 million compared
to $12.2 million for the same period in 2008. The decrease in current taxes is
due to a decrease in net income.
Based on current commodity prices and our 2009 development capital
spending plans we now expect our U.S. current income taxes to average
approximately 10% of our cash flow from U.S. operations for 2009.
Net Income
Net income for the first quarter of 2009 was $51.8 million or $0.31 per
trust unit compared to $121.4 million or $0.82 per trust unit for the same
period in 2008. The $69.6 million decrease in net income was primarily due to
a significant decline in oil and gas prices resulting in lower oil and gas
sales revenue of $202.5 million (net of transportation costs), as well as
increased DDA&A of $22.8 million, increased operating costs of $12.1 million
and decreased future income tax recovery of $9.1 million. This was partially
offset by increased commodity derivative instrument gains of $149.0 million
and decreased royalties of $38.8 million.
Cash Flow from Operating Activities
Cash flow for the three months ended March 31, 2009 was $169.4 million or
$1.02 per trust unit compared to $256.2 million or $1.74 per trust unit for
the same period in 2008. The decrease in cash flow per unit was largely due to
the significant decrease in crude oil and natural gas prices.
Selected Financial Results
Three months ended Three months ended
March 31, 2009 March 31, 2008
-----------------------------------------------------------
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 94,962 89,150
-------------------------------------------------------------------------
Weighted
average sales
price(2) $ 35.24 $ - $ 35.24 $ 62.10 $ - $ 62.10
Royalties (6.43) - (6.43) (11.57) - (11.57)
Commodity
derivative
instruments 5.38 1.48 6.86 (1.35) (9.79) (11.14)
Operating costs (9.95) 0.11 (9.84) (8.96) 0.08 (8.88)
General and
administrative (2.05) (0.16) (2.21) (1.85) (0.18) (2.03)
Interest
expense, net
of other
income (0.63) (0.76) (1.39) (0.79) 0.77 (0.02)
Foreign
exchange gain/
(loss) (0.28) 0.18 (0.10) (0.05) (0.39) (0.44)
Current income
tax (0.10) - (0.10) (1.18) - (1.18)
Restoration and
abandonment
cash costs (0.43) 0.43 - (0.50) 0.50 -
Depletion,
depreciation,
amortization
and accretion - (19.02) (19.02) - (17.23) (17.23)
Future income
tax recovery - 3.05 3.05 - 4.33 4.33
Gain on sale of
marketable
securities(3) - - - - 1.02 1.02
-------------------------------------------------------------------------
Total per BOE $ 20.75 $(14.69) $ 6.06 $ 35.85 $(20.89) $ 14.96
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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, 2009 and 2008.
(CDN$ millions, Three months ended Three months ended
except per March 31, 2009 March 31, 2008
unit amounts) Canada U.S. Total Canada U.S. Total
-------------------------------------------------------------------------
Daily
Production
Volumes
Natural gas
(Mcf/day) 325,799 13,058 338,857 295,799 11,947 307,746
Crude oil
(bbls/day) 25,381 9,046 34,427 23,734 9,522 33,256
Natural gas
liquids
(bbls/day) 4,059 - 4,059 4,603 - 4,603
Total Daily
Production
Volumes
(BOE/day) 83,740 11,222 94,962 77,637 11,513 89,150
Pricing(1)
Natural gas
(per Mcf) $ 5.12 $ 5.38 $ 5.13 $ 7.47 $ 8.95 $ 7.52
Crude oil
(per bbl) 43.26 40.04 42.41 84.31 90.30 86.02
Natural gas
liquids
(per bbl) 40.59 - 40.59 69.75 - 69.75
Capital
Expenditures
Development
capital and
office $ 89.0 $ 10.8 $ 99.8 $108.3 $ 19.6 $127.9
Acquisitions
of oil
and gas
properties 1.8 0.2 2.0 7.4 0.1 7.5
Dispositions
of oil
and gas
properties - - - (2.1) - (2.1)
Revenues
Oil and gas
sales(1) $262.3 $ 38.9 $301.2 $415.7 $ 88.0 $503.7
Royalties(2) (46.5) (8.5) (55.0) (75.2) (18.6) (93.8)
Commodity
derivative
instruments
gain/(loss) 58.6 - 58.6 (90.3) - (90.3)
Expenses
Operating $ 80.3 $ 3.8 $ 84.1 $ 68.6 $ 3.4 $ 72.0
General and
adminis-
trative 17.0 1.9 18.9 15.1 1.3 16.4
Depletion,
depreciation,
amortization
and
accretion 138.9 23.7 162.6 118.4 21.4 139.8
Current income
taxes
expense/
(recovery) - 0.8 0.8 (2.7) 12.2 9.5
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(2) U.S. Royalties include state production tax.
Quarterly Financial Information
In general, crude oil and natural gas sales increased from 2007 to mid
2008 due to increased commodity prices and increased production from the Focus
acquisition. Oil and gas sales decreased in the latter part of 2008 and in the
first quarter of 2009 as a result of the sharp decline in commodity prices.
Net income has been affected by fluctuating commodity prices and risk
management costs, the fluctuating Canadian dollar, higher operating costs and
changes in future tax provisions due to the SIFT tax and corporate rate
reductions. Furthermore, changes in the fair value of our commodity derivative
instruments and other financial instruments cause net income to continually
fluctuate between quarters.
Quarterly Financial Information
($ millions, Net Income per trust unit
except per trust Oil and Gas -------------------------
unit amounts) Sales(1) Net Income Basic Diluted
-------------------------------------------------------------------------
2009
First quarter $ 301.2 $ 51.8 $ 0.31 $ 0.31
-------------------------------------------------------------------------
2008
Fourth Quarter $ 418.3 $ 189.5 $ 1.15 $ 1.15
Third Quarter 647.8 465.8 2.82 2.82
Second Quarter 734.4 112.2 0.68 0.68
First quarter 503.7 121.4 0.82 0.82
-------------------------------------------------
Total $ 2,304.2 $ 888.9 $ 5.54 $ 5.53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007
Fourth Quarter $ 389.8 $ 98.7 $ 0.76 $ 0.76
Third Quarter 364.8 93.0 0.72 0.72
Second Quarter 382.5 40.1 0.31 0.31
First Quarter 380.0 107.9 0.88 0.87
-------------------------------------------------
Total $ 1,517.1 $ 339.7 $ 2.66 $ 2.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
Liquidity and Capital Resources
Capital Markets and Enerplus' Credit Exposure
The ongoing turmoil in the financial markets has impacted the
availability of credit and equity in the marketplace. The current market
conditions indicate that it may be difficult to issue additional equity or
increase credit capacity without significant costs at this time. In addition,
there has been a dramatic reduction in crude oil and natural gas prices and as
a result there is greater emphasis on evaluating credit capacity, credit
counterparties and liquidity. We discuss these risks below as they relate to
our credit facility, oil and gas sales counterparties, financial derivative
counterparties and joint venture partners.
Credit Facility
---------------
Enerplus' bank credit facility is an unsecured, covenant-based agreement
with a syndicate of thirteen financial institutions, a copy of which was filed
on March 18, 2008 as a "Material document" on the Fund's SEDAR profile at
www.sedar.com. Of the thirteen syndicate members in Enerplus' facility, seven
are major Canadian banks which represent approximately $985 billion or 70% of
the commitments under the $1.4 billion facility. The facility is extendable
each year and is currently set to expire in November 2010. Borrowing costs
under the facility range between 55.0 and 110.0 basis points over bankers'
acceptance rates, with our current borrowing cost being 55.0 basis points over
bankers' acceptance rates. At March 31, 2009 we have drawn $447.8 million or
approximately 32% of the $1.4 billion facility and have a trailing debt-to-
cash flow ratio of 0.6x. At March 31, 2009 we are in compliance with all
covenants under the credit facility.
Our exposure to our lenders relates to their potential inability to
provide funding. Should a lender be unable or choose not to fund, other
lenders have the right, but not the obligation, to increase their commitment
levels to cover the shortfall. Failure to fund would be considered a breach of
contract and could result in potential damages in our favour, however the
likelihood of substantiating and receiving damages is unknown. We have not
experienced any funding issues under the facility to date.
Oil and Gas Sales Counterparties
--------------------------------
The Fund's oil and gas receivables are with customers in the petroleum
and natural gas business and are subject to normal credit risks. Concentration
of credit risk is mitigated by marketing production to numerous purchasers
under normal industry sale and payment terms. A credit review process is in
place to assess and monitor our counterparties' credit worthiness on a regular
basis. This process involves reviewing and ratifying our corporate credit
guidelines, assessing the credit ratings of our counterparties and setting
exposure limits. When warranted we obtain financial assurances such as letters
of credit, parental guarantees, or third party insurance to mitigate our
credit risk. This process is utilized for both our oil and gas sales
counterparties as well as our financial derivative counterparties.
Financial Derivative Counterparties
-----------------------------------
The Fund is exposed to credit risk in the event of non-performance by our
financial counterparties regarding our derivative contracts. The Fund
mitigates this risk by entering into transactions with major financial
institutions, the majority of which are members of our bank syndicate. We have
International Swaps and Derivatives Association ("ISDA") agreements in place
with the majority of our financial counterparties. These agreements provide
some credit protection in that they generally allow parties to aggregate
amounts owing to each other under all outstanding transactions and settle with
a single net amount in the case of a credit event. Absent an ISDA we rely on
long form confirmations which provide Enerplus with similar credit protection.
At March 31, 2009 we had $143.2 million in mark-to-market assets offset by
$24.7 million of mark-to-market liabilities consisting of net asset positions
of $91.6 million with major Canadian institutions and $26.9 million with U.S.
institutions.
We will continue to monitor developments in the financial markets that
could impact the credit worthiness of our financial counterparties, however it
has recently been very difficult to foresee counterparty solvency issues. To
date we have not experienced any losses due to non-performance by our
derivative counterparties.
Joint Venture Partners
----------------------
We attempt to mitigate the credit risk associated with our joint interest
receivables by reviewing and actively following up on older accounts. In
addition, we are specifically monitoring our receivables against a watch list
of publicly traded companies that have high debt-to-cash flow ratios or fully
drawn bank facilities. We do not anticipate any significant issues in the
collection of our joint interest receivables at this time. However, if the
current low commodity prices and tight capital markets prevail, there is a
risk of increased bad debts related to our industry partners.
Distribution Policy
The amount of cash distributions is proposed by management and approved
by the Board of Directors. We continually assess distribution levels with
respect to anticipated cash flows, debt levels, capital spending plans and
capital market conditions. The level of cash withheld has historically varied
between approximately 10% and 40% of annual cash flow from operating
activities and is dependent upon numerous factors, the most significant of
which are the prevailing commodity price environment, our current levels of
production, debt obligations, funding requirements for our development capital
program and our access to equity markets.
The sharp decrease in crude oil and natural gas prices has resulted in a
decrease in our overall cash flows. This commodity price downturn, combined
with the ongoing uncertainty and reduced access to the debt and equity
markets, has reinforced our belief in the importance of maintaining strong
financial flexibility. To that end, we have significantly reduced our monthly
cash distributions to $0.18 per unit effective February 20, 2009 from a high
of $0.47 per trust unit on September 20, 2008. We intend to manage our
distribution levels and capital spending in order to minimize increases in our
debt levels and preserve our balance sheet strength for future acquisitions.
Although we intend to continue to make cash distributions to our
unitholders, these distributions are not guaranteed. To the extent there is
taxable income at the trust level, determined in accordance with the Canadian
Income Tax Act, the distribution of that taxable income is non-discretionary.
Sustainability of our Distributions and Asset Base
As an oil and gas producer we have a declining asset base and therefore
rely on ongoing development activities and acquisitions to replace production
and add additional reserves. Our future crude oil and natural gas production
is highly dependent on our success in exploiting our asset base and acquiring
or developing additional reserves. To the extent we are unsuccessful in these
activities our cash distributions could be reduced.
Development activities and acquisitions may be funded internally by
withholding a portion of cash flow or through external sources of capital such
as debt or the issuance of equity. To the extent that we withhold cash flow to
finance these activities, the amount of cash distributions to our unitholders
may be reduced. Should external sources of capital become limited or
unavailable, our ability to make the necessary development expenditures and
acquisitions to maintain or expand our asset base may be impaired and
ultimately reduce the amount of cash distributions.
Enerplus currently has approximately $9.5 billion of safe harbour growth
capacity within the context of the Canadian Government's "normal growth"
guidelines for SIFT's.
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 2009
cash distributions of $89.5 million were funded entirely through cash flow of
$169.4 million.
Our payout ratio, which is calculated as cash distributions divided by
cash flow, was 53% for the first quarter of 2009 compared to 75% for the same
period in 2008. The decrease in the payout ratio is mainly due to the
reduction in our monthly cash distributions. Our adjusted payout ratio, which
is calculated as cash distribution plus development capital and office
expenditures divided by cash flow, was 112% for the first quarter of 2009. Our
2009 development capital program spending is more heavily weighted towards the
first quarter as some properties such as Tommy Lakes have limited access
during the year. In addition, changes in our non-cash operating working
capital also increased our first quarter adjusted payout ratio. Over the
remaining quarters we still expect to support our distributions and capital
expenditures with our cash flow. However, we will continue to fund
acquisitions and growth through additional debt and equity when required. We
continue to have conservative debt levels with a trailing twelve month
debt-to- cash flow ratio of 0.6x at March 31, 2009.
For the three months ended March 31, 2009, our cash distributions
exceeded our net income by $37.8 million (2008 - $71.0 million). Non-cash
items, such as changes in the fair value of our derivative instruments and
future income taxes, cause net income to fluctuate between periods but do not
impact cash flow from operations. In addition, other non-cash charges such as
DDA&A are not a good proxy for the cost of maintaining our productive capacity
as they are based on the historical costs of our PP&E and not the fair market
value of replacing those assets within the context of the current environment.
It is not possible to distinguish between capital spent on maintaining
productive capacity and capital spent on growth opportunities in the oil and
gas sector due to the nature of reserve reporting, natural reservoir declines
and the risks involved with capital investment. As a result we do not
distinguish maintenance capital separately from development capital spending.
The level of investment in a given period may not be sufficient to replace
productive capacity given the natural declines associated with oil and natural
gas assets. In these instances a portion of the cash distributions paid to
unitholders may represent a return of the unitholders' capital.
The following table compares cash distributions to cash flow and net
income.
Three months ended Year ended Year ended
($ millions, except March 31, December 31 December 31,
per unit amounts) 2009 2008 2007
-------------------------------------------------------------------------
Cash flow from operating
activities: $ 169.4 $ 1,262.8 $ 868.5
Cash distributions 89.5 786.1 646.8
-------------------------------------------------------------------------
Excess of cash flow over cash
distributions $ 79.9 $ 476.7 $ 221.7
Net income $ 51.8 $ 888.9 $ 339.7
(Shortfall)/excess of net income
over cash distributions $ (37.7) $ 102.8 $ (307.1)
Cash distributions per weighted
average trust unit $ 0.54 $ 4.90 $ 5.07
Payout ratio(1) 53% 62% 74%
-------------------------------------------------------------------------
(1) Based on cash distributions divided by cash flow.
Long-Term Debt
Long-term debt at March 31, 2009 was $739.3 million, an increase of $75.0
million from $664.3 million at December 31, 2008. Long-term debt at March 31,
2009 is comprised of $447.8 million of bank indebtedness and $291.5 million of
senior unsecured notes.
Bank indebtedness of $447.8 million at March 31, 2009 increased $66.9
million from December 31, 2008. This increase is partially due to our 2009
development program being more heavily weighted towards the first quarter. In
addition, we had significant development activity in the last two months of
2008 resulting in numerous payments to vendors in the first quarter of 2009.
As our development capital program will moderate over the remainder of the
year we do not expect to significantly increase debt to fund development
activity.
Our working capital at March 31, 2009, excluding cash, current deferred
financial assets and credits and future income taxes increased by $70.1
million compared to December 31, 2008. This change is due to decreased
accounts payable that resulted from lower capital spending activity along with
decreased distributions payable as a result of the reduction in our monthly
distributions.
We continue to maintain a conservative balance sheet as demonstrated
below:
March 31, December 31,
Financial Leverage and Coverage 2009 2008
-------------------------------------------------------------------------
Long-term debt to cash flow
(12 month trailing) 0.6 x 0.5 x
Cash flow to interest expense (12 month trailing) 40.2 x 46.5 x
Long-term debt to long-term debt plus equity 15% 13 %
-------------------------------------------------------------------------
Long-term debt is measured net of cash.
At March 31, 2009 Enerplus had a $1.4 billion unsecured covenant based
facility that matures November 2010, through its wholly-owned subsidiary
EnerMark Inc. We have the ability to request an extension of the facility each
year or repay the entire balance at maturity. This bank debt carries floating
interest rates that we expect to range between 55.0 and 110.0 basis points
over Bankers' Acceptance rates, depending on Enerplus' ratio of senior debt to
earnings before interest, taxes and non- cash items.
Payments with respect to the bank facilities, senior unsecured notes and
other third party debt have priority over claims of and future distributions
to the unitholders. Unitholders have no direct liability should cash flow be
insufficient to repay this indebtedness. The agreements governing these bank
facilities and senior unsecured notes stipulate that if we default or fail to
comply with certain covenants, the ability of the Fund's operating
subsidiaries to make payments to the Fund and consequently the Fund's ability
to make distributions to the unitholders may be restricted. At March 31, 2009
we are in compliance with our debt covenants, the most restrictive of which
limits our long-term debt to three times trailing cash flow reflecting
acquisitions on a pro forma basis. Refer to "Debt of Enerplus" in our Annual
Information Form for the year ended December 31, 2008 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 4.
We anticipate that we will continue to have adequate liquidity under our
bank credit facility and from cash flow from operating activities to fund
planned development capital spending in 2009.
Accumulated Deficit
We have historically paid cash distributions in excess of accumulated
earnings as cash distributions are based on the actual cash flow generated in
the period, whereas accumulated earnings are based on net income which
includes non-cash items such as DDA&A charges, derivative instrument mark-to-
market gains and losses, unit based compensation charges and future income tax
provisions.
Trust Unit Information
We had 165,828,000 trust units outstanding at March 31, 2009 compared to
164,142,000 trust units at March 31, 2008 and 165,590,000 trust units
outstanding at December 31, 2008. This includes 6,841,000 exchangeable
partnership units which are convertible at the option of the holder into 0.425
of an Enerplus trust unit (2,907,000 trust units). During the first quarter of
2009, 397,000 partnership units were converted into 169,000 trust units.
During the first quarter of 2009, 238,000 trust units (2008 - 317,000)
were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and
Unit Purchase Plan ("DRIP") and the trust unit rights incentive plan, net of
redemptions. This resulted in $5.4 million (2008 - $11.9 million) of
additional equity to the Fund. For further details see Note 7.
The weighted average basic number of trust units outstanding for the
three months ended March 31, 2009 was 165,716,000 (2008 - 147,482,000). At
April 29, 2009 we had 165,872,000 trust units outstanding including the
equivalent limited partnership units.
Income Taxes
The following is a general discussion of the Canadian and U.S. tax
consequences of holding Enerplus trust units as capital property. The summary
is not exhaustive in nature and is not intended to provide legal or tax
advice. Investors or potential unitholders should consult their own legal or
tax advisors as to their particular tax consequences.
Canadian Unitholders
We qualify as a mutual fund trust under the Income Tax Act (Canada) and
accordingly, trust units of Enerplus are qualified investments for RRSPs,
RRIFs, RESPs, DPSPs and TFSAs. Each year we have historically transferred all
of our taxable income to the unitholders by way of distributions.
In computing income, unitholders are required to include the taxable
portion of distributions received in that year. An investor's adjusted cost
base ("ACB") in a trust unit equals the purchase price of the trust unit less
any non-taxable cash distributions received from the date of acquisition. To
the extent a unitholder's ACB is reduced below zero, such amount will be
deemed to be a capital gain to the unitholder and the unitholder's ACB will be
brought to $nil.
For 2009, we estimate that 95% of cash distributions will be taxable and
5% will be a tax deferred return of capital. Actual taxable amounts may vary
depending on actual distributions which are dependent upon, among other
things, production, commodity prices and cash flow experienced throughout the
year.
U.S. Unitholders
U.S. unitholders who received cash distributions were subject to at least
a 15% Canadian withholding tax. The withholding tax is applied to both the
taxable portion of the distribution as computed under Canadian tax law and the
non-taxable portion of the distribution. U.S. taxpayers may be eligible for a
foreign tax credit with respect to Canadian withholding taxes paid.
For U.S. taxpayers the taxable portion of cash distributions are
considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers
this should be a "Qualified Dividend" eligible for the reduced tax rate. The
15% preferred rate of tax on "Qualified Dividends" is currently scheduled to
expire in 2010. We are unable to determine whether or to what extent the
preferred rate of tax on "Qualified Dividends" may be extended.
For 2009, we estimate that 90% of cash distributions will be taxable to
most U.S. investors and 10% will be a tax deferred return of capital. Actual
taxable amounts may vary depending on actual distributions which are dependent
upon production, commodity prices and cash flow experienced throughout the
year.
In April 2009, we estimate our non-resident ownership to be 65%.
INTERNAL CONTROLS AND PROCEDURES
There were no changes in our internal control over financial reporting
during the quarter ended March 31, 2009 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
Convergence of Canadian GAAP with International Financial Reporting
Standards ("IFRS")
In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic
plan that will result in Canadian GAAP being converged with IFRS by 2011 for
public reporting entities. On February 13, 2008 the AcSB confirmed that IFRS
will be required for public companies beginning January 1, 2011.
In order to meet our reporting requirements and transition to IFRS we
have established a project team comprised of individuals from Finance,
Information Systems and Business Solutions, Tax, Investor Relations and
Management. Our transition plan consists of four main phases:
- An IFRS diagnostic phase which involves an assessment of the
differences between Canadian GAAP and IFRS,
- An assessment and selection phase whereby we will determine
accounting policies for transition and our continuing IFRS accounting
policies,
- An evaluation of our information systems, business processes,
procedures and controls to support the new reporting standards, and
- Training and development.
To date we have completed our IFRS diagnostic assessment and have started
to analyze and identify accounting policy choices, which include assessing the
impact on information systems and business processes. We have also provided
training to certain business groups which are impacted. We intend to generate
financial information in accordance with IFRS during 2010 to provide
comparative information for the 2011 financial statements.
The transition from current Canadian GAAP to IFRS is a significant
undertaking that may materially affect our reported financial position and
results of operations. As we have not yet determined our accounting policies,
we are unable to quantify the impact of adopting IFRS on our financial
statements. In addition, due to anticipated changes to IFRS and International
Accounting Standards prior to our adoption of IFRS, our plan is subject to
change based on new facts and circumstances that arise after the date of this
MD&A.
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
(CDN$ thousands) (Unaudited) 2009 2008
-------------------------------------------------------------------------
Assets
Current assets
Cash $ 125 $ 6,922
Accounts receivable 144,893 163,152
Deferred financial assets (Note 8) 134,898 121,281
Other current 5,955 3,783
-------------------------------------------------------------------------
285,871 295,138
Property, plant and equipment (Note 2) 5,213,631 5,246,998
Goodwill 639,340 634,023
Deferred financial assets (Note 8) 8,288 6,857
Other assets (Note 8) 47,116 47,116
-------------------------------------------------------------------------
$ 6,194,246 $ 6,230,132
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable $ 198,173 $ 272,818
Distributions payable to unitholders 29,849 41,397
Future income taxes 33,688 30,198
-------------------------------------------------------------------------
261,710 344,413
-------------------------------------------------------------------------
Long-term debt (Note 4) 739,295 664,343
Deferred financial credits (Note 8) 24,719 26,392
Future income taxes 625,057 648,821
Asset retirement obligations (Note 3) 211,179 207,420
-------------------------------------------------------------------------
1,600,250 1,546,976
-------------------------------------------------------------------------
Equity
Unitholders' capital (Note 7) 5,478,114 5,471,336
Accumulated deficit (1,218,950) (1,181,199)
Accumulated other comprehensive income 73,122 48,606
-------------------------------------------------------------------------
(1,145,828) (1,132,593)
4,332,286 4,338,743
-------------------------------------------------------------------------
$ 6,194,246 $ 6,230,132
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2009 2008
-------------------------------------------------------------------------
Accumulated income, beginning of period $ 3,175,819 $ 2,286,927
Net income 51,786 121,394
-------------------------------------------------------------------------
Accumulated income, end of period $ 3,227,605 $ 2,408,321
Accumulated cash distributions, beginning
of period $(4,357,018) $(3,570,880)
Cash distributions (89,537) (192,358)
-------------------------------------------------------------------------
Accumulated cash distributions, end of period $(4,446,555) $(3,763,238)
-------------------------------------------------------------------------
Accumulated deficit, end of period $(1,218,950) $(1,354,917)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2009 2008
-------------------------------------------------------------------------
Balance, beginning of period $ 48,606 $ (108,727)
Other comprehensive income 24,516 21,222
-------------------------------------------------------------------------
Balance, end of period $ 73,122 $ (87,505)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(CDN$ thousands except per trust unit Three months ended March 31,
amounts) (Unaudited) 2009 2008
-------------------------------------------------------------------------
Revenues
Oil and gas sales $ 307,515 $ 510,069
Royalties (55,038) (93,836)
Commodity derivative instruments (Note 8) 58,645 (90,379)
Other income 144 15,116
-------------------------------------------------------------------------
311,266 340,970
-------------------------------------------------------------------------
Expenses
Operating 84,130 72,016
General and administrative 18,870 16,437
Transportation 6,301 6,317
Interest (Note 5) 11,997 6,988
Foreign exchange (Note 6) 853 3,684
Depletion, depreciation, amortization and
accretion 162,560 139,794
-------------------------------------------------------------------------
284,711 245,236
-------------------------------------------------------------------------
Income before taxes 26,555 95,734
Current taxes 839 9,541
Future income tax recovery (26,070) (35,201)
-------------------------------------------------------------------------
Net Income $ 51,786 $ 121,394
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per trust unit
Basic $ 0.31 $ 0.82
Diluted $ 0.31 $ 0.82
-------------------------------------------------------------------------
Weighted average number of trust units
outstanding (thousands)(1)
Basic 165,716 147,482
Diluted 165,716 147,583
-------------------------------------------------------------------------
(1) Includes the exchangeable partnership units.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2009 2008
-------------------------------------------------------------------------
Net income $ 51,786 $ 121,394
-------------------------------------------------------------------------
Other comprehensive income/(loss), net of tax:
Unrealized gain/(loss) on marketable
securities - 2,578
Realized gains on marketable securities
included in net income - (6,158)
Gains and losses on derivatives designated
as hedges in prior periods included in
net income - 74
Change in cumulative translation adjustment 24,516 24,728
-------------------------------------------------------------------------
Other comprehensive income/(loss) 24,516 21,222
-------------------------------------------------------------------------
Comprehensive income $ 76,302 $ 142,616
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three months ended March 31,
(CDN$ thousands) (Unaudited) 2009 2008
-------------------------------------------------------------------------
Operating Activities
Net income $ 51,786 $ 121,394
Non-cash items add/(deduct):
Depletion, depreciation, amortization
and accretion 162,560 139,794
Change in fair value of derivative
instruments (Note 8) (16,721) 66,472
Unit based compensation (Note 7) 1,379 1,486
Foreign exchange on translation of
senior notes (Note 6) 8,237 9,233
Future income taxes recovery (26,070) (35,201)
Amortization of senior notes premium (202) (153)
Reclassification adjustments from AOCI
to net income - 92
Gain on sale of marketable securities - (8,263)
Asset retirement obligations settled
(Note 3) (3,652) (4,020)
-------------------------------------------------------------------------
177,317 290,834
Increase in non-cash operating working
capital (7,929) (34,618)
-------------------------------------------------------------------------
Cash flow from operating activities 169,388 256,216
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of issue costs
(Note 7) 5,400 11,885
Cash distributions to unitholders (89,537) (192,358)
Increase in bank credit facilities 66,917 32,602
(Increase)/Decrease in non-cash financing
working capital (11,549) 14,417
-------------------------------------------------------------------------
Cash flow from financing activities (28,769) (133,454)
-------------------------------------------------------------------------
Investing Activities
Capital expenditures (99,874) (127,923)
Property acquisitions (1,977) (7,549)
Property dispositions 13 2,122
Proceeds on sale of marketable securities - 18,320
Increase in non-cash investing working
capital (46,401) (10,418)
-------------------------------------------------------------------------
Cash flow from investing activities (148,239) (125,448)
-------------------------------------------------------------------------
Effect of exchange rate changes on cash 823 2,437
-------------------------------------------------------------------------
Change in cash (6,797) (249)
Cash, beginning of period 6,922 1,702
-------------------------------------------------------------------------
Cash, end of period $ 125 $ 1,453
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Cash income taxes paid $ - $ 9,002
Cash interest paid $ 2,701 $ 8,318
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements of Enerplus Resources Fund
("Enerplus" or the "Fund") have been prepared by management following the
same accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2008. 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, 2008.
2. PROPERTY, PLANT AND EQUIPMENT (PP&E)
March 31, December 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Property, plant and equipment $ 8,634,309 $ 8,497,206
Accumulated depletion, depreciation and
accretion (3,420,678) (3,250,208)
-------------------------------------------------------------------------
Net property, plant and equipment $ 5,213,631 $ 5,246,998
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capitalized development general and administrative ("G&A") expenses of
$6,249,000 are included in PP&E for the three months ended March 31,
2009 (March 31, 2008 - $4,909,000). Excluded from PP&E for the depletion
and depreciation calculation is $266,688,000 (December 31 2008 -
$257,608,000) related to oil sands projects which have not yet commenced
commercial production.
3. ASSET RETIREMENT OBLIGATIONS
The following is a reconciliation of the asset retirement obligations:
Three months ended Year ended
March 31, December 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Asset retirement obligations, beginning
of period $ 207,420 $ 165,719
Corporate acquisition - 36,784
Changes in estimates 3,473 4,087
Acquisition and development activity 776 7,394
Dispositions - (110)
Asset retirement obligations settled (3,652) (18,308)
Accretion expense 3,162 11,854
-------------------------------------------------------------------------
Asset retirement obligations, end of period $ 211,179 $ 207,420
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. LONG-TERM DEBT
March 31, December 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Bank credit facilities(a) $ 447,805 $ 380,888
Senior notes(b)
US$175 million (issued June 19, 2002) 223,439 217,327
US$54 million (issued October 1, 2003) 68,051 66,128
-------------------------------------------------------------------------
Total long-term debt $ 739,295 $ 664,343
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Unsecured Bank Credit Facility
Enerplus currently has a $1.4 billion unsecured covenant based facility
that matures November 18, 2010. The facility is extendible each year with
a bullet payment required at maturity. 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 weighted average
interest rate on the facility for the three months ended March 31, 2009
was 1.4% (March 31, 2008 - 4.3 %).
(b) Senior Unsecured Notes
On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes
that mature June 19, 2014. The notes have a coupon rate of 6.62% priced
at par, with interest paid semi-annually on June 19 and December 19 of
each year. Principal payments are required in five equal installments
beginning June 19, 2010 and ending June 19, 2014. Concurrent with the
issuance of the notes on June 19, 2002, the Fund entered into a cross
currency interest rate swap ("CCIRS") with a syndicate of financial
institutions. Under the terms of the swap, the amount of the notes was
fixed for purposes of interest and principal repayments at a notional
amount of CDN$268,328,000. Interest payments are made on a floating rate
basis, set at the rate for three-month Canadian bankers' acceptances,
plus 1.18%. At March 31, 2009, the notes have an amortized cost of
US$177,467,000 and are translated into Canadian dollars using the period
end foreign exchange rate.
On October 1, 2003, Enerplus issued US$54,000,000 senior unsecured notes
that mature October 1, 2015. The notes have a coupon rate of 5.46% priced
at par with interest paid semi-annually on April 1 and October 1 of each
year. Principal payments are required in five equal installments
beginning October 1, 2011 and ending October 1, 2015. The notes are
translated into Canadian dollars using the period end foreign exchange
rate. In September 2007 Enerplus entered into foreign exchange swaps that
effectively fix the five principal repayments on the notes at a CDN/US
exchange rate of 0.98 or CDN$55,080,000.
5. INTEREST EXPENSE
Three months ended March 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Realized
Interest on long-term debt $ 5,554 $ 13,345
Unrealized
Loss/(gain) on cross currency interest
rate swap 7,964 (8,344)
(Gain)/loss on interest rate swaps (1,319) 2,140
Amortization of the premium on senior
unsecured notes (202) (153)
-------------------------------------------------------------------------
Interest Expense $ 11,997 $ 6,988
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. FOREIGN EXCHANGE
Three months ended March 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Realized
Foreign exchange loss $ 2,363 $ 568
Unrealized
Foreign exchange loss on translation of
U.S. dollar denominated senior notes 8,237 9,233
Foreign exchange gain on cross currency
interest rate swap (8,318) (4,171)
Foreign exchange gain on foreign
exchange swaps (1,431) (1,946)
-------------------------------------------------------------------------
Foreign exchange loss $ 853 $ 3,684
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. UNITHOLDERS' CAPITAL
Unitholders' capital as presented on the Consolidated Balance Sheets
consists of trust unit capital, exchangeable partnership unit capital and
contributed surplus.
Three months ended Year ended
March 31, December 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Trust units $ 5,340,787 $ 5,328,629
Exchangeable partnership units 116,349 123,107
Contributed surplus 20,978 19,600
-------------------------------------------------------------------------
Balance, end of period $ 5,478,114 $ 5,471,336
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Trust Units
Authorized: Unlimited number of trust units
Three months ended Year ended
(thousands) March 31, 2009 December 31, 2008
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Balance, beginning of
period 162,514 $5,328,629 129,813 $4,020,228
Issued for cash:
Pursuant to rights
incentive plan - - 210 6,755
Cancelled trust units - - (116) (3,794)
Exchangeable limited
partnership units
exchanged 169 6,758 786 31,444
Trust unit rights incentive
plan (non-cash) - exercised - - - 3,642
DRIP(*), net of redemptions 238 5,400 1,671 63,761
Issued for acquisition of
corporate and property
interests (non-cash) - - 30,150 1,206,593
-------------------------------------------------------------------------
162,921 $5,340,787 162,514 $5,328,629
Equivalent exchangeable
partnership units 2,907 116,349 3,076 123,107
-------------------------------------------------------------------------
Balance, end of period 165,828 $5,457,136 165,590 $5,451,736
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Distribution Reinvestment and Unit Purchase Plan
(b) Exchangeable Partnership Units
Enerplus Exchangeable Limited Partnership Units are exchangeable into
Enerplus trust units at a ratio of 0.425 of an Enerplus trust unit for
each limited partnership unit. During the period January 1, 2009 to
March 31, 2009, 397,000 exchangeable limited partnership units were
converted into 169,000 trust units. As at March 31, 2009, the 6,841,000
outstanding exchangeable partnership units represent the equivalent of
2,907,000 trust units.
Three months ended Year ended
(thousands) March 31, 2009 December 31, 2008
Issued: Units Amount Units Amount
-------------------------------------------------------------------------
Assumed on February 13, 2008 7,238 $ 123,107 9,087 $ 154,551
Exchanged for trust units (397) (6,758) (1,849) (31,444)
-------------------------------------------------------------------------
Balance, end of period 6,841 $ 116,349 7,238 $ 123,107
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Contributed Surplus
Three months ended Year ended
March 31, December 31,
($ thousands) 2009 2008
-------------------------------------------------------------------------
Balance, beginning of period $ 19,600 $ 12,452
Trust unit rights incentive plan
(non-cash) - exercised - (3,642)
Trust unit rights incentive plan
(non-cash) - expensed 1,378 6,996
Cancelled trust units - 3,794
-------------------------------------------------------------------------
Balance, end of period $ 20,978 $ 19,600
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(d) Trust Unit Rights Incentive Plan
As at March 31, 2009 a total of 5,888,000 rights issued pursuant to the
Trust Unit Rights Incentive Plan ("Rights Incentive Plan") with an
average exercise price of $35.35 were outstanding. This represents 3.6%
of the total trust units outstanding of which 2,426,000 rights, with an
average exercise price of $45.05, were exercisable. Under the Rights
Incentive Plan, distributions per trust unit to Enerplus unitholders in a
calendar quarter which represent a return of more than 2.5% of the net
PP&E of Enerplus at the end of such calendar quarter may result in a
reduction in the exercise price of the rights. Results for the three
months ended March 31, 2009 have not reduced the exercise price of the
outstanding rights.
The Fund uses a binomial lattice option-pricing model to calculate the
estimated fair value of rights granted under the plan. The following
assumptions were used to arrive at the estimate of fair value for rights
granted during the three months ended March 31, 2009:
Three months ended March 31, 2009
-------------------------------------------------------------------------
Dividend yield 12.61%
Volatility 44.41%
Risk-free interest rate 1.69%
Forfeiture rate 12.40%
Right's exercise price reduction $1.92
-------------------------------------------------------------------------
Non-cash compensation costs of $1,379,000 ($0.01 per unit) related to
rights issued were charged to general and administrative expense during
the three months ended March 31, 2009 (March 31, 2008 - $1,486,000, $0.01
per unit). Activity for the rights issued pursuant to the Rights Plan is
as follows:
Three months ended Year ended
March 31, 2009 December 31, 2008
-----------------------------------------------
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 4,001 $45.05 3,404 $47.59
Granted 1,964 17.14 1,403 42.00
Exercised - - (210) 32.22
Forfeited and expired (77) 44.58 (596) 44.94
-------------------------------------------------------------------------
End of period 5,888 $35.35 4,001 $45.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Rights exercisable at end
of period 2,426 $45.05 2,024 $46.44
-------------------------------------------------------------------------
(1) Exercise price reflects grant prices less reduction in exercise price
discussed above.
(e) Basic and Diluted per Trust Unit Calculations
Basic per-unit calculations are calculated using the weighted average
number of trust units and exchangeable partnership units (converted at
the 0.425 exchange ratio) outstanding during the period. Diluted per-unit
calculations include additional trust units for the dilutive impact of
rights outstanding pursuant to the Rights Incentive Plan.
Net income per trust unit has been determined based on the following:
Three months ended March 31,
(thousands) 2009 2008
-------------------------------------------------------------------------
Weighted average units 165,716 147,482
Dilutive impact of rights - 101
-------------------------------------------------------------------------
Diluted trust units 165,716 147,583
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(f) Performance Trust Unit Plan
In 2007 the Fund adopted a Performance Trust Unit ("PTU") plan for
executives and employees. For the period ended March 31, 2009 the Fund
recorded cash compensation costs of $1,826,000 ($1,083,000 period ended
March 31, 2008) under the plan which are included in general and
administrative expenses.
At March 31, 2009 there were 405,000 PTU's outstanding (422,000 -
March 31, 2008).
(g) Restricted Trust Unit Plan
In 2009 the Fund adopted a new Restricted Trust Unit ("RTU") plan for
executives and employees, which will replace the PTU plan. Under the RTU
plan employees and officers receive cash compensation in relation to the
value of a specified number of underlying notional trust units. The
number of notional trust units awarded is variable to individuals and
they vest one-third at the end of each year for three years. Upon
vesting, plan participants receive a cash payment based on the value of
the underlying trust units plus notional accrued distributions.
For the period ended March 31, 2009 the Fund recorded cash compensation
costs of $1,293,000 under the RTU plan which are included in general and
administrative expenses.
At March 31, 2009 there were 864,000 RTU's outstanding.
8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
(a) Carrying Value and Fair Value of Non-derivative Financial Instruments
i. Cash
Cash is classified as held-for-trading and is reported at fair value.
ii. Accounts Receivable
Accounts receivable are classified as loans and receivables and are
reported at amortized cost. At March 31, 2009 the carrying value of
accounts receivable approximated their fair value.
iii. Marketable Securities
Marketable securities with a quoted market price in an active market are
classified as available-for-sale and are reported at fair value, with
changes in fair value recorded in other comprehensive income. During the
first quarter of 2009 the Fund did not hold any investments in publicly
traded marketable securities.
Marketable securities without a quoted market price in an active market
are reported at cost unless an other than temporary impairment exists. As
at March 31, 2009 the Fund reported investments in marketable securities
of private companies at cost of $47,116,000 (December 31, 2008 -
$47,116,000) in Other Assets on the Consolidated Balance Sheet. Realized
gains and losses on marketable securities are included in other income.
iv. Accounts Payable & Distributions Payable to Unitholders
Accounts payable and distributions payable to unitholders are classified
as other liabilities and are reported at amortized cost. At March 31,
2009 the carrying value of these accounts approximated their fair value.
v. Long-term debt
Bank Credit Facilities
The bank credit facilities are classified as other liabilities and are
reported at cost. At March 31, 2009 the carrying value of the bank credit
facility approximated its fair value.
US$175 million senior notes
The US$175,000,000 senior notes, which are classified as other
liabilities, are reported at amortized cost of US$177,467,000 and are
translated to Canadian dollars at the period end exchange rate. At
March 31, 2009 the Canadian dollar amortized cost of the senior notes was
approximately $223,439,000 and the fair value of these notes was
$221,444,000.
US$54 million senior notes
The US$54,000,000 senior notes, which are classified as other
liabilities, are reported at their amortized cost of US$54,000,000 and
are translated into Canadian dollars at the period end exchange rate. At
March 31, 2009 the Canadian dollar amortized cost of the senior notes was
approximately $68,051,000 and the fair value of these notes was
$63,755,000.
(b) Fair Value of Derivative Financial Instruments
The Fund's derivative financial instruments are classified as held for
trading and are reported at fair value with changes in fair value
recorded through earnings. The deferred financial assets and credits on
the Consolidated Balance Sheets result from recording derivative
financial instruments at fair value. At March 31, 2009 a current deferred
financial asset of $134,898,000, a non-current deferred financial asset
of $8,288,000 and a non-current deferred financial credit of $24,719,000
are recorded on the Consolidated Balance Sheet.
The deferred financial asset relating to crude oil instruments of
$76,314,000 at March 31, 2009 consists of the fair value of the financial
instruments, representing a gain position of $91,975,000 less the related
deferred premiums of $15,661,000. The deferred financial asset relating
to natural gas instruments of $57,284,000 at March 31, 2009 consists of
the fair value of the financial instruments of $72,660,000 less the
related deferred premiums of $15,376,000.
The following table summarizes the fair value as at March 31, 2009 and
change in fair value for the period ended March 31, 2009 of the Fund's
derivative financial instruments. The fair values indicated below are
determined using observable market data including price quotations in
active markets.
Cross
Currency Foreign
Interest Interest Exchange Electricity
($ thousands) Rate Swaps Rate Swaps Swaps Swaps
-------------------------------------------------------------------------
Deferred financial
assets/(credits),
beginning of period $(10,051) $(16,341) $ 6,857 $ 348
Change in fair value
gain/(loss) 1,319(1) 354(2) 1,431(3) 952(4)
-------------------------------------------------------------------------
Deferred financial
assets/(credits),
end of period $ (8,732) $(15,987) $ 8,288 $ 1,300
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance sheet
classification:
Current asset/
(liability) $ - $ - $ - $ 1,300
Non-current asset/
(liability) $ (8,732) $(15,987) $ 8,288 $ -
-------------------------------------------------------------------------
Commodity Derivative
Instruments
-------------------------
($ thousands) Oil Gas Total
-------------------------------------------------------------
Deferred financial
assets/(credits),
beginning of period $ 96,641 $ 24,292 $101,746
Change in fair value
asset/(credits) (20,327)(5) 32,992(5) 16,721
-------------------------------------------------------------
Deferred financial
assets/(credits),
end of period $ 76,314 $ 57,284 $118,467
-------------------------------------------------------------
-------------------------------------------------------------
Balance sheet
classification:
Current asset/
(liability) $ 76,314 $ 57,284 $134,898
Non-current asset/
(liability) $ - $ - $(16,431)
-------------------------------------------------------------
(1) Recorded in interest expense.
(2) Recorded in foreign exchange expense (gain of $8,318) and interest
expense (loss of $7,964).
(3) Recorded in foreign exchange expense.
(4) Recorded in operating expense.
(5) Recorded in commodity derivative instruments (see below).
The following table summarizes the income statement effects of the Fund's
commodity derivative instruments:
Three months ended March 31,
(thousands) 2009 2008
-------------------------------------------------------------------------
Gain/(loss) due to change in fair value $ 12,665 $ (79,445)
Net realized cash gain/(loss) 45,980 (10,934)
-------------------------------------------------------------------------
Commodity derivative instruments gain/(loss) $ 58,645 $ (90,379)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Commodity Risk Management
The Fund is exposed to commodity price fluctuations as part of its normal
business operations, particularly in relation to its crude oil and
natural gas sales. The Fund manages a portion of these risks through a
combination of financial derivative and physical delivery sales
contracts. The Fund's policy is to enter into commodity contracts
considered appropriate to a maximum of 80% of forecasted production
volumes net of royalties. The Fund's outstanding commodity derivative
contracts as at April 29, 2009 are summarized below.
Crude Oil:
WTI US$/bbl
----------------------------------------
Fixed
Daily Price
Volumes Sold Purchased Sold and
bbls/day Call Put Put Swaps
-------------------------------------------------------------------------
Term
April 1, 2009 -
December 31, 2009
Put 1,400 - $122.00 - -
Put 1,000 - $120.00 - -
Put 500 - $116.00 - -
Collar 850 $100.00 $ 85.00 - -
Collar 1,000 - $ 92.00 $ 79.00 -
3-Way option 1,000 $ 85.00 $ 70.00 $ 57.50 -
3-Way option 1,000 $ 95.00 $ 79.00 $ 62.00 -
Swap 500 - - - $100.05
-------------------------------------------------------------------------
There were no new contracts entered into during or subsequent to the
quarter.
Natural Gas:
AECO CDN$/Mcf
---------------------------------------------------------
Fixed
Daily Price
Volumes Sold Purchased Sold and
MMcf/day Call Put Put Swaps
-------------------------------------------------------------------------
Term
April 1, 2009 -
October 31, 2009
Put 9.5 - $ 8.44 - -
Put 14.2 - $ 7.70 - -
Put 2.8 - $ 7.78 - -
Put 4.7 - $ 7.87 - -
Put 4.7 - $ 7.72 - -
Collar 2.8 - $ 9.23 $ 7.65 -
Collar 2.8 - $ 9.50 $ 7.91 -
Collar 5.7 - $ 9.60 $ 7.91 -
Swap 3.8 - - - $ 7.86
April 1, 2009 -
October 31, 2010
Swap 23.7 - - - $ 7.33
November 1, 2009 -
March 31, 2010
Put 9.5 - $ 8.97 - -
Put 2.8 - $ 9.07 - -
Put 9.5 - $ 9.06 - -
Call 4.7 $ 12.13 - - -
2009 - 2010
Physical 2.0 - - - $ 2.67
-------------------------------------------------------------------------
There were no new contracts entered into during or subsequent to the
quarter.
The following sensitivities show the impact to after-tax net income of
the respective changes in forward crude oil and natural gas prices as at
March 31, 2009 on the Fund's outstanding commodity derivative contracts
at that time with all other variables held constant:
Increase/(decrease)
to after-tax net income
----------------------------
25% decrease 25% increase
in forward in forward
$ thousands) prices prices
-------------------------------------------------------------------------
Crude oil derivative contracts $ 15,364 $(16,500)
Natural gas derivative contracts $ 20,378 $(19,642)
-------------------------------------------------------------------------
Electricity:
The Fund is subject to electricity price fluctuations and it manages this
risk by entering into forward fixed rate electricity derivative April 29,
2009 are summarized below.
Volumes Price
Term MWh CDN$/MWh
-------------------------------------------------------------------------
April 1, 2009 - December 31, 2009 4.0 $74.50
April 1, 2009 - December 31, 2009(1) 2.0 $64.00
April 1, 2009 - December 31, 2010 4.0 $77.50
April 1, 2009 - December 31, 2010(1) 2.0 $68.75
-------------------------------------------------------------------------
(1) Electricity contracts entered into during the first quarter of 2009
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund, including our
Annual Information Form, is available under our profile on the SEDAR website
at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.
For further information regarding this news release or a copy of our 2009
first quarter interim report, please contact our investor relations department
at 1-800-319-6462 or email investorrelations@enerplus.com.
INFORMATION REGARDING DISCLOSURE IN THIS NEWS RELEASE AND OIL AND GAS
RESERVES, RESOURCES AND OPERATIONAL INFORMATION
All amounts in this news release are stated in Canadian dollars unless
otherwise specified.
Where applicable, natural gas has been converted to barrels of oil
equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy
equivalent conversion method primarily applicable at the burner tip and does
not represent a value equivalent at the wellhead. Use of BOE in isolation may
be misleading. In accordance with Canadian practice, production volumes and
revenues are reported on a gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Unless otherwise specified, all reserves
volumes in this news release (and all information derived therefrom) are based
on "company interest reserves" using forecast prices and costs. "Company
interest reserves" consist of "gross reserves" (as defined in National
Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101")
plus Enerplus' royalty interests in reserves. "Company interest reserves" are
not a measure defined in NI 51-101 and does not have a standardized meaning
under NI 51-101. Accordingly, our company interest reserves may not be
comparable to reserves presented or disclosed by other issuers. Our oil and
gas reserves statement for the year ended December 31, 2008, which includes
complete disclosure of our oil and gas reserves and other oil and gas
information in accordance with NI 51-101, is contained within our Annual
Information Form dated March 13, 2009 (the "AIF"), available on our website at
www.enerplus.com and on our SEDAR profile at www.sedar.com and which also
forms part of our Form 40-F for the year ended December 31, 2008 filed with
the SEC on March 13, 2009 (the "Form 40-F"), a copy of which is available at
www.sec.gov. Readers are also urged to review the Management's Discussion &
Analysis and financial statements included in this news release for more
complete disclosure on our operations.
This news release contains certain forward-looking information and
statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "guidance",
"objective", "ongoing", "may", "will", "project", "should", "believe",
"plans", "intends" and similar expressions are intended to identify forward-
looking information or statements. In particular, but without limiting the
foregoing, this news release contains forward-looking information and
statements pertaining to the following: the amount, timing and tax treatment
of cash distributions to unitholders; payout ratios; tax treatment of income
trusts such as the Fund; the structure of the Fund and its subsidiaries; the
Fund's income taxes, tax liabilities and tax pools; the volume and product mix
of the Fund's oil and gas production; oil and natural gas prices and the
Fund's risk management programs; the amount of asset retirement obligations;
future liquidity and financial capacity and resources; future capital
expenditures; cost and expense estimates; results from operations and
financial ratios; the Fund's ongoing strategy; the Fund's credit exposure;
cash flow sensitivities; royalty rates and their impact on the Fund's
operations and results; future growth including development, exploration, and
acquisition and development activities and related expenditures, including
with respect to both our conventional and oil sands activities.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
the Fund including, without limitation: that the Fund will continue to conduct
its operations in a manner consistent with past operations; the general
continuance of current or, where applicable, assumed industry conditions;
availability of debt and/or equity sources to fund the Fund's capital and
operating requirements as needed; the continuance of existing and, in certain
circumstances, proposed tax and royalty regimes; the accuracy of the estimates
of the Fund's reserve volumes; and certain commodity price and other cost
assumptions. The Fund believes the material factors, expectations and
assumptions reflected in the forward-looking information and statements are
reasonable at this time but no assurance can be given that these factors,
expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
unanticipated operating results or production declines; changes in tax or
environmental laws or royalty rates; increased debt levels or debt service
requirements; inaccurate estimation of the Fund's oil and gas reserves
volumes; limited, unfavourable or no access to debt or equity capital markets;
increased costs and expenses; the impact of competitors; reliance on industry
partners; and certain other risks detailed from time to time in the Fund's
public disclosure documents including, without limitation, those risks
identified in the MD&A, our MD&A for the year ended December 31, 2008 and in
the AIF and Form 40-F as described above.
The forward-looking information and statements contained in this news
release speak only as of the date of this release and none of the Fund or its
subsidiaries assumes any obligation to publicly update or revise them to
reflect new events or circumstances, except as may be required pursuant to
applicable laws.
Gordon J. Kerr
President & Chief Executive Officer
Enerplus Resources Fund
%CIK: 0001126874
Emergency Number
