EXHIBIT 2
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HARVEST ENERGY TRUST 1ST QUARTER 2005
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MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's discussion and analysis ("MD&A") of Harvest Energy Trust's
("Harvest" or the "Trust") financial condition and results of operations should
be read in conjunction with Harvest's audited consolidated financial statements
and accompanying notes for the year ended December 31, 2004 as well as our
unaudited consolidated financial statements and notes for the three months ended
March 31, 2005. Certain comparative figures have been reclassified to conform
with the current period presentation.
FORWARD-LOOKING INFORMATION
This first quarter report contains forward-looking information and estimates
with respect to Harvest. This information addresses future events and
conditions, and as such involves risks and uncertainties that could cause actual
results to differ materially from those contemplated by the information
provided. These risks and uncertainties include but are not limited to, factors
intrinsic in domestic and international politics and economics, general industry
conditions including the impact of environmental laws and regulations,
imprecision of reserve estimates, fluctuations in commodity prices, interest
rates or foreign exchange rates and stock market volatility. The information and
opinions concerning the Trust's future outlook are based on information
available as at May 11, 2005.
CERTAIN FINANCIAL REPORTING MEASURES
The Trust has used certain measures of financial reporting that are commonly
used as benchmarks within the oil and natural gas industry in the following MD&A
discussion. These measures include: Funds flow from operations, Net Operating
Income, Net Debt, Payout Ratio and Operating Netbacks. These measures are not
defined under Canadian generally accepted accounting principles ("GAAP") and
should not be considered in isolation or as an alternative to conventional GAAP
measures. Certain of these measures are not necessarily comparable to a
similarly titled measure of another company or trust. When these measures are
used, they are defined as "non-GAAP" and should be given careful consideration
by the reader. Specifically, management uses Funds flow from operations
(previously referred to as cash flow from operations) which represents funds
flow from operations before changes in non-cash working capital, to analyze
operating performance and leverage. Funds flow should not be viewed as an
alternative to cash flow from operating activities, net earnings or other
measures of financial performance calculated in accordance with Canadian GAAP.
All references to funds flow throughout this report are based on funds flow
before changes in non-cash working capital.
TRUST OVERVIEW AND STRATEGY
Harvest Energy Trust is an oil and natural gas royalty trust, which focuses on
the operation of high quality mature properties. The Trust employs a disciplined
approach to the oil and natural gas production business, whereby it acquires
high working interest, large resource-in-place, mature producing properties and
employs "best practice" technical and field operational practices to extract
maximum value. These operational practices include: diligent hands-on management
to maintain and maximize production rates, the application of technology and
selective capital investment to maximize reservoir recovery, enhancing
operational efficiencies to control and reduce expenses, and unique marketing
arrangements complemented by corporate hedging strategies to effectively manage
funds flow. The Trust has operations in four core areas: North Central Alberta,
East Central Alberta, Southern Alberta and Southeast Saskatchewan.
HARVEST ENERGY TRUST 1ST QUARTER 2005
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SUMMARY OF HISTORICAL QUARTERLY RESULTS
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(RESTATED - REFER TO NOTE 2 OF THE
CONSOLIDATED FINANCIAL STATEMENTS) (RESTATED)
2005 2004 2003
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FINANCIAL Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
- --------------------------------------------- ---------------------------------------------- ----------------------------------
Revenue, net of royalties $ 109,931 $ 106,964 $ 85,096 $ 44,461 $ 39,298 $ 33,575 $ 24,706 $ 21,350
Operating expense (27,348) (25,725) (19,538) (14,306) (13,873) (13,335) (10,271) (6,790)
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Net operating income(1) $ 82,583 $ 81,239 $ 65,558 $ 30,155 $ 25,425 $ 20,240 $ 14,435 $ 14,560
Net income (loss)(3) (43,070) 11,600 1,740 151 (2,250) 5,495 5,488 1,064
Per Trust Unit, basic(2,3) (1.02) 0.29 0.06 0.01 (0.13) 0.30 0.44 0.09
Per Trust Unit, diluted(2,3) (1.02) 0.27 0.06 0.01 (0.13) 0.29 0.43 0.09
Funds flow from operations(1,3,4) 52,687 52,870 41,267 15,839 13,734 13,699 16,758 9,546
Per Trust Unit, basic(1,3) 1.25 1.31 1.42 0.91 0.80 0.85 1.35 0.84
Per Trust Unit, diluted(1,3) 1.19 1.18 1.12 0.78 0.67 0.82 1.31 0.82
SALES VOLUMES
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Crude oil (bbl/d) 30,087 30,992 22,397 14,775 14,626 14,497 11,054 9,371
Natural gas liquids (bbl/d) 780 1,309 377 141 50 70 77 67
Natural gas (mcf/d) 27,114 28,338 11,909 2,249 915 1,744 1,453 1,161
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Total (BOE/d) 35,386 37,024 24,759 15,291 14,829 14,858 11,373 9,632
=================================================================================================================================
NOTE 1 THIS IS A NON-GAAP MEASURE AS REFERRED TO IN THE "CERTAIN FINANCIAL
REPORTING MEASURES" SECTION OF THIS MD&A.
NOTE 2 THE SUM OF THE INTERIM PERIODS DOES NOT EQUAL THE TOTAL PER YEAR AMOUNT
AS THERE WERE LARGE FLUCTUATIONS IN THE WEIGHTED AVERAGE NUMBER OF
TRUST UNITS OUTSTANDING IN EACH INDIVIDUAL QUARTER.
NOTE 3 RESTATED 2004 TO REFLECT ADOPTION OF EIC 151 "EXCHANGEABLE SHARES"
AND AMENDED CICA HANDBOOK SECTION 3860 "FINANCIAL INSTRUMENTS -
DISCLOSURE AND PRESENTATION". SEE CHANGES IN ACCOUNTING POLICIES FOR
FURTHER DISCUSSION.
NOTE 4 FUNDS FLOW FROM OPERATIONS NOW INCLUDES INTEREST ON CONVERTIBLE
DEBENTURES AND EQUITY BRIDGE NOTES. PREVIOUSLY THIS WAS PART OF FUNDS
FLOW FROM FINANCING ACTIVITIES.
The above table highlights Harvest's performance for the first quarter of 2005,
and the preceding 7 quarters. The net loss reported for the three month period
ended March 31, 2005 is entirely due to the change in the fair value of our
outstanding derivative contacts of $70.7 million.
Net revenues and net operating income have trended higher over the eight
quarters shown above, with the most significant increases occurring in the third
and fourth quarters of 2004. The revenue increase since the second quarter of
2003 is primarily attributable to increasing production volumes and a strong
commodity price environment through 2004 and for the first quarter of 2005. The
two acquisitions completed in 2004, which closed in June and September, were the
most significant reasons for the increase in production volumes, revenue and
funds flow since the second quarter of 2004.
Net income reflects both cash and non-cash items. Changes in non-cash items,
including depletion, depreciation and accretion (DD&A), unrealized foreign
exchange, unrealized gains and losses on derivative contracts, Trust Unit right
compensation expense and future income taxes can cause net income to vary
significantly. However, these items do not impact the funds flow available for
distribution to Unitholders, and therefore we believe net income may be a less
meaningful measure of performance for Harvest. Due primarily to the inclusion of
unrealized mark-to-market gains and losses on derivative contracts, net income
(loss) has not reflected the same trend as net revenues or funds flow. The net
loss for the first quarter of 2005 is due primarily to mark-to-market losses on
derivatives recorded as an expense on the income statement. Mark-to-market
losses arise from changes in the fair values of the derivative contracts in the
period. We ceased hedge accounting for all of our derivative instruments in
October 2004.
Funds flow from operations is a very important measure for a royalty trust
because it represents the source for cash distributions to Unitholders. Internal
funds flow also finances capital expenditures which are used to replace
reserves,
HARVEST ENERGY TRUST 1ST QUARTER 2005
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leading to sustainability. Our low payout ratio is a key competitive advantage
in creating future sustainability. Excluding the substantial non-recurring
foreign exchange gain realized in the third quarter of 2003, our funds flow from
operations has demonstrated a strengthening trend. Funds flow can be impacted by
factors outside of management's control such as commodity prices and currency
exchange rates. We strive to mitigate the impact of these factors by using
hedging (generally referred to herein as 'derivatives' or 'derivative
contracts') on a portion of our transactions to establish a fixed floor for
future commodity prices and currency exchange rates.
REVENUES
THREE MONTHS ENDED MARCH 31
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2005 2004 Change
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Oil and natural gas sales ($/BOE) $ 40.76 $ 35.19 16%
Royalty expense ($/BOE) (6.25) (6.07) 3%
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Net revenues ($/BOE) $ 34.51 $ 29.12 19%
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Net revenues ($ millions) $ 109.9 $ 39.3 180%
=========================================================================================
Our net revenue is impacted by production volumes, commodity prices, currency
exchange rates and royalty rates. Due to the two significant acquisitions
completed during the latter half of 2004, which increased production volumes
compared to the first quarter of 2004, and a crude oil price environment that
has remained robust for the past 3 quarters, our net revenues in the three month
period ending March 31, 2005 increased 180% over the same period in 2004.
Changes in realized prices, volumes and royalty rates are discussed separately
below. The impact of our hedging activities on current and future periods'
income is discussed under "Derivative Contracts".
SALES VOLUMES
First quarter 2005 sales volumes averaged 35,386 BOE/d and were 139% higher than
the 14,829 BOE/d realized in the three month period ended March 31, 2004. This
increase in production is due to the volumes associated with properties acquired
in June and September 2004, as well as successful development and optimization
work across all four of our core areas.
Compared to the first quarter of 2004, at which time we were 99% crude oil and
only 1% natural gas, we have successfully diversified our product mix. In the
first quarter of 2005, our production was approximately 13% natural gas, 2%
natural gas liquids, with crude oil decreasing to approximately 85%. Our 2004
acquisitions significantly contributed to our more diversified production mix,
added two more core areas in North Central Alberta and Southern Alberta and
enhanced our existing East Central Alberta core area.
The average daily sales volumes by product were as follows:
THREE MONTHS ENDED MARCH 31
---------------------------------------------
2005 2004
--------------------- -------------------
Light oil (Bbls/d) 9,943 28% 5,053 34%
Medium oil (Bbls/d) 5,671 16% 4,150 28%
Heavy oil (Bbls/d) 14,473 41% 5,423 37%
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Total oil (Bbls/d) 30,087 85% 14,626 99%
Natural gas liquids (Bbls/d) 780 2% 50 0%
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Total oil and natural gas liquids (Bbls/d) 30,867 87% 14,676 99%
Natural gas (mcf/d) 27,114 13% 915 1%
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Total oil equivalent (BOE/d) 35,386 100% 14,829 100%
==========================================================================================
We anticipate that daily production volumes will average between 34,000 to
36,000 BOE/d for the year and we will maintain a production weighting consistent
with the first quarter.
HARVEST ENERGY TRUST 1ST QUARTER 2005
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REALIZED COMMODITY PRICES
The following table provides a breakdown of our first quarter 2005 and 2004
average commodity prices by product type before realized losses on derivative
contracts.
THREE MONTHS ENDED MARCH 31
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2005 2004 Change
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Product prices:
Light oil ($/bbl) $ 55.81 $ 41.09 36%
Medium oil ($/bbl) 39.50 36.44 8%
Heavy oil ($/bbl) 31.67 28.79 10%
Natural gas liquids ($/bbl) 36.00 35.00 3%
Natural gas ($/mcf) 6.53 5.46 20%
------------------------------------------------------------------------
BOE ($/BOE) $ 40.76 $ 35.20 16%
================================================================================
During the first three months of 2005, our realized commodity prices increased
relative to the same period in 2004. Revenues were impacted by realized losses
on commodity derivative contracts totaling $18.7 million, higher than the $8.9
million loss realized in the first quarter of 2004. This is primarily due to a
42% higher average WTI oil price in the first quarter of 2005 relative to the
same period in 2004. Given that the majority of commodity derivative contracts
that we currently have in place through 2005 provide firm floors with upside
participation, we anticipate that these structures will enable us to realize oil
prices that are closer to spot price levels during 2005 than would have been the
case with our 2004 hedging instruments which were primarily swaps and collars.
The table below provides an example of the impact of Harvest's 2005 commodity
derivative contracts in light of varying WTI oil price levels. This data is
designed to provide readers with directional information only.
Oil Price Scenario ($U.S.) Harvest Average WTI Oil Price After Hedging ($U.S.)
- -------------------------- ---------------------------------------------------
$25.00 WTI $31.96
$55.00 WTI $48.76
$75.00 WTI $65.37
================================================================================
At the time of writing, we have entered into oil price derivative contracts on
approximately 75% of our 2005 net crude oil production, and approximately 59% of
our estimated 2006 net crude oil production. The majority of the 2005 and 2006
commodity derivative contracts that we have in place provide a fixed crude oil
floor price, while retaining the ability to participate in upward price
appreciation. Examples of such contracts include 'indexed puts' and
'participating swaps', and additional information on these and other commodity
derivative contracts can be found in the "Derivative Contracts" section of this
MD&A.
THREE MONTHS ENDED MARCH 31
---------------------------------------
Benchmarks 2005 2004 Change
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West Texas Intermediate crude oil (US$ per barrel) $ 49.91 $ 35.25 42%
Edmonton Par light crude ($ per barrel) 61.56 45.68 35%
Lloyd blend crude oil ($ per barrel) 37.32 33.22 12%
Bow river blend crude oil ($ per barrel) 39.03 34.74 12%
AECO natural gas ($ per mcf) 6.52 6.44 1%
U.S. / Canadian dollar exchange rate 1.227 1.318 (7%)
Bank of Canada interest rate 2.75% 2.72% 1%
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HARVEST ENERGY TRUST 1ST QUARTER 2005
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The benchmark price of WTI crude oil has the greatest impact on Harvest's
revenues because the majority of the Trust's production is crude oil. Foreign
exchange also has an impact on Harvest's revenues as oil prices are
predominantly based on U.S. dollar prices. Following the significant property
acquisition completed in September 2004, Harvest's natural gas weighting
increased from 1% to approximately 13%, increasing the impact of fluctuations in
AECO natural gas spot prices on revenues.
A stronger Canadian dollar versus the U.S. dollar and slightly wider
differentials for heavy crude versus WTI tempered the effects that higher
worldwide prices of crude oil had on our revenues during the first quarter of
2005. The price of WTI was approximately 42% higher in the first quarter 2005
relative to the same period in 2004 but was offset by a 7% higher value of the
Canadian dollar relative to the U.S. dollar.
The differential between heavy and light crude oil continued to fluctuate in the
first quarter 2005 but narrowed from the levels experienced in the fourth
quarter of 2004. The historically wide differentials are primarily due to the
current strong demand for gasoline and lighter oil products. The demand for
these products tends to increase the price of lighter crude oil relative to
heavy and medium crude. An increase in the supply of foreign heavy and sour
crude from the Middle East has also contributed to heavy crude price softening
in general.
The outages at certain Canadian oil sands plants pushed prices for heavy crude
blending components higher, which also had a negative impact on our netbacks. It
is anticipated that this impact will be mitigated once these oil sands plants
come back on-stream in the next few months. To a large part, the historically
high prices that have been set for WTI have been caused by demand for light oil
products outpacing the capacity of refineries to produce those products. If
demand falters and light oil prices fall as a result, we would not expect heavy
crude prices to drop as quickly or on a dollar for dollar basis with light
prices, thereby reducing the differential for heavy crude. We believe the worst
of the impact of wide differentials has already been experienced.
The assets from the two significant acquisitions completed in 2004 significantly
increased our product diversification to include more natural gas and light oil
in our portfolio. This diversification reduces Harvest's outright exposure to
heavy oil differentials and increases our exposure to North American natural gas
prices.
ROYALTIES
Our first quarter 2005 net royalties, as a percentage of revenues before hedging
losses, were lower at approximately 15% compared to 17% in the first quarter of
2004 and approximately 17% in the fourth quarter 2004. This is primarily
attributable to the impact of the lower royalty rate properties acquired in
September 2004. The Saskatchewan government recently changed its legislation to
make its resource surcharge applicable to trusts producing oil and gas in the
province, effective April 1, 2005. The surcharge is 3.6% of gross resource
revenues (2% for production from wells drilled subsequent to October 2002). We
estimate the blended rate applied to Harvest's Saskatchewan properties to be
approximately 3.2% and with Saskatchewan revenues making up 20% of the total for
Harvest, we anticipate royalty rates increasing to approximately 16% for the
remainder of the year.
HARVEST ENERGY TRUST 1ST QUARTER 2005
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OPERATING EXPENSES
THREE MONTHS ENDED MARCH 31
-------------------------------------
($ PER BOE) 2005 2004 Change
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Operating expense $ 8.59 $ 10.28 (16%)
Realized gains on electricity
derivative contracts (0.05) (0.15) (67%)
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Net operating expense $ 8.54 $ 10.13 (16%)
================================================================================
The $1.59/BOE decrease in operating expenses, net of gains on electricity
contracts, during the first quarter of 2005 compared to the first quarter of
2004 reflects the lower cost assets we purchased in 2004, as well as the effect
of operating cost reduction projects completed in 2004.
The first quarter operating cost figure of $8.54/BOE is in line with our
performance goals set out in the December 31, 2004 MD&A. A combination of
extremely cold weather for several weeks in January as well as extensive
workovers completed during the quarter resulted in Harvest incurring higher than
anticipated operating costs on a per BOE basis for the period. However, further
efficiencies as a result of our ongoing capital program coupled with higher
production volumes relative to 2004 are expected to keep the overall 2005
average unit operating expenses per BOE between $7.75 - $8.50.
During the first quarter of 2005, approximately 20% of Harvest's operating costs
related to the consumption of electricity. Management has utilized fixed price
electricity contracts to mitigate electricity price risk within Alberta. In
addition, a new coal-fired generator, Genesee #3, has been brought on-stream in
the province of Alberta and will provide both increased price stability and
likely lower Alberta Electric System Operator (AESO) prices through 2005. Our
electricity hedges (approximately 85% of our estimated Alberta electricity usage
is hedged at an average price of $47.71 per MWh) will help further moderate the
impact of cost swings, as will realizing the benefits of capital projects
undertaken in 2004 dedicated to power efficiency projects.
THREE MONTH PERIOD ENDED MARCH 31
---------------------------------
Benchmark Price 2005 2004 Change
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Alberta Power Pool electricity price ($ per MWh) $ 45.90 $ 48.83 (6%)
================================================================================
GENERAL AND ADMINISTRATION EXPENSES
THREE MONTHS ENDED MARCH 31
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($MILLIONS EXCEPT PER BOE) 2005 2004 Change
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G&A $ 3.3 $ 1.2 175%
Per BOE ($/BOE) 1.02 0.89 15%
Unit right compensation expense 2.2 0.2 1000%
Per BOE ($/BOE) 0.70 0.13 438%
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Total G&A $ 5.5 $ 1.4 293%
Per BOE ($/BOE) $ 1.72 $ 1.02 69%
================================================================================
General and administration expenses ("G&A") charged against income in the first
quarter of 2005 totaled $5.5 million ($1.72/BOE) compared to $1.4 million
($1.02/BOE) in the same quarter in 2004.
The significant increase in G&A in the first quarter of 2005 is a result of a
modification made to our Unit Incentive Rights Plan in the fourth quarter of
2004, resulting in a prospective change in accounting for Unit appreciation
rights (UARs). In previous quarters, UARs were valued at the date they were
granted using a mathematical option valuation model and an expense was charged
to G&A based on that valuation. Following the prospective accounting change, we
now value vested UARs at the difference between exercise price and market price
at each reporting period end to determine the related liability at the end of
the period. Changes in the assumptions used in determining this liability, such
as our Trust Unit price, the
HARVEST ENERGY TRUST 1ST QUARTER 2005
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exercise price and the number of UARs vested at each accounting period will
cause this liability to fluctuate and the difference is reflected as an expense
on the consolidated statement of income.
The increase in cash G&A, excluding UAR expense, is the result of increased
production volumes, and associated higher staff and system expenses. For 2005,
we anticipate that Harvest's cash G&A/BOE will average between $0.90 -
$1.00/BOE, before UAR expense.
INTEREST EXPENSE
THREE MONTHS ENDED MARCH 31
---------------------------
2005 2004 Change
($MILLIONS) (RESTATED)
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Interest on short term debt $ 1.3 $ 0.7 86%
Interest on long term debt 6.5 0.9 622%
Amortization of deferred charges - short term debt 1.2 0.7 71%
Amortization of deferred charges - long term debt 0.4 0.1 300%
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Total interest expense $ 9.4 $ 2.4 292%
================================================================================
Interest on short term debt in the first quarter of 2005 totaled $1.3 million
and relates to the interest paid on our outstanding bank debt. The interest on
long term debt totaled $6.5 million in the first quarter, $6.0 million of which
pertains to our U.S.$250 million senior notes, issued in October 2004. These
notes provide Harvest with a long-term (Oct 15, 2011 maturity), fixed interest
rate (7.875%) source of debt, a natural hedge to currency exchange rates, and
are non-callable for four years. Harvest is one of the few energy trusts to have
accessed the U.S. debt market, and we believe it significantly improves our
capital structure relative to our peers. With the senior notes, we are not
subject to annual borrowing base reviews and therefore are not at risk of
reduced borrowing capacity based on volatile commodity prices. The remaining
$500,000 of long term interest expense relates to our convertible debentures.
Previously, we had recorded the interest incurred on our convertible debentures
as a charge to accumulated income rather than net income. As a result of changes
in accounting standards that came into effect for the first quarter of 2005, we
now reflect this as interest expense in net income. This change is discussed
further under "New Accounting Policies".
Our first quarter total interest expense and amortization of deferred charges of
$9.4 million is higher than the $2.4 million reflected in the first quarter of
2004. The increase in total interest expense is due to interest costs associated
with higher bank debt and the senior notes used to partially finance the June
and September 2004 acquisitions.
Interest expense is expected to decline slightly through 2005 as the outstanding
bank debt is repaid and convertible debentures continue to convert into Trust
Units.
DEPLETION, DEPRECIATION AND ACCRETION (DD&A)
THREE MONTHS ENDED MARCH 31
------------------------------
($MILLIONS EXCEPT PER BOE) 2005 2004 Change
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Depletion and depreciation $ 36.5 $ 9.5 284%
Depletion of capitalized asset retirement costs 2.8 1.8 56%
Accretion on asset retirement obligation 2.3 0.8 188%
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Total depletion, depreciation and accretion $ 41.6 $ 12.1 244%
Per BOE ($/BOE) $ 13.05 $ 8.98 45%
================================================================================
Our first quarter depletion, depreciation, and accretion expense totaled $41.6
million ($13.05/BOE) compared to $12.1 million ($8.98/BOE) for the same quarter
in 2004. Relative to the first quarter of 2004, our higher DD&A is primarily
attributable to the significant acquisitions completed from June to September
2004, and reflects the higher netback production acquired. We anticipate full
year 2005 DD&A rates to range between $12 and $14 / BOE.
HARVEST ENERGY TRUST 1ST QUARTER 2005
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FOREIGN EXCHANGE LOSSES AND GAINS
Foreign exchange gains and losses are attributable to the effect of changes in
the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar
denominated senior notes, as well as any U.S. dollar deposits and cash balances.
Our senior notes, which were issued in October 2004, reduce our net exposure to
fluctuations in foreign exchange rates by offsetting the impact of fluctuations
on net oil prices realized. We have entered into a currency exchange put option
for calendar 2005, on U.S. $8.33 million per month at $1.20 Canadian / U.S. to
provide a further hedge against foreign exchange volatility.
During the first quarter of 2005, the Canadian dollar was somewhat less volatile
against the U.S. dollar compared to the prior period, resulting in a foreign
exchange loss of $2.1 million, compared to a foreign exchange gain of $7.1
million in the fourth quarter of 2004. This also compares to a small foreign
exchange gain recorded in the first quarter of 2004.
DERIVATIVE CONTRACTS
All of our hedging activities are carried out pursuant to policies approved by
the Board of Directors of Harvest Operations Corp. Management intends to
facilitate stable, long-term monthly distributions by reducing the impact of
volatility in commodity prices. As part of our risk management policy,
management utilizes a variety of derivative instruments (including swaps,
options and collars) to manage commodity price, foreign currency and interest
rate exposures. These instruments are commonly referred to as 'hedges' but may
not receive hedge treatment for accounting purposes. Management also enters into
electricity price and heat rate based derivatives to assist in maintaining
stable operating costs. We reduce our exposure to credit risk associated with
these financial instruments by only entering into transactions with financially
sound, credit worthy counterparties.
When there is a high degree of correlation between the price movements in a
derivative financial instrument and the item designated as being 'hedged' and
management documents the effectiveness of this relationship, we may employ hedge
accounting. Effective January 1, 2004, we implemented CICA Accounting Guideline
13, "Hedging Relationships" (AcG-13), which addresses the identification,
designation and effectiveness of financial contracts for the purpose of applying
hedge accounting. Under this guideline, financial derivative contracts must be
designated to the underlying revenue or expense stream that they are intended to
hedge, and then tested to ensure they remain sufficiently effective in order to
continue hedge accounting. As of October 1, 2004, we ceased to apply hedge
accounting to our derivative contracts. As a result, from October 1, 2004 all of
our derivatives are marked-to-market with the resulting gain or loss reflected
in earnings for the reporting period. The mark-to-market valuation represents
the amount that would be required to settle the contract on the period end date.
Collectively our contracts had a mark-to-market unrealized non-cash loss
position on the balance sheet of $86.1 million as at March 31, 2005. Please
refer to Note 10 in the consolidated financial statements for further
information. The difference between this value and the amount at December 31,
2004 of $15.4 million is reflected as an unrealized loss in the first quarter.
The following table provides a reconciliation of the changes in Harvest's
mark-to-market position on its derivative contracts between periods.
($MILLIONS) AS AT MARCH 31, 2005 As at December 31, 2004
- ---------------------------------------------------------------------------------------------------------
Opening mark-to-market position (15.4) --
Unrealized loss on outstanding derivative contracts(1) (75.3) (27.9)
Unrealized gain on outstanding derivative contracts(1) 4.6 12.5
- ---------------------------------------------------------------------------------------------------------
Closing mark-to-market position (86.1) (15.4)
=========================================================================================================
NOTE 1 EXCLUDES AMORTIZATION OF DEFERRED CHARGES (GAIN) RECORDED UPON
ADOPTION OF MARK-TO-MARKET ACCOUNTING AND REFLECTED IN UNREALIZED GAINS
AND LOSSES ON DERIVATIVE CONTRACTS ON THE STATEMENT OF INCOME.
HARVEST ENERGY TRUST 1ST QUARTER 2005
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We determine the value of our derivative contracts using prices from actively
quoted markets, and where we are unable to obtain quoted prices, we use widely
accepted valuation models.
In the first three months of 2005, we recorded a realized loss on commodity
derivative contracts of $18.7 million, and an unrealized loss of $74.7 million
for a total loss of $93.4 million. The realized loss portion reflects the
effective cost of our hedges on production during this period. Realized
derivative contract losses in 2005, assuming similar commodity price levels, are
expected to be lower than those experienced in 2004 as the majority of our
hedged volumes utilize contracts which provide a firm floor but allow for
participation in strengthening commodity prices. The volume of our production
hedged with swaps and collars that have fixed price ceilings has greatly
diminished for 2005 and is nil for 2006.
The table below provides a summary of gains and losses on derivative contracts:
THREE MONTHS ENDED MARCH 31, 2005 March 31, 2004
------------------------------------------------------- --------------
($THOUSANDS) Oil Currency Electricity Total Total
- ----------------------------------------------------------------------------------------------------------- --------------
Unrealized (losses) / gains on derivative contracts (72,312) (3,047) 4,607 (70,752) --
Realized (loss) / gain on derivative contracts (19,731) 840 166 (18,725) (8,857)
Amortization of deferred charges relating to
derivative contracts (4,361) -- -- (4,361) (5,490)
Amortization of deferred gains relating to derivative
contracts -- -- 445 445 --
- ------------------------------------------------------------------------------------------------------------ ---------------
Total (losses) / gains on derivative contracts (96,404) (2,207) 5,218 (93,393) (14,347)
============================================================================================================ ===============
PREPAID EXPENSES AND DEPOSITS
Our prepaid expenses and deposit accounts include $38.3 million of amounts which
are held on margin for counterparties to our derivative contracts.
DEFERRED CHARGES AND DEFERRED GAINS
The deferred charges asset balance on the balance sheet is comprised of two main
components: deferred financing charges and deferred assets related to the
discontinuation of hedge accounting. The deferred financing charges relate
primarily to the issuance of the senior notes and bank debt and are amortized
over the life of the corresponding debt.
DEFERRED CHARGES
($THOUSANDS) As at March 31, 2005 As at December 31, 2004
- ----------------------------------------------------------------------- --------------------------------------------------
ON DIS- DISCOUNT On Dis- Discount
CONTINUATION ON Continuation Financing on
OF HEDGE FINANCING SENIOR of Hedge Costs Senior
ACCOUNTING COSTS NOTES TOTAL Accounting (restated) Notes Total
- ----------------------------------------------------------------------- --------------------------------------------------
Opening Balance 10,759 12,781 2,000 25,540 -- 1,989 -- 1,989
Additions -- 504 -- 504 25,705 20,971 2,075 48,751
Transferred to -- --
unit issue -- --
costs -- (265) -- (265) -- (5,721) -- (5,721)
Amortization (4,361) (1,647) (74) (6,082) (14,946) (4,458) (75) (19,479)
- ----------------------------------------------------------------------- --------------------------------------------------
Closing Balance 6,398 11,373 1,926 19,697 10,759 12,781 2,000 25,540
======================================================================= ===================================================
We discontinued the use of hedge accounting for all of our derivative financial
instruments effective October 1, 2004. For contracts where hedge accounting had
previously been applied, a deferred charge and a deferred gain was recorded
equal to the fair value of the contracts at the time hedge accounting was
discontinued, and a corresponding amount was recorded as a
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
derivative contracts asset or liability. The deferred amount is recognized in
income in the period in which the underlying transaction is recognized.
At March 31, 2005, the deferred gain remaining on the balance sheet was $1.7
million, all of which related to discontinuing hedge accounting. For the three
month period ended March 31, 2005, $4.4 million of the deferred charge and
$445,000 of the deferred gain has been amortized and recorded in gains and
losses on derivative contracts. At March 31, 2005, a $6.4 million deferred
charge and a $1.7 million deferred gain is remaining relating to the balances
initially set up upon discontinuation of hedge accounting.
GOODWILL
Goodwill is the residual amount that results when the purchase price of an
acquired business exceeds the fair value for accounting purposes of the net
identifiable assets and liabilities of that acquired business. In June 2004, we
completed a Plan of Arrangement with Storm Energy Ltd., and acquired certain oil
and natural gas producing properties in North Central Alberta for total
consideration of $192.2 million. This transaction has been accounted for using
the purchase price method, and resulted in Harvest recording goodwill of $43.8
million in 2004. This goodwill balance will be assessed annually for impairment
or more frequently if events or changes in circumstances occur that would
reasonably be expected to reduce the fair value of the acquired business to a
level below its carrying amount.
FUTURE INCOME TAXES
Future income taxes reflect the net tax effects of temporary differences between
the carrying amounts of assets and liabilities of our corporate operating
subsidiaries for financial reporting purposes and the related income tax
balances. Future income taxes arise, for example, as depletion and depreciation
expense recorded against capital assets differs from claims against related tax
pools. Future income taxes also arise when tax pools associated with assets
acquired are different from the purchase price recorded for accounting purposes.
We recorded a recovery of future income taxes for the three month period ended
March 31, 2005 of $26.0 million, compared to a $2.6 million recovery for the
same period last year. The significant increase in the future income tax
recovery reflects the large loss before taxes and non-controlling interest.
ASSET RETIREMENT OBLIGATION (ARO)
In connection with a property acquisition or development expenditure, we record
the discounted fair value of the ARO as a liability in the year in which an
obligation to reclaim and restore the related asset is incurred, which is
generally when the related well or facility is created or acquired. Our ARO
costs are capitalized as part of the carrying amount of the related assets, and
are depleted and depreciated over our estimated net proved reserves. ARO
estimates are adjusted at the end of each period to reflect the impact of the
passage of time on the discounted present value as well as changes in the
estimated future funds flow that make up the obligation.
Our asset retirement obligation has increased by approximately $2.0 million in
2005 mainly due to future retirement cost estimates associated with current
drilling activity and the accretion of the asset retirement obligation.
NON-CONTROLLING INTEREST
At March 31, 2005, we have recorded a non-controlling interest amount on our
consolidated balance sheet for $3.4 million. The non-controlling interest arises
as a result of adopting the guidance from the Emerging Issues Committee ("EIC")
of the Canadian Institute of Chartered Accountants EIC 151 "Exchangeable
Securities Issued by Subsidiaries of Income Trusts" (see "New Accounting
Policies - Exchangeable Shares"). This EIC requires that when shares are issued
by a subsidiary of a
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
trust, and they are exchangeable into Units of the trust, they should be
classified as either non-controlling interest or equity. EIC 151 requires, among
other things, that the exchangeable shares not be transferable to third parties
in order to be classified as equity. As the exchangeable shares issued by
Harvest Operations Corp. do not meet the criteria to be considered equity of the
Trust, they have been classified as non-controlling interest. Previously, they
had been recorded as part of the equity of the Trust.
The exchangeable shares were originally issued by Harvest Operations Corp. as
partial consideration for the purchase of a corporate entity in 2004. The
exchangeable shares rank equally with the Trust Units and participate in
distributions through an increase in the exchange ratio applied to the
exchangeable shares when they are converted to Trust Units.
Over time, the exchangeable shares will continue to be converted into Trust
Units and the non-controlling interest on the balance sheet will be eliminated.
The non-controlling interest on the balance sheet represents the book value of
the remaining exchangeable shares plus the accumulated earnings or loss of the
Trust attributed to those exchangeable shares. The non-controlling interest on
the income statement represents the current period loss attributed to the
non-controlling interest holders during the period. The total net loss
attributed to non-controlling interest for the three months ended March 31, 2005
was $495,000.
LIQUIDITY AND CAPITAL RESOURCES
Our drilling and operational enhancement programs, as well as current financial
commitments, are expected to be financed from funds flow from operations (see
"Certain Financial Reporting Measures" in this MD&A). Our cash distributions to
Unitholders are financed solely from funds flow from operations. In the first
quarter of 2005, our distribution payout ratio of 48% (calculated by dividing
distributions to Unitholders by funds flow from operations) resulted in excess
funds flow available for our capital expenditure programs. We anticipate that
sufficient funds flow from operations in 2005 will be available to finance our
planned capital development program, expected distributions of $0.20 per Unit
per month and still leave us with sufficient funds to repay a portion of
outstanding bank debt. Given the significant amount of oil price hedges we have
in place, we believe that our funds flow in 2005 will exceed cash distributions
as well as our budgeted capital expenditures under most WTI price scenarios. It
is also important to note that to the extent our Unitholders elect to receive
distributions in the form of Trust Units rather than cash under our Distribution
Reinvestment Plan (DRIP), this further reduces net cash outlays. During the
first quarter of 2005, DRIP participation was approximately 19%.
The table below provides an analysis of our debt structure, including some key
debt ratios. We believe that the current capital structure is appropriate given
our low payout ratio, the significant hedges in place, and the long term to
maturity of the majority of our debt. As noted above, we intend to use funds
flow after distributions and capital expenditures to repay bank debt this year.
AS AT MARCH 31, As at December 31,
($ MILLIONS) 2005 2004 Change
- ----------------------------------------------------------------------------------------------------------------------
Bank debt $ 103.7 $ 75.5 37%
Working capital deficit (surplus) excluding bank debt(2) (3.6) 27.8 113%
Senior notes 302.4 300.5 1%
Convertible debentures 19.1 25.8 (26%)
- ----------------------------------------------------------------------------------------------------------------------
Net debt obligations $ 421.6 $ 429.6 (2%)
- ----------------------------------------------------------------------------------------------------------------------
Annualized quarterly funds flow(1) $ 210.8 $ 211.5 (0%)
Trailing net debt to funds flow (times) 2.0 2.0 -
======================================================================================================================
NOTE 1 REFLECTS REALIZED HEDGING LOSSES WHICH WERE SIGNIFICANT IN THE FIRST
QUARTER GIVEN THE NATURE OF OUR OIL PRICE HEDGES. OUR HEDGES IN 2005
ARE PRIMARILY INSTRUMENTS WHICH DO NOT PLACE A CAP ON WTI PRICE
REALIZATIONS.
NOTE 2 EXCLUDES CURRENT PORTION OF DERIVATIVE CONTRACTS ASSETS AND LIABILITIES
AND TRUST UNIT INCENTIVE PLAN LIABILITY.
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
Since inception, we have communicated our intention to pursue a strategy that
will allow us to sustain at least $0.20 per Unit per month in distributions.
During the first quarter of 2005, the Trust declared $25.4 million in
distributions payable to Unitholders; $0.20 per Trust Unit for each of January,
February and March 2005. This is the same per Unit level paid to Unitholders in
the first quarter of 2004 ($9.1 million). We also declared a special
distribution relating to undistributed 2004 taxable income of $10.7 million. The
higher level of distributions paid in the first quarter of 2005 reflects the
increased number of Trust Units outstanding compared to the first quarter of
2004.
Harvest's payout ratio, which is the ratio of distributions to funds flow from
operations, remains among the lowest in the trust sector. We reported a 48%
payout ratio in the first quarter of 2005, compared to 75% in the same period in
2004. We anticipate that our payout ratio will range between 40% and 50% during
2005, assuming a $0.20 distribution and commodity prices consistent with those
realized in the first quarter. This low payout ratio will provide Harvest
significant flexibility in financing capital and acquisition activities and
servicing our outstanding debt. Reducing our debt helps position us to take
advantage of any future acquisition opportunities.
Of the total first quarter 2005 distributions, the Distribution Reinvestment
Plan ("DRIP") accounted for 19% of total distributions, or $4.8 million
represented by 209,000 Trust Units. Harvest's DRIP enables Unitholders to
reinvest their cash distributions back into Harvest Units, rather than receive
the amount paid in cash. Management anticipates that during 2005, the DRIP will
remain at or near the first quarter level. Should the percentage participation
in our DRIP decrease, we will need to use a larger amount of funds flow to pay
monthly distributions.
Payments to U.S. Unitholders are subject to 15% Canadian withholding tax, which
applies to the taxable portion of the distribution. After consulting with our
U.S. tax advisors, we are of the view that our distributions are "qualified
dividends" under the Jobs and Growth Tax Relief Reconciliation Act of 2003.
These dividends are eligible for the reduced tax rate applicable to long-term
capital gains. However, the distributions may not be qualified dividends in
certain circumstances, depending on the holder's personal situation (i.e. if an
individual holder does not meet a holding period test). Where the distributions
do not qualify, they should be reported as ordinary dividends. U.S. and other
non-resident Unitholders are urged to consult independent legal advice on how
their distributions should be treated for tax purposes.
From time to time the Trust may require external financing, through both debt
and equity, to further its business plan of maintaining production, reserves and
distributions through acquisitions and capital expenditures. Our ability to
obtain the necessary financing is subject to external factors including, but not
limited to, fluctuations in equity and commodity markets, economic downturns and
interest and foreign exchange rates. Adverse changes in these factors could
require Harvest's Management to alter the current business plan of the Trust.
Harvest's bank lending group has set the amount of our credit facility to $325
million, leaving approximately $220 million undrawn at the end of the first
quarter 2005. Dependent upon market conditions, the Trust may draw under this
facility, or complete additional financings in the form of convertible
debentures or Trust Units to expand the capital program or to finance additional
acquisitions. The Trust also has access to and may utilize bridge financing,
similar to that used in 2004, or issue additional senior notes, if required.
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
A breakdown of our outstanding Trust Units and potentially dilutive elements is
as follows:
- -----------------------------------------------------------------------------------------------------------------------------
AS AT MARCH 31, 2005 As at December 31, 2004
- -----------------------------------------------------------------------------------------------------------------------------
Market price of Trust Units at end of period ($/unit) 24.70 22.95
Trust Units outstanding 43,114,827 41,788,500
Exchangeable shares outstanding(1) 244,812 455,547
Trust Units represented by Exchangeable shares 269,753 485,003
Total market value of Trust Units at end of period(2) ($millions) $ 1,072 $ 970
9% Convertible debentures(3), face value $ 9,262,000 $ 10,700,000
8% Convertible debentures(4), face value $ 9,941,000 $ 15,159,000
Trust Unit rights outstanding(5) 1,500,450 1,117,725
Total Trust Units, diluted(6) 46,172,372 45,088,376
=============================================================================================================================
NOTE 1 EXCHANGEABLE SHARES ARE EXCHANGEABLE INTO TRUST UNITS AT THE ELECTION
OF THE HOLDER AT ANY TIME. THE EXCHANGE RATIO IN EFFECT ON MARCH 31,
2005 WAS 1.08991:1, AND ON DECEMBER 31, 2004 WAS 1.06466:1. AS A RESULT
OF THE SPECIAL DISTRIBUTION, THE EXCHANGE RATIO WAS INCREASED TO
1.10188 EFFECTIVE APRIL 15, 2005. THIS REVISED EXCHANGE RATIO WAS USED
TO DETERMINE TRUST UNITS REPRESENTED BY EXCHANGEABLE SHARES.
NOTE 2 INCLUDING TRUST UNITS OUTSTANDING AND ASSUMING EXCHANGE OF ALL
EXCHANGEABLE SHARES.
NOTE 3 EACH DEBENTURE IN THIS SERIES HAS A FACE VALUE OF $1,000 AND IS
CONVERTIBLE, AT THE OPTION OF THE HOLDER AT ANY TIME, INTO TRUST UNITS
AT A PRICE OF $13.85 PER TRUST UNIT. IF DEBENTURE HOLDERS CONVERTED ALL
OUTSTANDING DEBENTURES IN THIS SERIES AT MARCH 31, 2005 AND DECEMBER
31, 2004, AN ADDITIONAL 668,736 (REFLECTS IMPACT OF SPECIAL
DISTRIBUTION ON CONVERSION PRICE) AND 764,286 TRUST UNITS WOULD BE
ISSUABLE, RESPECTIVELY. FOR ACCOUNTING PURPOSES THE CONVERTIBLE
DEBENTURES ARE RECORDED AT A DISCOUNT TO REFLECT THE IMPLIED INTEREST
RATE ON ISSUANCE.
NOTE 4 EACH DEBENTURE IN THIS SERIES HAS A FACE VALUE OF $1,000 AND IS
CONVERTIBLE, AT THE OPTION OF THE HOLDER AT ANY TIME, INTO TRUST UNITS
AT A PRICE OF $16.07 PER TRUST UNIT. IF DEBENTURE HOLDERS CONVERTED ALL
OUTSTANDING DEBENTURES IN THIS SERIES AT MARCH 31, 2005 AND DECEMBER
31, 2004, AN ADDITIONAL 618,606 (REFLECTS IMPACT OF SPECIAL
DISTRIBUTION ON CONVERSION PRICE) AND 932,862 TRUST UNITS WOULD BE
ISSUABLE, RESPECTIVELY. FOR ACCOUNTING PURPOSES THE CONVERTIBLE
DEBENTURES ARE RECORDED AT A DISCOUNT TO REFLECT THE IMPLIED INTEREST
RATE ON ISSUANCE.
NOTE 5 EXERCISABLE AT AN AVERAGE PRICE OF $13.47 PER TRUST UNIT AS AT MARCH
31, 2005, AND $10.09 PER TRUST UNIT AS AT DECEMBER 31, 2004.
NOTE 6 FULLY DILUTED UNITS DIFFER FROM DILUTED UNITS FOR ACCOUNTING
PURPOSES. FULLY DILUTED INCLUDES TRUST UNITS OUTSTANDING AS AT MARCH
31, 2005 OR DECEMBER 31, 2004 PLUS THE IMPACT OF THE CONVERSION OF
EXERCISE OF EXCHANGEABLE SHARES, TRUST UNIT RIGHTS AND CONVERTIBLE
DEBENTURES IF COMPLETED AT MARCH 31, 2005 OR DECEMBER 31, 2004.
($MILLIONS) AS AT MARCH 31, 2005 As at December 31, 2004 % Change
- -----------------------------------------------------------------------------------------------------------------------
Total market capitalization(1) $ 1,071.6 $ 970.2 10%
Net debt 421.6 429.6 (2%)
- -----------------------------------------------------------------------------------------------------------------------
Enterprise value (total capitalization)(2) $ 1,493.2 $ 1,399.8 7%
- -----------------------------------------------------------------------------------------------------------------------
Net debt as a percentage of enterprise value (%) 28% 31% 24%
=======================================================================================================================
NOTE 1 REFLECTS CONVERSION OF EXCHANGEABLE SHARES INTO TRUST UNITS.
NOTE 2 ENTERPRISE VALUE AS PRESENTED DOES NOT HAVE ANY STANDARDIZED MEANING
PRESCRIBED BY CANADIAN GAAP AND THEREFORE IT MAY NOT BE COMPARABLE WITH
THE CALCULATION OF SIMILAR MEASURES FOR OTHER ENTITIES. TOTAL
CAPITALIZATION IS NOT INTENDED TO REPRESENT THE TOTAL FUNDS WE HAVE
RECEIVED FROM EQUITY AND DEBT.
The decrease in net debt as at March 31, 2005 compared to the year ended
December 31, 2004 is primarily the result of the conversion of our convertible
debt to equity. Of the convertible debentures outstanding at March 31, 2005,
approximately $1.5 million have converted into Units through May 4, 2005 and we
anticipate continued conversions through 2005.
CONTRACTUAL OBLIGATIONS
Our contractual obligations have not changed significantly from those disclosed
in the MD&A and financial statements for the year ended December 31, 2004.
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
OFF BALANCE SHEET ARRANGEMENTS
We have a number of immaterial operating leases in place on moveable field
equipment, vehicles and office space. The leases require periodic lease payments
and are recorded as either operating costs or G&A. We also finance our annual
insurance premiums, whereby a portion of the annual premium is deferred and paid
monthly over the balance of the term.
RELATED PARTY TRANSACTIONS
A corporation controlled by one of our directors sublets office space from us
and we provide administrative services to that corporation on a cost recovery
basis. See Note 12 to the Consolidated Financial Statements.
CAPITAL ASSET EXPENDITURES
Development capital expenditures, excluding minor property acquisitions totaled
$23.2 million for the three month period ended March 31, 2005. This compares to
$10.2 million in the first quarter of 2004. The increase is due to several
factors, including higher drilling activity, and additional well workovers and
optimization activities.
Despite rising asset costs, we are continuing to review opportunities within the
acquisition market. We successfully transacted several minor asset acquisitions
during the quarter. These transactions included land and minor working interest
acquisitions, both of which contribute to Harvest's development strength and
presence in our core areas.
At the time of writing, we have identified approximately 300 potential drilling
locations for Harvest, and anticipate further additions to this list as we
continue to develop our properties. In 2005, we plan to drill 70 net wells and
will continue to be active in analyzing potential acquisition opportunities. In
the event the acquisition market becomes too expensive and Harvest cannot create
value by purchasing assets, we have a healthy drilling inventory for at least
two years.
SENSITIVITIES
The table below indicates the impact of changes in key variables on several
financial measures of Harvest. The figures in this table are based on the Units
outstanding as at March 31, 2005 and our existing hedging program, and are
provided for directional information only.
Variable
-------------------------------------------------------------------------------------------
WTI Heavy Oil Price Crude Oil Canadian Bank Foreign Exchange
Price/bbl differential/bbl Production Prime Rate Rate Cdn. / U.S.
- ---------------------------------------------------------------------------------------------------------------------------------
Assumption $40.00 U.S. $15.00 U.S. 35,000 bbl/d 4.25% 1.21
Change (plus or minus) $ 1.00 U.S. $ 1.00 U.S. 1,000 bbl/d 1% 0.01
ANNUALIZED IMPACT ON:
Funds flow from operations ($000's) $ 4,300 $ 6,200 $ 12,010 $ 750 $ 2,100
Per Trust Unit, basic $ 0.10 $ 0.14 $ 0.27 $ 0.02 $ 0.05
Per Trust Unit, diluted $ 0.10 $ 0.14 $ 0.27 $ 0.02 $ 0.05
Payout ratio 1.4% 2.1% 4.2% 0.3% 0.7%
==================================================================================================================================
As noted above, our commodity price risk management program can reduce
sensitivities due to the oil price derivatives executed under our risk
management program. Those contracts in place as at March 31, 2005 are summarized
in the table below. The prices shown for collars, indexed puts and participating
swaps are floor prices. The nature of the indexed puts and participating swaps
allow us to participate in positive price movements above these levels, while
providing fixed price realizations if the market price drops below the floor
price.
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
2005 2006
------------------------------------------------------------------------------
Volume (bbls/d) Pricing ($/bbl) Volume (bbls/d) Pricing ($/bbl)
- -----------------------------------------------------------------------------------------------------------------
WTI Crude Oil Swaps 841 $ 23.26 -- --
WTI Crude Oil Collars 3,831 $ 28.13 -- --
WTI Indexed Put Contracts 18,500 $ 35.95 3,719 $ 34.00
WTI Participating Swaps -- -- 11,271 $ 39.73
=================================================================================================================
CRITICAL ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES
Our critical accounting policies and estimates are substantially the same as
those presented in our 2004 annual MD&A.
IMPACT ON NET INCOME OF CHANGE IN ACCOUNTING POLICIES
The implementation of new accounting policies in 2005 as discussed below
resulted in changes to the accounting treatment for exchangeable shares,
convertible debentures and the equity bridge notes. As a result, we have
restated previously reported annual and quarterly net income. The restatements
were required per the transitional provisions of the respective accounting
standards.
The following table illustrates the impact of the new accounting policies on
annual net income and net income per Unit for periods which have been presented
for comparative purposes and were impacted by the restatements.
($ THOUSANDS) Year Ended December 31, 2004
- -------------------------------------------------------------------------------
Net income before change in accounting policies(1) 18,231
Increase (decrease) in net income:
Interest expense(2) (6,765)
Non-controlling interest(3) (225)
- -------------------------------------------------------------------------------
Net income after change in accounting policies 11,241
- -------------------------------------------------------------------------------
Net income per Trust Unit, as reported
Basic 0.47
Diluted 0.45
Net income per Trust Unit, as restated
Basic 0.45
Diluted 0.43
===============================================================================
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
The following table illustrates the impact of the new accounting policies on
quarterly net income (loss) and net income (loss) per Unit for periods which
have been presented for comparative purposes:
2004
---------------------------------------------------------------
($ THOUSANDS) Q4 Q3 Q2 Q1
- -----------------------------------------------------------------------------------------------------------------------
Net Income (loss) before change in accounting policies(1) 12,536 5,166 1,594 (1,065)
Increase (decrease) in net income:
Interest expense(2) (751) (3,386) (1,443) (1,185)
Non-controlling interest(3) (185) (40) -- --
Net income (loss) after change in accounting policies 11,600 1,740 151 (2,250)
Net income (loss) per Trust Unit, as reported
Basic 0.29 0.07 0.02 (0.13)
Diluted 0.28 0.07 0.02 (0.13)
Net income (loss) per Trust Unit, as restated
Basic 0.29 0.06 0.01 (0.13)
Diluted 0.27 0.06 0.01 (0.13)
=======================================================================================================================
NOTE 1 THIS REPRESENTS NET INCOME AS REPORTED BEFORE RETROACTIVE RESTATEMENT
FOR CHANGES IN ACCOUNTING POLICIES.
NOTE 2 ADOPTION OF THE AMENDMENT TO CICA HANDBOOK SECTION 3860 "FINANCIAL
INSTRUMENTS - DISCLOSURE AND PRESENTATION" RESULTED IN THE CONVERTIBLE
DEBENTURES AND EQUITY BRIDGE NOTES BEING CLASSIFIED AS DEBT WHEREAS
PREVIOUSLY THEY WERE CLASSIFIED AS EQUITY. IN ADDITION, THE INTEREST
EXPENSE RELATING TO THESE INSTRUMENTS WAS REQUIRED TO BE CHARGED
AGAINST NET INCOME RATHER THAN DIRECTLY TO ACCUMULATED INCOME. ALSO,
THE DEFERRED FINANCING CHARGES ASSOCIATED WITH THE CONVERTIBLE
DEBENTURES ARE NOW REFLECTED SEPARATELY IN DEFERRED CHARGES ON THE
BALANCE SHEET AND AMORTIZED TO INCOME OVER THE TERM OF THE DEBT;
PREVIOUSLY THEY WERE APPLIED AS A REDUCTION TO THE OUTSTANDING BALANCE.
NOTE 3 ADOPTION OF EIC 151 "EXCHANGEABLE SECURITIES ISSUED BY SUBSIDIARIES OF
INCOME TRUSTS", RESULTED IN THE EXCHANGEABLE SHARES BEING CLASSIFIED AS
MINORITY INTEREST AND THE INCOME ATTRIBUTED TO MINORITY INTEREST
HOLDERS BEING APPLIED AGAINST NET INCOME.
NEW ACCOUNTING POLICIES
FINANCIAL INSTRUMENTS
On January 1, 2005, the Trust retroactively adopted the amendment to the
Canadian Institute of Chartered Accountants ("CICA") handbook section 3860
"Financial Instruments". These changes require that fixed-amount contractual
obligations that can be settled by issuing a variable number of equity
instruments be classified as liabilities. The convertible debentures and the
equity bridge notes previously issued by the Trust have characteristics that
meet the noted criteria and we have retroactively accounted for these
instruments as debt and reflected related interest costs as interest expense in
the statement of income.
EXCHANGEABLE SHARES
On January 19, 2005, the CICA issued EIC-151 "Exchangeable Securities Issued by
Subsidiaries of Income Trusts" that states that equity interests held by third
parties in subsidiaries of an income trust should be reflected as either
non-controlling interest or debt in the consolidated balance sheet unless they
meet certain criteria. EIC-151 requires that the shares be non-transferable in
order to be classified as equity. The exchangeable shares issued by Harvest
Operations Corp. are transferable and, in accordance with EIC-151, have been
reclassified to non-controlling interest on the consolidated balance sheet. In
addition, a portion of consolidated income or loss before non-controlling
interest is reflected as a reduction to such income or loss in the Trust's
consolidated statement of income. Prior periods have been retroactively
restated.
VARIABLE INTEREST ENTITIES ("VIES")
In June 2003, the CICA issued Accounting Guideline 15 "Consolidation of Variable
Interest Entities" ("AcG-15"). AcG-15 defines VIEs as entities in which either:
the equity at risk is not sufficient to permit that entity to finance its
activities without
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
additional financial support from other parties; or equity investors lack voting
control, an obligation to absorb expected losses or the right to receive
expected residual returns. AcG-15 harmonizes Canadian and U.S. GAAP and provides
guidance for companies consolidating VIEs in which it is the primary
beneficiary. The guideline is effective for all annual and interim periods
beginning on or after November 1, 2004. We have performed a review of entities
in which Harvest has an interest and have determined that we do not have any
variable interest entities at this time.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
In an effort to harmonize Canadian GAAP with U.S. GAAP, the Canadian Accounting
Standards Board has recently issued new Handbook sections:
o 1530, Comprehensive Income;
o 3855, Financial Instruments - Recognition and Measurement; and
o 3865, Hedges.
Under these new standards, all financial assets should be measured at fair value
with the exception of loans, receivables and investments that are intended to be
held to maturity and certain equity investments, which should be measured at
cost. Similarly, all financial liabilities should be measured at fair value when
they are held for trading or they are derivatives. Gains and losses on financial
instruments measured at fair value will be recognized in the income statement in
the periods they arise with the exception of gains and losses arising from:
o financial assets held for sale, for which unrealized gains and losses are
deferred in other comprehensive income until sold or impaired; and
o certain financial instruments that qualify for hedge accounting.
Sections 3855 and 3865 make use of the term "other comprehensive income". Other
comprehensive income comprises revenues, expenses, gains and losses that are
excluded from net income. Unrealized gains and losses on qualifying hedging
instruments, unrealized foreign exchange gains and losses, and unrealized gains
and losses on financial instruments held for sale will be included in other
comprehensive income and reclassified to net income when realized. Comprehensive
income and its components will be a required disclosure under the new standard.
These standards are effective for interim and annual financial statements
relating to fiscal years beginning on or after October 1, 2006. As we do not
apply hedge accounting to any of our derivative instruments, we do not expect
these pronouncements to have a significant impact on our consolidated financial
results other than as it relates to unrealized foreign exchange gains and
losses.
NON-MONETARY TRANSACTIONS
The AcSB has approved revisions to Section 3830, Non-Monetary Transactions, that
require all non-monetary transactions to be measured at fair market value
unless:
o the transaction lacks commercial substance;
o the transaction is an exchange of production or property held for sale in
the ordinary course of business for production or property to be sold in
the same line of business to facilitate sales to customers other than the
parties to the exchange;
o neither the fair value of the assets or services received nor the fair
value of the assets or services given up is reliably measurable; or
o the transaction is a non-monetary, non-reciprocal transfer to owners that
represents a spin-off or other form of restructuring or liquidation.
The new requirements apply to non-monetary transactions, initiated in periods
beginning on or after January 1, 2006. Earlier adoption is permitted as of the
beginning of a period beginning on or after July 1, 2005. We do not expect the
adoption of this section will have any material impact on our results of
operations or financial position.
HARVEST ENERGY TRUST 1ST QUARTER 2005
- --------------------------------------------------------------------------------
OPERATIONAL AND OTHER BUSINESS RISKS
Our operational and other business risks are substantially the same as those
presented in our 2004 annual MD&A.
KEY PERFORMANCE INDICATORS AND OUTLOOK
We have indicated guidance on full year 2005 performance measures elsewhere in
this MD&A.
Harvest plans to continue with its business plan of acquiring and operating high
quality, mature crude oil and natural gas properties that can be enhanced
through operational and exploitation techniques. Harvest also plans to continue
to identify new areas in the Western Canadian sedimentary basin that can support
sustainable distributions and growth in net asset value per Unit.
It is important to note that any future guidance provided is based upon
management's current expectations. The ultimate results may vary, perhaps
materially.
Additional information on Harvest Energy Trust, including our most recently
filed Annual Information Form and annual report, can be accessed from SEDAR at
www.sedar.com or from our website at www.harvestenergy.ca.