EXHIBIT 3
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HARVEST ENERGY TRUST 2ND 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 and six
month periods ended June 30, 2005. Certain comparative figures have been
reclassified to conform with the current period presentation.
All references are to Canadian dollars unless otherwise indicated. Natural gas
volumes recorded in thousand cubic feet ("mcf") are converted to barrels of oil
equivalent ("BOE") using the ratio of six (6) thousand cubic feet to one (1)
barrel of oil ("bbl"). BOE's may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf:1 bbl is based on an energy
equivalent conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the wellhead.
FORWARD-LOOKING INFORMATION
This second 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 August 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 before changes in
non-cash working capital and settlement of asset retirement obligations ("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 (referred to as cash flow from
operations in our year end 2004 MD&A), to analyze operating performance and
leverage. Funds Flow from Operations 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. For the three and six
month periods ended June 30, 2005 and 2004, Funds Flow from Operations is
reconciled to its closest GAAP measure, cash flow from operating activities, as
follows:
Three months Six months
THREE MONTHS ENDED ended June 30, SIX MONTHS ENDED ended June 30,
$000S JUNE 30, 2005 2004 JUNE 30, 2005 2004
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Funds Flow from Operations before changes in
non-cash working capital and settlement
of asset retirement obligations 57,217 15,839 109,904 29,573
Changes in working capital (6,983) 137 (55,677) (2,158)
Settlement of asset retirement obligations (663) (89) (1,164) (153)
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Cash flow from operating activities 49,571 15,887 53,063 27,262
====================================================================================== ===================================
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
HARVEST ENERGY TRUST 2ND QUARTER 2005
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processes to extract maximum value. These operational processes 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 from Operations. The Trust has operations in four
core areas: Northern (which includes the newly acquired Hay River property in
Northeast British Columbia), East Central Alberta, Southern Alberta and
Southeast Saskatchewan.
SUBSEQUENT ACQUISITIONS AND EVENTS
Subsequent to the end of the quarter, on August 2, 2005, we closed the
acquisition of the Hay River property, as well as a $250 million bought deal
financing. The impact of the acquisition and financing on Harvest's financial
statements is effective as of the closing date.
Operationally, the addition of the Hay River property increased our production
by approximately 5,200 BOE/d to between 39,000 to 40,000 BOE/d at the time of
writing. At approximately $7.75/BOE, the operating expenses at Hay River are
lower than Harvest's average, which should reduce our overall operating expenses
and improve our netbacks. Given the accretive nature of the transaction, our per
Trust Unit Funds Flow from Operations is expected to increase. However, our
royalties as a percentage of revenue will increase as Hay River has a royalty
rate of approximately 23% compared to our current royalty rate of 16%. Average
price received should improve with the addition of these barrels which sell at a
premium to our average medium gravity crude production, and overall, we would
expect to see an improvement in our netback as a result.
The proceeds from the bought deal financing were used to repay bank debt
incurred in the Hay River property acquisition. We issued 6.5 million Trust
Units at $26.90 for $175 million, and $75 million of 6.5% convertible
debentures, with a conversion price of $31.00. As a result of the offering, we
have approximately 50.3 million Trust Units outstanding, approximately $85
million of convertible debentures outstanding, and net debt (excluding
convertible debentures) at a level consistent with that reported at June 30,
2005.
The listing of our Trust Units on the NYSE took place on July 21, 2005, and we
believe this will lead to improved access to U.S. equity markets and greater
financing flexibility.
HARVEST ENERGY TRUST 2ND 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
------------------------ ----------------------------------------------- -----------------------
FINANCIAL Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
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Revenue, net of royalties $ 120,263 $ 109,931 $ 106,964 $ 85,096 $ 44,461 $ 39,298 $ 33,575 $ 24,706
Operating expense (28,635) (27,348) (25,725) (19,538) (14,306) (13,873) (13,335) (10,271)
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Net operating income(1) $ 91,628 $ 82,583 $ 81,239 $ 65,558 $ 30,155 $ 25,425 $ 20,240 $ 14,435
Net income (loss) 19,516 (43,070) 11,600 1,740 151 (2,250) 5,495 5,488
Per Trust Unit, basic(2) 0.45 (1.02) 0.29 0.06 0.01 (0.13) 0.30 0.44
Per Trust Unit, diluted(2) 0.44 (1.02) 0.27 0.06 0.01 (0.13) 0.29 0.43
Funds Flow from Operations(1,2,3) 57,217 52,687 52,870 41,267 15,839 13,734 13,699 16,758
Per Trust Unit, basic(1,2) 1.32 1.25 1.31 1.42 0.91 0.80 0.85 1.35
Per Trust Unit, diluted(1,2) 1.29 1.19 1.18 1.12 0.78 0.67 0.82 1.31
SALES VOLUMES
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Crude oil (bbl/d) 28,855 30,087 30,992 22,397 14,775 14,626 14,497 11,054
Natural gas liquids (bbl/d) 798 780 1,309 377 141 50 70 77
Natural gas (mcf/d) 28,857 27,114 28,338 11,909 2,249 915 1,744 1,453
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Total (BOE/d) 34,463 35,386 37,024 24,759 15,291 14,829 14,858 11,373
====================================================================================================================================
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 FUNDS FLOW FROM OPERATIONS IN 2005 INCLUDES INTEREST ON CONVERTIBLE
DEBENTURES AND EQUITY BRIDGE NOTES. IN PRIOR PERIODS, THIS WAS PART OF
CASH FLOW FROM FINANCING ACTIVITIES.
The above table highlights Harvest's performance for the second quarter of 2005,
and the preceding 7 quarters.
Net revenues and net operating income have trended steadily higher over the
eight quarters shown above, with the most significant increase through the third
and fourth quarters of 2004. 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 from Operations since the second
quarter 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 half of 2005.
Net income reflects both cash and non-cash items. Changes in non-cash items,
including depletion, depreciation and accretion (DD&A), unrealized foreign
exchange gains and losses, 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
from Operations 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 from Operations. 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 at the end of the period of $70.7
million. Net income for the three month period ended June 30, 2005 was $19.5
million. Lower mark-to-market losses in the second quarter reduced the impact on
net income for that period. Mark-to-market losses arise from changes in the fair
values of the derivative contracts in the period. We ceased hedge accounting for
all of our derivative instruments in October 2004 and this has accounted for
increased volatility in our earnings.
Funds Flow from Operations is a very important measure for a royalty trust
because it represents the source for cash distributions to Unitholders. Funds
Flow from Operations enables us to repay debt and also finances capital
expenditures which are used to replace produced reserves, leading to
sustainability. Our low payout ratio is a key competitive advantage in creating
future sustainability. Excluding the substantial non-recurring foreign exchange
gain realized in the third quarter of 2003, our Funds Flow from Operations has
demonstrated a strengthening trend. Funds Flow from Operations can be impacted
by factors outside of management's control such as commodity prices and currency
exchange rates. We strive to mitigate the impact of these factors by using
hedging (generally referred to herein as 'derivatives' or 'derivative
contracts')
HARVEST ENERGY TRUST 2ND QUARTER 2005
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on a portion of our transactions to establish a fixed floor for future commodity
prices, and mitigate the impact of fluctuating heavy oil price differentials and
currency exchange rates.
REVENUES
Three months ended June 30 Six months ended June 30
--------------------------------- -------------------------------------
2005 2004 Change 2005 2004 Change
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Oil and natural gas sales ($/BOE) 45.67 38.30 19% 43.20 36.77 17%
Royalty expense ($/BOE) (7.32) (6.35) 15% (6.78) (6.21) 9%
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Net revenues ($/BOE) 38.35 31.95 20% 36.42 30.56 19%
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Net revenues ($ millions) 120.3 44.5 170% 230.2 83.8 175%
==================================================================== =====================================
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 substantially increased
production volumes, and a crude oil price environment that has continued to
strengthen for the past 4 quarters, our net revenues in the three and six month
periods ending June 30, 2005 increased 170% and 175%, respectively, over the
same periods 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
At 34,463 BOE/d, second quarter 2005 sales volumes were in line with our
original full-year target of between 34,000 and 36,000 BOE/d and were 125%
higher than the 15,291 BOE/d realized in the three month period ended June 30,
2004. Volumes averaged 34,921 BOE/d for the first six months of 2005, and were
132% higher than the 15,060 BOE/d realized in the same period in 2004. This
increase in production year-over-year is due to the volumes associated with
properties acquired in June and September 2004, as well as successful
development and optimization work across our core areas.
The average daily sales volumes by product were as follows:
THREE MONTHS ENDED JUNE 30
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2005 2004
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VOLUME WEIGHTING Volume Weighting % Change
---------------------- --------------------- ------------
Light oil (Bbl/d) 9,826 29% 5,216 34% 88%
Medium oil (Bbl/d) 5,510 16% 4,082 27% 35%
Heavy oil (Bbl/d) 13,519 39% 5,477 36% 147%
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Total oil (Bbl/d) 28,855 84% 14,775 97% 95%
Natural gas liquids (Bbl/d) 798 2% 141 1% 466%
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Total oil and natural gas liquids (Bbl/d) 29,653 86% 14,916 98% 99%
Natural gas (mcf/d) 28,857 14% 2,249 2% 1183%
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Total oil equivalent (BOE/d) 34,463 100% 15,291 100% 125%
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HARVEST ENERGY TRUST 2ND QUARTER 2005
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SIX MONTHS ENDED JUNE 30
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2005 2004
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VOLUME WEIGHTING Volume Weighting % Change
---------------------- ---------------------- ------------
Light oil (Bbl/d) 9,884 28% 5,134 34% 93%
Medium oil (Bbl/d) 5,590 16% 4,116 27% 36%
Heavy oil (Bbl/d) 13,993 40% 5,451 36% 157%
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Total oil (Bbl/d) 29,467 84% 14,701 97% 100%
Natural gas liquids (Bbl/d) 789 2% 95 1% 731%
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Total oil and natural gas liquids (Bbl/d) 30,256 87% 14,796 98% 104%
Natural gas (mcf/d) 27,990 13% 1,582 2% 1669%
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Total oil equivalent (BOE/d) 34,921 100% 15,060 100% 132%
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Second quarter 2005 production was impacted by unusually heavy rainfall and
flooding in Alberta and Saskatchewan, primarily at Suffield and Hayter,
resulting in lower realized heavy oil production relative to capacity. Extended
turnarounds in Killarney and East Hayter resulted in an extended period of
shut-in production in those areas as well.
Following the Hay River, B.C. property acquisition on August 2, 2005, an
additional 5,200 BOE/d of medium gravity crude oil was added to our production,
resulting in revised forecasts for full year 2005 production volumes. We now
estimate that Harvest's full year 2005 production will average between 36,000
and 37,000 BOE/d.
REALIZED COMMODITY PRICES
The following table provides a breakdown of our first quarter and year to date
2005 and 2004 average commodity prices by product type before realized losses on
derivative contracts.
THREE MONTHS ENDED JUNE 30 SIX MONTHS ENDED JUNE 30
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2005 2004 Change 2005 2004 Change
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Product prices:
Light oil ($/bbl) $ 59.13 $ 44.28 34% $ 57.47 $ 42.71 35%
Medium oil ($/bbl) 43.43 36.95 18% 41.44 36.69 13%
Heavy oil ($/bbl) 36.04 33.53 7% 33.79 31.17 8%
Natural gas liquids ($/bbl) 47.31 30.39 56% 41.75 31.60 32%
Natural gas ($/mcf) 7.92 5.91 34% 7.25 5.78 25%
---------------------------------------------------------------------- -------------------------------
BOE ($/BOE) $ 45.67 $ 38.30 19% $ 43.20 $ 36.77 17%
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Realized loss on derivative
contracts gain (loss) ($/BOE)(1) (7.49) (8.80) 15% (6.71) (7.77) 14%
Realized price after hedging ($/BOE) $ 38.18 $ 29.50 29% $ 36.49 $ 29.00 26%
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(1) INCLUDES AMOUNTS REALIZED ON OIL AND FOREIGN EXCHANGE CONTRACTS, AND
EXCLUDES AMOUNTS REALIZED ON ELECTRICITY CONTRACTS.
Average realized prices continued to strengthen during the second quarter and
were 19% higher during the period compared to the second quarter of 2004. For
the first six months of 2005, our average realized prices were 17% higher than
the same period in 2004. In the three and six months ended June 30, 2005,
revenues were impacted by realized losses on commodity derivative contracts
totaling $23.5 million and $42.4 million, respectively. This is higher than the
$12.2 million and $21.3 million losses realized in the three and six months
ended June 30, 2004, respectively. However, on a per BOE basis, our realized
losses relative to revenue for the three month period ended June 30, 2005
decreased to $7.49 / BOE compared to $8.80 / BOE in the same period in 2004. For
the six month period ended June 30, 2005, the realized loss per BOE relative to
revenue was $6.71 /BOE compared to $7.77 / BOE in the same period the previous
year.
The decline in hedging losses per BOE in 2005 despite a 40% increase in WTI
reflects our new hedging strategy in 2005, which is to provide firm floors with
upside participation. We anticipate that these structures will enable us to
realize oil prices that are closer to spot price levels during 2005 and 2006
than would have been the case with our 2004 hedging
HARVEST ENERGY TRUST 2ND QUARTER 2005
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instruments which were primarily swaps and collars. The table below provides an
example of the impact of Harvest's 2005 commodity derivative contracts in light
of varying WTI oil price levels. This data is designed to provide readers with
directional information only.
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Average Annual Oil Price Scenario ($U.S.) Harvest Average WTI Oil Price After Hedging ($U.S.)
- ------------------------------------------- ---------------------------------------------------
$35.00 WTI $38.21
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$55.00 WTI $49.55
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$75.00 WTI $67.55
===============================================================================================
At the time of writing, we have entered into oil price derivative contracts on
approximately 72% of our total 2005 net crude oil production, approximately 50%
of our estimated 2006 net crude oil production, and 14% of our estimated 2007
net crude oil production (based on an assumption of flat production through
2007). The majority of our 2005 and all of our 2006 and 2007 commodity
derivative contracts provide a fixed crude oil floor price, while retaining the
ability to participate in upward price appreciation. Examples of such contracts
include 'indexed puts' and 'participating swaps', and additional information on
these and other commodity derivative contracts can be found in the "Derivative
Contracts" section of this MD&A.
Three months ended June 30 Six months ended June 30
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Benchmarks 2005 2004 Change 2005 2004 Change
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West Texas Intermediate crude oil (US$ / bbl) $ 53.17 $ 38.32 39% $ 51.51 $ 36.73 40%
Edmonton Par light crude ($ / bbl) $ 65.79 $ 50.59 30% $ 63.67 $ 48.09 32%
Lloyd blend crude oil ($ / bbl) $ 39.65 $ 36.14 10% $ 38.54 $ 34.67 11%
Bow river blend crude oil ($ / bbl) $ 39.72 $ 37.12 7% $ 39.07 $ 35.77 9%
Natural Gas Liquids ($ / bbl) $ 51.16 $ 41.48 23% $ 51.51 $ 39.82 29%
AECO natural gas ($ / mcf) $ 7.38 $ 6.80 9% $ 7.03 $ 6.71 5%
U.S. / Canadian dollar exchange rate 1.244 1.360 (9%) 1.236 1.339 (8%)
Bank of Canada interest rate 2.75% 2.72% 0.03% 2.75% 2.50% 0.25%
==========================================================================================================================
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 denominated in
U.S. dollars. With a second quarter production weighting to natural gas of
approximately 13% compared to 1% in the second quarter of 2004, fluctuations in
natural gas prices now have a greater impact on our revenue than in 2004.
A stronger Canadian dollar and wider differentials for heavy crude versus WTI
tempered the effect of higher worldwide crude prices on our revenues during the
three and six months ended June 30, 2005 relative to the same periods in 2004.
The price of WTI was approximately 39% higher in the second quarter of 2005 and
40% higher in the six months ended June 30, 2005 relative to the same periods in
2004 but was somewhat offset by a much stronger Canadian dollar.
The differential between heavy and light crude oil prices narrowed toward the
end of the second quarter; however, heavy oil in Canada was priced at an average
of 40% discount to WTI during the second quarter. This compares to a 31%
differential in the second quarter of 2004. The narrowing differentials late in
the quarter can be attributed to a number of factors including increased demand
for heavier products in Asia and the onset of the summer paving season and
increased demand for asphalt. Harvest has taken steps to mitigate the future
impact of fluctuating heavy oil differentials with two new hedges entered into
in the second quarter which take effect in July 2005. See "Derivative
Contracts".
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.
The production acquired from the Hay River property is
HARVEST ENERGY TRUST 2ND QUARTER 2005
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primarily medium gravity crude, but has historically realized differentials
which are significantly less than the typical medium oil differential of $15.00
to $25.00.
ROYALTIES
In the second quarter of 2005, royalties as a percentage of revenues before
hedging loss, were approximately 16% compared to 16.6% in the second quarter of
2004. For the six month period ended June 30, 2005, royalties as a percent of
revenue were 15.7%, compared to 16.9% in the same period in 2004. This decrease
from 2004 is primarily attributable to the impact of the lower royalty rate
properties acquired in September 2004. The Saskatchewan government recently
changed its legislation to make its resource surcharge applicable to trusts
producing oil and natural gas in the province effective April 1, 2005. The
surcharge is 3.6% of gross resource revenues (2% for production from wells
drilled subsequent to October 2002). We estimate the blended rate applied to
Harvest's Saskatchewan properties will be approximately 3.2% with Saskatchewan
revenues which makes up 20% of Harvest's total. This increased our royalty rate
from 15% in the first quarter of 2005 to 16% in the second quarter of 2005. The
new Hay River properties acquired in August 2005 have a higher royalty rate,
which is estimated to increase our overall royalty rates to approximately 18% to
19% for the latter half of 2005.
OPERATING EXPENSES
Three months ended June 30 Six months ended June 30
------------------------------- -------------------------------------
($ PER BOE) 2005 2004 Change 2005 2004 Change
- ------------------------------------------------------------------- -------------------------------------
Operating expense $ 9.13 $ 10.28 (11%) $ 8.86 10.28 (14%)
Realized gains on electricity
derivative contracts (0.05) (0.51) (90%) (0.05) (0.33) (85%)
- ------------------------------------------------------------------- -------------------------------------
Net operating expense $ 9.08 $ 9.77 (7%) $ 8.81 $ 9.95 (11%)
==========================================================================================================
The decrease in operating expenses (before gains on electricity derivative
contracts), during the second quarter of 2005 compared to the second quarter of
2004 reflects lower cost assets purchased in 2004, as well as the effect of
operating cost reduction projects completed in 2004. These operating cost
reductions have been somewhat offset by cost inflation in the Western Canadian
oil and natural gas sector and the impact of incremental workover costs spread
over lower volumes due to the downtime which occurred due to turnarounds and
flooding, as described under "Sales Volumes". The Hay River properties acquired
in August 2005 have lower operating costs at approximately $7.75/BOE, which will
result in slightly lower operating costs per BOE through the balance of 2005.
For the three and six month periods ended June 30, 2005, approximately 25% and
27%, respectively, of our operating costs is related to the consumption of
electricity. Over the last 9 months the 450 megawatts (MW) of additional power
from the Genesee #3 coal-fired plant in Alberta has proven to dampen both
electricity price volatility and spot market prices. Management has also
utilized fixed price electricity contracts to mitigate electricity price risk
within Alberta. Our electricity hedges (approximately 85% of our estimated
Alberta electricity usage is hedged at an average price of $47.71 per MWh
through December 2006) will help further moderate the impact of cost swings, as
will realizing the benefits of capital projects undertaken in 2004 that were
dedicated to power efficiency projects.
Three months ended June 30 Six months ended June 30
----------------------------------- -------------------------------------
Benchmark Price 2005 2004 Change 2005 2004 Change
- -------------------------------------------------------------------------------------- -------------------------------------
Alberta Power Pool electricity price ($ per MWh) $ 51.46 $ 60.07 (14%) 48.67 54.43 (11%)
============================================================================================================================
HARVEST ENERGY TRUST 2ND QUARTER 2005
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GENERAL AND ADMINISTRATION EXPENSES ("G&A")
Three months ended June 30 Six months ended June 30
----------------------------------- ---------------------------------
($MILLIONS EXCEPT PER BOE) 2005 2004 Change 2005 2004 Change
- ----------------------------------------------------------------------------- ---------------------------------
G&A - cash $ 2.9 1.5 93% 6.2 2.7 130%
Per BOE ($/BOE) 0.94 1.07 (12%) 0.98 0.98 0%
G&A - non-cash unit compsentation expense 3.7 0.2 1750% 5.9 0.4 1375%
Per BOE ($/BOE) 1.17 0.15 680% 0.93 0.14 564%
- ----------------------------------------------------------------------------- ---------------------------------
Total G&A $ 6.6 $ 1.7 288% 12.1 3.1 290%
Per BOE ($/BOE) $ 2.11 $ 1.22 73% $ 1.91 $ 1.12 71%
================================================================================================================
The increase in cash G&A, excluding unit right compensation expense, is the
result of higher staff and system expenses associated with the additional
properties in our portfolio. For 2005, we anticipate that Harvest's cash G&A/BOE
will be less than $1.00/BOE, before unit right compensation expense. Management
does not anticipate a significant increase in cash G&A expenses associated with
the Hay acquisition and increased production should result in slightly lower
cash G&A/BOE. However, Trust Unit prices have increased significantly since June
30, 2005, which could lead to a higher unit right compensation expense in the
third quarter.
General and administration expenses charged against income in the second quarter
of 2005 totaled $6.6 million ($2.11/BOE) compared to $1.7 million ($1.22/BOE) in
the same quarter in 2004. For the six month period ended June 30, 2005, G&A
charged against income totaled $12.1 million ($1.91/BOE) compared to $3.1
million ($1.12/BOE) in the same period in 2004.
The significant increase in G&A in 2005 compared to 2004 is a result of a
modification made to our Unit Incentive Rights Plan in the fourth quarter of
2004, resulting in a prospective change in accounting for Unit appreciation
rights (UARs). In the third quarter of 2004, the Plan was modified so
unitholders could settle in cash and therefore we now value vested UARs at the
difference between exercise price and market price at each reporting period end
to determine the related liability at that date. Changes in the assumptions used
in determining this liability, such as our Trust Unit price, the exercise price
and the number of UARs vested at each accounting period will cause this
liability to fluctuate and the difference is reflected as an expense on the
consolidated statement of income.
INTEREST EXPENSE
Three months ended June 30 Six months ended June 30
------------------------------------ -------------------------------------
2005 2004 Change 2005 2004 Change
($MILLIONS) (RESTATED) (RESTATED)
- -------------------------------------------------------------------------------------- -------------------------------------
Interest on short term debt $ 1.6 $ 0.4 300% $ 2.8 $ 1.1 155%
Amortization of deferred charges - short term debt 1.3 0.6 117% 2.5 1.3 92%
- ----------------------------------------------------------------------------------------------------------------------------
Total interest on short term debt 2.9 1.0 190% $ 5.3 $ 2.4 121%
- ----------------------------------------------------------------------------------------------------------------------------
Interest on long term debt 6.6 1.3 408% 13.0 2.2 491%
Amortization of deferred charges - long term debt 0.3 0.1 200% 0.8 0.2 300%
- ----------------------------------------------------------------------------------------------------------------------------
Total interest on long term debt 6.9 1.4 393% 13.8 2.4 475%
- ----------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 9.8 $ 2.4 308% $ 19.1 $ 4.8 298%
============================================================================================================================
In the three and six month periods ended June 30, 2005, cash interest on short
term debt totaled $1.6 million and $2.8 million, compared to $0.4 million and
$1.1 million for the same periods in 2004. Interest on short term debt relates
to the interest paid on our outstanding bank debt. Cash interest on long term
debt totaled $6.6 million and $13.0 million in the second quarter and six months
ended June 30, 2005, and $1.3 million and $2.2 million in the same periods in
2004. Of the interest on long term debt, $6.2 million in the three month period
and $12.2 million in the six month period ended June 30, 2005 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 can be redeemed
after four years. For the three and six month periods ending June 30, 2005, the
remaining $0.4 million and $0.8 million 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
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
standards that came into effect for the first quarter of 2005, we now reflect
this as interest expense on the statement of income. This change is discussed
further under "New Accounting Policies" and the 2004 amounts have been
retroactively restated to reflect this new presentation.
Our second quarter total interest expense and amortization of deferred charges
of $9.8 million is higher than the $2.4 million reflected in the second quarter
of 2004. For the six month period ended June 30, 2005 total interest expense and
amortization of deferred charges was $19.1 million compared to $4.8 million for
the same period in 2004. The increase in total interest expense in 2005 is due
to higher bank debt and the senior notes, which were used to partially finance
the July and September 2004 acquisitions.
Total interest expense is expected to be slightly higher through the balance of
2005 given $75 million of new 6.5% convertible debentures issued in August 2005
associated with the Hay River acquisition.
DEPLETION, DEPRECIATION AND ACCRETION (DD&A)
Three months ended June 30 Six months ended June 30
--------------------------------- -------------------------------
($MILLIONS EXCEPT PER BOE) 2005 2004 Change 2005 2004 Change
- ---------------------------------------------------------------------------------- -------------------------------
Depletion and depreciation $ 32.5 $ 10.1 222% 69.0 19.7 250%
Depletion of capitalized asset retirement costs 2.6 1.8 44% 5.4 3.6 50%
Accretion on asset retirement obligation 2.3 0.9 156% 4.6 1.6 188%
- ------------------------------------------------------------------------------------------------------------------
Total depletion, depreciation and accretion $ 37.4 $ 12.8 192% $ 79.0 $ 24.9 217%
Per BOE ($/BOE) $ 11.93 $ 9.22 29% 12.49 9.09 37%
==================================================================================================================
Our second quarter depletion, depreciation, and accretion expense totaled $37.4
million ($11.93/BOE) compared to $12.8 million ($9.20/BOE) for the same quarter
in 2004. Our total DD&A for the six month period ended June 30, 2005 was $79.0
million ($12.50/BOE), compared to $24.9 million ($9.08/BOE) for the same period
in 2004. Relative to the second quarter of 2004 and the six month period ended
June 30, 2004, our higher DD&A is primarily attributable to the significant
acquisitions completed in June and September 2004, and reflects the higher
netback production acquired. We anticipate full year 2005 DD&A rates to range
between $13 and $15 per BOE with the Hay River acquisition completed in August.
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 credit
facility 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 per $U.S. to provide a further hedge against foreign exchange
volatility.
The largest portion of our foreign exchange gains and losses are directly
related to our U.S. dollar denominated senior notes. In the second quarter of
2005, the Canadian dollar weakened against the U.S. dollar, and we incurred
unrealized losses on our senior notes of $3.9 million. This amount was partially
offset by realized settlements of amounts held on deposit denominated in U.S.
dollars. The net result for the second quarter 2005 was a foreign exchange loss
of $3.2 million. In the second quarter of 2004, we did not have any U.S. dollar
denominated debt and as a result, in a time of a weakening Canadian dollar, we
recorded gains because changes in foreign exchange were largely related to sales
transactions.
For the six month period ended June 30, 2005, we realized a foreign exchange
loss of $5.4 million, compared to a foreign exchange gain of $1.3 million for
the same period in 2004. Again, this reflects the impact of a weakened Canadian
dollar at June 30, 2005 compared to December 31, 2004 on our senior notes.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
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 (primarily options) to
manage commodity price, heavy oil price differentials, 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.
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
derivative contracts had a mark-to-market unrealized non-cash loss position on
the balance sheet of $77.5 million as at June 30, 2005. The difference between
this value and the mark-to-market amount at December 31, 2004 ($15.4 million) is
reflected as an unrealized loss in the six month period ended June 30, 2005.
Please refer to Note 10 in the consolidated financial statements for further
information.
The following table provides a reconciliation of the changes in Harvest's
mark-to-market position on its derivative contracts from January 1, 2005 to June
30, 2005.
($MILLIONS) AS AT JUNE 30, 2005 As at December 31, 2004
- ---------------------------------------------------------------------------------------------------------
Opening mark-to-market position (15.4) --
Unrealized loss on outstanding derivative contracts(1) (68.7) (27.9)
Unrealized gain on outstanding derivative contracts(1) (6.6) 12.5
- ---------------------------------------------------------------------------------------------------------
Closing mark-to-market position (77.5) (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.
We determine the value of our derivative contracts using prices from actively
quoted markets. Where we are unable to obtain quoted prices, we use widely
accepted valuation models.
In the three months ended June 30, 2005, we recorded a net realized loss on
commodity derivative contracts of $23.3 million, and a net unrealized gain,
including amortization of deferred charges and gains, of $5.0 million for a
total loss of $18.3 million. For the six month period ended June 30, 2005, we
recorded a realized loss on commodity derivative contracts of $42.1 million, and
an unrealized loss including amortization of deferred charges and gains, of
$69.5 million for a total loss of $111.6 million. The realized loss portion
reflects the effective cost of our hedges related to production during the
period. If we had experienced similar WTI price levels in 2005 as 2004, realized
derivative contract losses in 2005 would have been lower than those experienced
in 2004 as the majority of our 2005 derivative contracts provide a firm floor
but allow for participation in strengthening commodity prices. The volume of our
production hedged with swaps and collars that have fixed price ceilings has
greatly diminished for 2005 and is nil for 2006 and 2007.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
The table below provides a summary of gains and losses on derivative contracts:
Three months
ended June 30,
THREE MONTHS ENDED JUNE 30, 2005 2004
------------------------------------------------------- ---------------
($THOUSANDS) Oil Currency Electricity Total Total
- ----------------------------------------------------------------------------------------------------------- ---------------
Unrealized (losses) / gains on derivative contracts 7,797 (1,145) 1,978 8,630 (4,242)
Realized (losses) / gains on derivative contracts (23,327) (168) 147 (23,348) (11,542)
Amortization of deferred charges relating to
derivative contracts (3,983) -- -- (3,983) --
Amortization of deferred gains relating to derivative
contracts -- -- 445 445 --
- ---------------------------------------------------------------------------------------------------------------------------
Total (losses) / gains on derivative contracts (19,513) (1,313) 2,570 (18,256) (15,784)
===========================================================================================================================
Six months
ended June 30,
SIX MONTHS ENDED JUNE 30, 2005 2004
------------------------------------------------------- ---------------
($THOUSANDS) Oil Currency Electricity Total Total
- ----------------------------------------------------------------------------------------------------------- ---------------
Unrealized (losses) / gains on derivative contracts (64,515) (4,192) 6,585 (62,122) (4,242)
Realized (losses) / gains on derivative contracts (43,058) 672 313 (42,073) (20,399)
Amortization of deferred charges relating to
derivative contracts (8,344) -- -- (8,344) (5,490)
Amortization of deferred gains relating to derivative
contracts -- -- 890 890 --
- ---------------------------------------------------------------------------------------------------------------------------
Total (losses) / gains on derivative contracts (115,917) (3,520) 7,788 (111,649) (30,131)
===========================================================================================================================
PREPAID EXPENSES AND DEPOSITS
Our prepaid expenses and deposits balance includes $44.5 million of amounts
which are held on margin with counterparties to our derivative contracts. This
balance will decrease as our hedges settle, provided oil prices do not increase
further.
DEFERRED CHARGES AND DEFERRED GAINS
The deferred charges asset balance on the balance sheet is comprised of two main
components: deferred financing charges and deferred assets related to the
discontinuation of hedge accounting. The deferred financing charges relate
primarily to the issuance of the senior notes, convertible debentures and bank
debt and are amortized over the life of the corresponding debt.
DEFERRED CHARGES
($THOUSANDS) As at June 30, 2005 As at December 31, 2004
- ----------------------------------------------------------------------- ----------------------------------------------------
ON DIS- On Dis-
CONTINUATION continuation Financing
OF HEDGE FINANCING DISCOUNT ON of Hedge Costs Discount on
ACCOUNTING COSTS SENIOR NOTES TOTAL Accounting (Restated) Senior Notes Total
- ----------------------------------------------------------------------- ----------------------------------------------------
Opening Balance 10,759 12,781 2,000 25,540 -- 1,989 -- 1,989
Additions -- 534 -- 534 25,705 20,971 2,075 48,751
Transferred to -- --
unit issue -- --
costs -- (563) -- (563) -- (5,721) -- (5,721)
Amortization (8,344) (3,285) (148) (11,777) (14,946) (4,458) (75) (19,479)
- ----------------------------------------------------------------------------------------------------------------------------
Closing Balance 2,415 9,467 1,852 13,734 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 derivative contracts
asset or liability. The deferred amount is recognized in income in the period in
which the underlying transaction is recognized.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
For the six month period ended June 30, 2005, $8.3 million of the deferred
charge and $0.9 million of the deferred gain was been amortized and recorded in
gains and losses on derivative contracts. At June 30, 2005, a $2.4 million
deferred charge and a $1.3 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,
Harvest 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 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 financial statement amounts of assets and liabilities held in Harvest's
corporate operating subsidiaries 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 and six month period ended June
30, 2005 of $3.8 million and $29.8 million, respectively, compared to a $1.6
million recovery and $4.2 million recovery for the same periods last year. The
significant increase in the future income tax recovery in the six month period
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 costs that make up the obligation.
Our asset retirement obligation has increased by approximately $4.0 million in
the first half of 2005 mainly due to the accretion of the asset retirement
obligation.
NON-CONTROLLING INTEREST
At June 30, 2005, we have recorded a non-controlling interest amount on our
consolidated balance sheet of $3.5 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 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 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.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
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 income (loss)
attributed to non-controlling interest for the three and six months ended June
30, 2005 was $120,000 and $(375,000), respectively.
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 second
quarter of 2005, our distribution payout ratio of 46% (calculated by dividing
distributions to Unitholders by Funds Flow from Operations) resulted in excess
Funds Flow from Operations available for our capital expenditure programs. This
compares to a payout ratio of 69% in the second quarter of 2004. Our payout
ratio for the six month period ended June 30, 2005 was 47% (excluding the
special distribution of 2004 income paid in Trust Units) compared to 72% for the
same period in 2004. During the second quarter, we announced a 25% increase to
our monthly distribution level, effective with the July distribution, payable in
August. We have also announced an increase to $0.35 per Trust Unit per month
commencing with the September 15 payment. This increase in distributions is a
reflection of the success of Harvest's strategy to date.
As at June 30, 2005, Harvest's net debt increased to $436.6 million from $429.6
million at December 31, 2004, primarily as a result of the deposit made by
Harvest for the $260 million Hay River acquisition. The Hay River acquisition
closed on August 2, 2005 and was financed by drawing on Harvest's new $400
million senior secured credit facility. Net proceeds from the equity and
convertible debenture financing, which closed the same day, of $237 million were
used to repay amounts drawn under the credit facility. Following the acquisition
and the financings, we anticipate net bank debt to be approximately $100
million.
We anticipate that sufficient Funds Flow from Operations for the balance of 2005
will be available to finance our planned capital development program, expected
distributions of $0.35 per Unit per month and still leave us with sufficient
funds to repay a portion of our outstanding bank debt. Given the significant
amount of oil price protection we have in place, we believe that our Funds Flow
from Operations 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 second quarter of
2005, DRIP participation averaged approximately 5%.
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 oil price protection in place, and the
long term to maturity of the majority of our debt. As noted above, we intend to
use Funds Flow from Operations after distributions and capital expenditures to
repay bank debt through the balance of 2005 and through 2006. Pro forma the Hay
River acquisition, net debt will be lower by approximately $26 million, and cash
flows will reflect the incremental production acquired. Management anticipates
pro forma debt to Funds Flow from Operations to be approximately 1.5 times.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
AS AT JUNE 30, As at December 31,
($ MILLIONS) 2005 2004 Change
- ------------------------------------------------------------------------------------------------------------
Bank debt $ 138.1 $ 75.5 83%
Working capital deficit (surplus) excluding bank debt(1) (18.6) 27.8 167%
Senior notes 306.4 300.5 2%
Convertible debentures 10.7 25.8 (59%)
- ------------------------------------------------------------------------------------------------------------
Net debt obligations $ 436.6 $ 429.6 2%
- ------------------------------------------------------------------------------------------------------------
Annualized quarterly funds flow(2) $ 228.9 $ 211.5 8%
Net debt to funds flow (times) 1.9 2.0 0%
============================================================================================================
NOTE 1 EXCLUDES CURRENT PORTION OF DERIVATIVE CONTRACTS ASSETS AND
LIABILITIES, FUTURE INCOME TAX AND TRUST UNIT INCENTIVE PLAN LIABILITY.
NOTE 2 REFLECTS REALIZED HEDGING LOSSES WHICH WERE SIGNIFICANT IN THE SECOND
QUARTER GIVEN THE NATURE OF OUR OIL PRICE HEDGES. OUR HEDGES IN THE
LATTER HALF OF 2005 ARE PRIMARILY INSTRUMENTS WHICH DO NOT PLACE A CAP
ON WTI PRICE REALIZATIONS.
Since inception, we have communicated our intention to pursue a strategy that
will allow us to sustain or increase our Funds Flow from Operations and
distributions per Unit. During the three month periods ended June 30, 2005 and
2004, we declared $26.1 million and $11 million, respectively, in distributions
payable to Unitholders ($0.20 per Trust Unit per month for each of April, May
and June). Year to date in 2005, distributions declared total $62.3 million,
including the payment of a special one-time distribution relating to
undistributed 2004 taxable income of $10.7 million, compared to $21.3 million
declared during the same period in 2004. Effective with the August distribution
(payable September 15, 2005), we have increased our distribution level to $0.35
per Trust Unit per month. The higher level of distributions paid in the second
quarter of 2005 reflects the increased number of Trust Units outstanding
compared to the first quarter of 2004.
Our payout ratio, which is the ratio of distributions to Funds Flow from
Operations, remains among the lowest in the trust sector. We reported a 46%
payout ratio in the second quarter of 2005, and a 47% payout ratio year-to-date,
compared to 69% and 72% in the same periods in 2004. We anticipate that our
payout ratio will range between 50% and 55%, assuming a $0.35 monthly
distribution and current commodity prices. This low payout ratio will provide
Harvest significant flexibility in financing capital and acquisition activities
and servicing our outstanding debt. Reducing our debt will help position us to
take advantage of any future acquisition opportunities.
Of the total second quarter 2005 distributions, the Distribution Reinvestment
Plan ("DRIP") accounted for 5% of total distributions, or $1.4 million
represented by approximately 63,000 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 the
balance of 2005, the DRIP will increase from second quarter levels and average
closer to our historical average of 20% participation. Should the percentage
participation in our DRIP decrease, we will need to use a larger amount of Funds
Flow from Operations 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 obtain independent legal advice on how
their distributions should be treated for tax purposes.
Harvest's Trust Units listed for trading on the New York Stock Exchange (NYSE)
on July 21, 2005. This listing will provide Harvest's unitholders with
additional liquidity, and Harvest with greater access to the U.S. capital
market. From time to time the Trust may require external financing, in the form
of 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 ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
Of the convertible debentures outstanding at June 30, 2005, approximately $2.1
million have converted into Units through August 11, 2005 and we anticipate
continued conversions of in-the-money debentures through 2005.
A breakdown of our outstanding Trust Units and potentially dilutive elements is
as follows:
- ---------------------------------------------------------------------------------------------------------------------------------
AS AT JUNE 30, 2005 As at December 31, 2004 As at June 30, 2004
- ---------------------------------------------------------------------------------------------------------------------------------
Market price of Trust Units at end of period ($/unit) 27.05 22.95 14.70
Trust Units outstanding 43,772,207 41,788,500 20,228,860
Exchangeable shares outstanding(1) 240,011 455,547 600,587
Trust Units represented by Exchangeable shares 268,640 485,003 600,587
Total market value of Trust Units at
end of period(2) ($millions) $ 1,191.3 $ 970.0 $ 306.2
9% Convertible debentures(3), face value ($millions) $ 2.8 $ 10.7 $ 57.8
8% Convertible debentures(4), face value ($millions) $ 8.0 $ 15.2 $ --
Trust Unit rights outstanding(5) 1,569,966 1,128,387 1,168,100
Total Trust Units, diluted(6) 46,309,075 45,099,038 26,125,761
=================================================================================================================================
NOTE 1 EXCHANGEABLE SHARES ARE EXCHANGEABLE INTO TRUST UNITS AT THE ELECTION
OF THE HOLDER AT ANY TIME. THE EXCHANGE RATIO IN EFFECT ON JUNE 30,
2005 WAS 1.11928:1, AND ON DECEMBER 31, 2004 WAS 1.06466:1. THE JUNE
30, 2005 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 JUNE 30, 2005 AND DECEMBER 31,
2004, AN ADDITIONAL 200,939 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 JUNE 30, 2005 AND DECEMBER 31,
2004, AN ADDITIONAL 497,324 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 $13.51 PER TRUST UNIT AS AT JUNE
30, 2005, AND $10.09 PER TRUST UNIT AS AT DECEMBER 31, 2004. ALSO
INCLUDES UNIT AWARD INCENTIVE PLAN RIGHTS OF 31,441 AS AT JUNE 30, 2005
AND 10,662 AT DECEMBER 31, 2004. EACH UNIT AWARD INCENTIVE PLAN RIGHT
CAN BE CONVERTED INTO ONE TRUST UNIT ONCE VESTED WITH NO ADDITIONAL
CONSIDERATION.
NOTE 6 FULLY DILUTED UNITS DIFFER FROM DILUTED UNITS FOR ACCOUNTING
PURPOSES. FULLY DILUTED INCLUDES TRUST UNITS OUTSTANDING AS AT JUNE 30,
2005 OR DECEMBER 31, 2004 PLUS THE IMPACT OF THE CONVERSION OR EXERCISE
OF EXCHANGEABLE SHARES, TRUST UNIT RIGHTS, UNIT AWARD RIGHTS AND
CONVERTIBLE DEBENTURES IF COMPLETED AT JUNE 30, 2005 OR DECEMBER 31,
2004.
($MILLIONS) AS AT JUNE 30, 2005 As at December 31, 2004 % Change
- ----------------------------------------------------------------------------------------------------------------
Total market capitalization(1) $ 1,191.3 $ 970.2 23%
Net debt 436.6 429.6 0
- ----------------------------------------------------------------------------------------------------------------
Enterprise value (total capitalization)(2) $ 1,627.9 $ 1,399.8 16%
- ----------------------------------------------------------------------------------------------------------------
Net debt as a percentage of enterprise value(3) (%) 27% 31% (4%)
================================================================================================================
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.
NOTE 3 THIS RATIO CHANGED FOLLOWING THE $175 MILLION TRUST UNIT AND $75
MILLION CONVERTIBLE DEBENTURE FINANCING WHICH CLOSED ON AUGUST 2, 2005.
AS OF THAT DATE, THE RATIO WAS APPROXIMATELY 25%.
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.
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.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
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 property acquisitions totaled $27.2
million and $50.4 million for the three and six month periods ended June 30,
2005. This compares to development capital expenditures of $8.3 million in the
second quarter of 2004 and $18.5 million for the six months ended June 30, 2004.
The three and six month periods ending June 30, 2005, include non-cash capital
additions of approximately $1 million relating to non-cash UAR costs that have
been capitalized. For the three month period ended June 30, 2005, property
acquisitions totaled $26.2 million, including $26 million paid to the vendor as
a deposit for the Hay River property. For the six month period ended June 30,
2005, property acquisitions totaled $30.8 million. Property acquisition
expenditures for the same periods in 2004 were $191.6 million and $193.4
million, respectively. The acquisition of Storm Energy took place in the second
quarter of 2004, and represents the majority of the acquisition expenditures in
the first half of that year. This acquisition was financed with $75 million of
debt and the remaining with Trust Units and Exchangeable Shares. The increase in
development capital expenditures in 2005 compared to 2004 is due to several
factors, including an increased number of producing properties, higher drilling
activity, additional well workovers and optimization activities, and generally
reflects the expanded base of internal growth opportunities resulting from past
acquisitions.
We continue to review opportunities within the acquisition market, and initiated
the acquisition of the Hay River property late in the second quarter. This $238
million acquisition, after adjustments, closed on August 2, 2005, and provides
us with 5,200 BOE/d of medium oil production, 19.8 mmBOE of proved plus probable
reserves, 54,000 net acres of undeveloped land, and an estimated 74 future
drilling locations.
Following the announcement of the acquisition, we also increased our forecasted
capital budget for 2005 to $110 million. Our 2005 budget includes drilling of
just under 90 wells. We 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
sufficient drilling inventory to keep us active for the next 2 to 3 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 June 30, 2005 and our existing hedging program, and are
provided for directional information only.
Variable
-----------------------------------------------------------------------------------------
WTI Heavy Oil Crude Oil Canadian Bank Foreign Exchange
Price/bbl Price differential/bbl Production Prime Rate Rate Cdn. / U.S.
- -----------------------------------------------------------------------------------------------------------------------------
Assumption $45.00 U.S. $15.00 U.S. 39,000 boe/d 4.25% 1.21
Change $1.00 U.S. $1.00 U.S. 1,000 boe/d 1% 0.01
ANNUALIZED IMPACT ON:
Funds flow from operations ($000's) $6,622 $2,109 $11,797 $1,043 $2,549
Per Trust Unit, basic $0.13 $0.04 $0.25 $0.01 $0.06
Per Trust Unit, diluted $0.12 $0.04 $0.24 $0.01 $0.06
Payout ratio 1.0% 0.4% 1.9% 0.2% 0.4%
- ----------------------------------------------------------------------------------------------------------------------------
As noted above, our commodity price risk management program provides significant
downside price protection, while allowing Harvest to participate in upward price
movements. Thus, cash flow sensitivities are less extreme with WTI price
declines than with price increases.
HARVEST ENERGY TRUST 2ND QUARTER 2005
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Oil price derivative contracts in place as at June 30, 2005 are summarized in
the table below. The prices shown for collars, indexed puts and participating
swaps are floor prices.
2005 2006 2007
-------------------------------- --------------------------------- --------------------------------
Volume (bbls/d) Pricing ($/bbl) Volume (bbls/d) Pricing ($/bbl) Volume (bbls/d) Pricing ($/bbl)
- ------------------------------------------------------------ --------------------------------- --------------------------------
WTI Crude Oil Swaps 500 $ 24.00 -- --
WTI Crude Oil Collars 3,500 $ 28.07 -- --
WTI Indexed Put Contracts 18,500 $ 35.95 3,719 $ 34.00
WTI Participating Swaps(1) -- -- 11,271 $ 39.73 2,479 (49.03)
WTI Participating Swaps(2) -- -- 5,000 $ 49.03 2,479 (49.03)
===============================================================================================================================
(1) 50% UPSIDE PARTICIPATION
(2) 75% UPSIDE PARTICIPATION.
The percent of WTI shown in the table below represents the average of all
outstanding contracts.
2005 2006
---------------------------------- ----------------------------------
Oil Price Differential Swap Contracts(1) Volume (bbls/d) Percent of WTI Volume (bbls/d) Percent of WTI
- ---------------------------------------------------------- ----------------- ---------------- -----------------
July - December 2005 10,000 28.7%
January - December 2006 7,500 28.7%
============================================================================ ==================================
(1) CERTAIN OF THESE CONTRACTS OVERLAP A PORTION OF BOTH YEARS.
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
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.
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
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 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
HARVEST ENERGY TRUST 2ND QUARTER 2005
- --------------------------------------------------------------------------------
any of our derivative instruments, we do not expect these pronouncements to have
a significant impact on our consolidated financial results.
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.
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 geographic areas 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.