EXHIBIT 2
---------
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
THIRD QUARTER 2005 FINANCIAL AND OPERATIONAL SUMMARY
The table below provides a summary of Harvest's financial and operating results
for the three and nine month periods ended September 30, 2005.
($000'S, EXCEPT WHERE NOTED) Three months ended September 30 Nine months ended September 30
- ------------------------------------------------------------------------------------- -------------------------------------
FINANCIAL 2005 2004 Change 2005 2004 Change
- ------------------------------------------------------------------------------------- ---------------------------------------
Revenue, net of royalties 169,654 85,096 99% 399,848 168,856 137%
Net income (loss)(5) 52,862 1,740 2938% 29,308 (359) --
Per Trust Unit, basic(5) $ 1.09 $ 0.06 1724% $ 0.66 $ (0.02) --
Per Trust Unit, diluted(5) $ 1.08 $ 0.06 1700% $ 0.64 $ (0.02) --
Funds flow from operations(4,5) 103,508 41,267 151% 213,412 72,372 195%
Per Trust Unit, basic(4,5) $ 2.14 $ 1.42 51% $ 4.78 $ 3.46 38%
Per Trust Unit, diluted(4,5) $ 2.09 $ 1.12 87% $ 4.55 $ 2.59 76%
Distributions per Trust Unit, declared(6) $ 0.95 $ 0.60 58% $ 2.15 $ 1.80 19%
Distributions declared 46,691 18,434 153% 108,957 39,740 174%
Payout ratio(2,4) 45% 45% 0% 46% 55% (9%)
Capital asset additions (excluding acquisitions) 33,594 13,182 155% 84,007 31,695 165%
Net acquisitions 209,666 513,815 100% 239,296 590,942 (60%)
Net debt(3,4) 418,169 403,372 4% 418,169 403,372 4%
Weighted average Trust Units outstanding, basic 48,306 29,058 66% 44,612 20,938 113%
Weighted average Trust Units outstanding, diluted 49,365 29,700 66% 45,719 20,938 118%
Trust Units outstanding, end of period 51,558 36,875 40% 51,558 36,875 40%
Trust Units fully diluted(7), end of period 55,680 44,851 24% 55,680 44,851 24%
OPERATING
- ------------------------------------------------------------------------------------- ---------------------------------------
Daily sales volumes
Light oil (bbl/d) 10,076 9,087 11% 9,949 6,461 54%
Medium oil (bbl/d) 8,792 5,416 62% 6,669 4,553 46%
Heavy oil (bbl/d) 13,735 7,894 74% 13,906 6,271 122%
Natural gas liquids (bbl/d) 850 377 125% 810 190 326%
Natural gas (mcf/d) 24,574 11,909 106% 26,839 5,049 432%
- ------------------------------------------------------------------------------------- ---------------------------------------
Total (BOE/d)(1) 37,549 24,759 52% 35,807 18,317 95%
OPERATING NETBACK(4) ($/BOE)(1)
- ------------------------------------------------------------------------------------- ---------------------------------------
Revenues 60.39 44.83 35% 49.27 40.43 22%
Realized loss on derivative contracts (6.85) (7.22) (5%) (6.76) (7.52) (10%)
Royalties (11.28) (7.47) 51% (8.37) (6.78) 23%
As a percent of revenue (%) 18.7% 16.7% 2% 17.0% 16.8% 0%
Operating expense(8) (8.96) (8.34) 7% (8.87) (9.22) (4%)
- ------------------------------------------------------------------------------------- ---------------------------------------
Operating netback(4) 33.30 21.80 53% 25.27 16.90 50%
- ------------------------------------------------------------------------------------- ---------------------------------------
NOTE 1 NATURAL GAS CONVERTED TO BARREL OF OIL EQUIVALENT (BOE) ON A 6:1 BASIS.
NOTE 2 RATIO OF DISTRIBUTIONS, EXCLUDING SPECIAL DISTRIBUTION, TO FUNDS FLOW
FROM OPERATIONS. IN THE THIRD QUARTER, REFLECTS DISTRIBUTIONS DECLARED
OF $0.25 (JULY) AND $0.35 (AUGUST AND SEPTEMBER) PER UNIT.
NOTE 3 NET DEBT IS BANK DEBT, SENIOR NOTES, EQUITY BRIDGE NOTES, CONVERTIBLE
DEBENTURES AND ANY WORKING CAPITAL DEFICIT EXCLUDING THE CURRENT
PORTION OF DERIVATIVE CONTRACTS, FUTURE INCOME TAX AND THE ACCOUNTING
LIABILITY RELATED TO OUR TRUST UNIT INCENTIVE PLAN..
NOTE 4 THESE ARE NON-GAAP MEASURES; PLEASE REFER TO "CERTAIN FINANCIAL
REPORTING MEASURES" INCLUDED IN OUR MD&A.
NOTE 5 PRIOR YEAR RESTATED TO REFLECT ADOPTION OF NEW ACCOUNTING STANDARDS
WITH RESPECT TO EXCHANGEABLE SHARES AND FINANCIAL INSTRUMENTS. SEE NOTE
2 TO THE CONSOLIDATED FINANCIAL STATEMENTS.
NOTE 6 AS IF THE TRUST UNIT WAS HELD THROUGHOUT THE PERIOD.
NOTE 7 FULLY DILUTED UNITS DIFFER FROM DILUTED UNITS FOR PURPOSES OF
CALCULATING EARNINGS PER UNIT AND FUNDS FLOW PER UNIT, AND IS MEANT TO
REFLECT THE NUMBER OF UNITS WHICH WOULD BE OUTSTANDING IF ALL
POTENTIALLY DILUTIVE ELEMENTS WERE EXERCISED. FULLY DILUTED INCLUDES
TRUST UNITS OUTSTANDING AS AT SEPTEMBER 30 PLUS THE IMPACT OF THE
CONVERSION OR EXERCISE OF EXCHANGEABLE SHARES, TRUST UNIT RIGHTS AND
CONVERTIBLE DEBENTURES IF CONVERTED AT SEPTEMBER 30.
NOTE 8 INCLUDES REALIZED GAIN ON ELECTRICITY DERIVATIVE CONTRACTS OF $0.43
($0.24 - 2004) AND $0.18 ($0.29 - 2004) FOR THE THREE AND NINE MONTH
PERIODS ENDED SEPTEMBER 30, 2005 AND 2004, RESPECTIVELY.
-1-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
THIRD QUARTER MESSAGE TO UNITHOLDERS
During the third quarter, we enjoyed another successful period of growth and
development as we increased distributions and continued to build the Trust's
assets for future performance. We achieved significant per unit distribution
increases, strengthened our asset base and financial structure and achieved the
highest quarterly funds flow from operations in Harvest's history at $2.14 per
basic trust unit (an increase of 62% over the second quarter of 2005).
Specific highlights during the quarter include increasing our monthly
distribution by 75% while still retaining a low payout ratio of 45%; investing
$33.6 million in property enhancement activities, which included drilling 20
wells with a 98% success rate; closing the Hay River property acquisition and
concurrent financing; listing our trust units for trading on the New York Stock
Exchange (NYSE); and implementing an enhanced Distribution Reinvestment, Premium
Distribution(TM), and Optional Trust Unit Purchase Plan for our Canadian
resident unitholders. Each of these initiatives contributed to the long-term
sustainability of Harvest.
On August 2, we added approximately 5,200 barrels of oil equivalent per day
(BOE/day) of crude oil from the Hay River, B.C. property acquisition. A full
quarter's impact from Hay River will be reflected in Harvest's fourth quarter
results. Hay River is an excellent fit with our existing portfolio, and enhances
our already significant development inventory. Furthermore, Hay River's lower
operating costs and premium price realizations relative to the benchmark for
medium gravity crude oil help to strengthen our overall corporate netbacks. We
anticipate significant drilling activity (approximately 30 wells) in the area
during this winter drilling season.
Our commitment to sustainability is supported by our strong financial position.
We believe that we can maintain our C$0.35 per trust unit monthly distribution
level through a downturn in oil prices due to our low payout ratio and our
hedging program. Our hedging strategy underpins our cash flow and provides
stability during volatile crude oil price environments by providing downside
protection while allowing for upside participation. For example, Harvest's 2006
hedging program would enable us to sustain the current monthly distribution
level of $0.35 per unit, finance a significant capital program, and generate an
annual payout ratio of approximately 75% even if crude oil prices should drop to
U.S.$40 per barrel for all of 2006. We have not hedged any of our natural gas
production, and therefore have fully benefited from rising natural gas spot
prices in Alberta.
Our capital development program, which is designed to replace naturally
declining production and reserves by making prudent investments in low-risk
property enhancement projects, further demonstrates our commitment to
sustainability. During the third quarter, Harvest invested approximately $33.6
million in our capital development program, with 64% of that amount allocated to
drilling. Our third quarter drilling activities were focused in Southern Alberta
and Saskatchewan, where we drilled 7 and 11 net wells, respectively. We also
drilled one well in each of East Central and North Central Alberta, for a total
of 20 net wells in the quarter, and achieved an overall success rate of 98%. We
expect to drill approximately 90 net wells in 2005, while continuing to dedicate
resources to our ongoing optimization and efficiency projects. We will continue
to focus on operating efficiency measures in our capital program, and remain
committed to operating cost reductions. Operating costs have increased due to
very significant power price increases impacting our small unhedged power volume
requirement.
During the quarter, we invested in optimization projects such as a water
handling expansion at Chauvin to add pumping capacity, and the deepening of
injection wells at Hayter, Big Marsh and Moose Valley to improve the efficiency
of water reinjection at these properties. Infrastructure additions were also
completed during the quarter, with a satellite field treating facility added in
Hazelwood, and a fluid processing facility installed in West Provost. Subsequent
to the end of the quarter, we expanded our 2005 capital budget to approximately
$130 million to pursue additional value adding projects identified by our
operational teams. This reflects the second supplement to our 2005 capital
program as our technical teams were able to identify and support solid economic
investment opportunities as their knowledge of our properties has matured. The
full impact of this optimization capital is expected to be realized as the
majority of the new production comes on-line during the
-2-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
first quarter of 2006. We are also finalizing our operating budget for 2006,
which is expected to be complete by early December, after which time we will be
providing our guidance for 2006.
Third quarter production volumes averaged 37,549 BOE/d, and include the addition
of the Hay River production from August 2 through September 30. Several factors
combined during the quarter to result in lower realized oil production relative
to capacity. An unscheduled outage and subsequent repairs at our Suffield
property impacted production for 6 days, and production was further impacted by
wet ground conditions in Alberta and Saskatchewan delaying completion of
scheduled workovers and other projects. However, the impact of these items was
partially mitigated by new drilling activity in our Hazelwood and East Hayter
areas where production was initiated sooner than expected. Our third quarter
operating expenses were $8.96 per BOE and reflect the rising cost environment
and short-term production outages. This is slightly less than the second quarter
($9.08/BOE), but still higher than we believe is achievable with our asset base.
We also strengthened our capital structure during the quarter by concluding a
financing of 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. The proceeds
from this offering were primarily used to repay bank debt incurred in acquiring
the Hay River property. By the end of the quarter our net debt was reduced to
approximately $418 million from $437 million at the end of the second quarter,
and we increased annualized funds flow from operations by $183 million. This has
resulted in quarter end net debt to annualized funds flow of 1.0 times - a
figure that reinforces our strong capital structure and is in line with our
peers. Harvest units also realized a dramatic improvement in trading liquidity
with a listing on the NYSE. Total trading volumes increased by 194% relative to
the second quarter.
With our current capital structure and approximately $350 million of undrawn
borrowing capacity, we are well positioned to take advantage of any acquisition
opportunities that may arise. Our criteria for acquisition opportunities include
return on equity and upside potential. We are not limited to a narrow range of
property types, commodity types or RLI. We have the advantage of remaining
opportunistic toward the acquisition marketplace due to our deep portfolio of
future development opportunities that currently offers several years of drilling
locations.
For 2005, we anticipate production volumes to average between 36,250 and 36,750
BOE per day, operating expenses of $8.75 to $9.00 per BOE, development capital
expenditures of approximately $130 million, and cash G&A (before unit right
compensation expenses) between $1.00 and $1.10 per BOE.
Harvest has positioned itself with a strong balance sheet, significant commodity
price protection and a large undrawn debt facility to allow us to be
opportunistic. We have a solid asset base, a prudent risk management program, a
strong capital structure, and a dedicated team. With these fundamentals, Harvest
will continue to focus on long-term sustainability and our goal of maintaining
or increasing funds flow per unit.
GOVERNMENT POLICY INITIATIVES
In a consultation paper issued on September 8, 2005, the Canadian Federal
Government expressed concerns about several economic policy issues arising from
the recent proliferation of income trusts in Canada. These concerns included the
impact on the Canadian economy and possible reductions to overall federal tax
revenues. The Government has requested comments and feedback from interested
stakeholders regarding the tax treatment of income trusts by December 31, 2005.
The government of Alberta has expressed similar concerns regarding the impact of
energy trusts on tax revenues, although it has acknowledged the benefits to
Alberta and the energy industry in general arising from energy trust investment
activity.
Energy income trusts fill a vital and active role in the Canadian energy sector.
The current tax treatment of energy trusts is crucial to enable the Canadian
energy industry to attract the capital necessary to meet Canada's current and
future energy needs. Energy trusts also provide a ready source of capital to
more conventional exploration focused oil and natural gas corporations through
acquisitions and further development of their mature properties. Harvest is
working to ensure that its
-3-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
views and the views of its unitholders are represented to both the provincial
and federal governments, through support given to industry associations.
We encourage existing or potential unitholders and other stakeholders who wish
to voice their support for the preservation of the current income trust taxation
structure to contact the Department of Finance via the following Web site:
WWW.FIN.GC.CA/ADMIN/CONTACT-E.HTML. Alberta resident unitholders can contact
their Member of Legislative Assembly (MLA) via the following website
HTTP://WWW.ASSEMBLY.AB.CA/NET/INDEX.ASPX?P=MLA_HOME to provide feedback on the
Alberta government's concerns with respect to trusts. Harvest's website at
WWW.HARVESTENERGY.CA includes a list of contact information for all Canadian
Members of Parliament (MP) and we encourage all Canadian resident unitholders to
contact their MP to express their views.
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 nine
month periods ended September 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. All references to WTI in the
following document refer to West Texas Intermediate, a high quality grade of
crude oil used as a benchmark in oil pricing.
FORWARD-LOOKING INFORMATION
This third 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 November 7th, 2005.
CERTAIN FINANCIAL REPORTING MEASURES
The Trust utilizes 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") calculated below, Net Operating Income, Net Debt, Payout
Ratio and Operating Netback (calculated in tables within the MD&A). 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 nine month periods ended September 30,
2005 and 2004, Funds Flow from Operations is reconciled to its closest GAAP
measure, cash flow from operating activities, as follows:
-4-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
THREE MONTHS
ENDED Three months NINE MONTHS Nine months
SEPTEMBER 30, ended ENDED SEPTEMBER ended September
$000S 2005 September 30, 2004 30, 2005 30, 2004
- -------------------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations before changes in 103,508 41,267 213,412 72,372
non- cash working capital and settlement
of asset retirement obligations
Changes in non-cash working capital 29,810 (9,093) (25,867) (12,405)
Settlement of asset retirement obligations (1,169) (154) (2,333) (307)
- -------------------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities 132,149 32,020 185,212 59,660
===============================================================================================================================
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. We employ a disciplined
approach to the oil and natural gas production business, whereby we acquire high
working interest, large resource-in-place, mature producing properties and
employ "best practice" technical and field operational 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, the enhancement of
operational efficiencies to control and reduce expenses, and unique marketing
arrangements complemented by corporate hedging strategies to effectively manage
Funds Flow from Operations. We have 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.
Our objective is to maintain or increase Funds Flow from Operations on a per
unit basis.
ACQUISITIONS AND EVENTS
On August 2, 2005, we closed the acquisition of the Hay River property, as well
as a $250 million bought deal equity and convertible debenture financing. The
impact of the acquisition and financing on Harvest's financial statements is
effective as of the closing date, and therefore this quarter only reflects two
months' results from Hay River.
The addition of the Hay River property in August increased our production volume
by approximately 5,200 BOE/d at that time. The Hay River barrels sell at a
premium to our average medium gravity crude production, and coupled with the
impact of the lower Hay River operating expenses, will improve our corporate
netbacks. The accretive nature of the transaction has contributed to an increase
in our per Trust Unit Funds Flow from Operations, as demonstrated by our third
quarter results. Hay River has a higher royalty rate than our corporate average,
which will increase our royalties as a percentage of revenue. In the future, due
to the winter access nature of this property, the first quarter results from Hay
River will reflect high operating and capital expenditures and lower volumes
than the remainder of the year. The second quarter results should reflect the
benefits of the activities undertaken in the first quarter, and as a result, the
first quarter will not be indicative of the operating and financial results
expected for the balance of the year.
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. At the time of writing,
approximately 52.2 million Trust Units are outstanding; approximately $53
million of convertible debentures are outstanding, and our net debt (excluding
convertible debentures) is $10 million lower than the level reported at
September 30, 2005.
We listed our Trust Units on the NYSE on July 21, 2005; this has lead to
improved liquidity and visibility for Harvest, improved access to U.S. equity
markets and greater financing flexibility.
-5-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
SUMMARY OF HISTORICAL QUARTERLY RESULTS
- -------------------------------------------------------------------------------------------------------------------------------
(RESTATED - REFER TO NOTE 2 OF THE
CONSOLIDATED STATEMENTS) (RESTATED)
2005 2004 2003
----------------------------------- ---------------------------------------------- ------------
FINANCIAL Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
- ------------------------------------------------------------------- ---------------------------------------------- ------------
Revenue, net of royalties $ 169,654 $ 120,263 $ 109,931 $ 106,964 $ 85,096 $ 44,461 $ 39,298 $ 33,575
Operating expense (32,441) (28,635) (27,348) (25,725) (19,538) (14,306) (13,873) (13,335)
- -------------------------------------------------------------------------------------------------------------------------------
Net operating income(1) $ 137,213 $ 91,628 $ 82,583 $ 81,239 ,58$ 65,558 $ 30,155 $ 25,425 $ 20,240,425
Net income (loss)(3) 52,862 19,516 (43,070) 11,600 1,740 151 (2,250) 5,495
Per Trust Unit, basic(2,3) 1.09 0.45 (1.02) 0.29 0.06 0.01 (0.13) 0.30
Per Trust Unit, diluted(2,3) 1.08 0.44 (1.02) 0.27 0.06 0.01 (0.13) 0.29
Funds flow from operations(1,2,3) 103,508 57,217 52,687 52,870 41,267 15,839 13,734 13,699
Per Trust Unit, basic(1,3) 2.14 1.32 1.25 1.31 1.42 0.91 0.80 0.85
Per Trust Unit, diluted(1,3) 2.09 1.29 1.19 1.18 1.12 0.78 0.67 0.82
SALES VOLUMES
- -------------------------------------------------------------------------------------------------------------------------------
Crude oil (bbl/d) 32,603 28,855 30,087 30,992 22,397 14,775 14,626 14,497
Natural gas liquids (bbl/d) 850 798 780 1,309 377 141 50 70
Natural gas (mcf/d) 24,574 28,857 27,114 28,338 11,909 2,249 915 1,744
- -------------------------------------------------------------------------------------------------------------------------------
Total (BOE/d) 37,549 34,463 35,386 37,024 24,759 15,291 14,829 14,858
===============================================================================================================================
NOTE 1 THIS IS A NON-GAAP MEASURE AS REFERRED TO UNDER "CERTAIN FINANCIAL
REPORTING MEASURES" IN 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 REPORTING PERIODS, THESE
ITEMS WERE REFLECTED IN FINANCING ACTIVITIES.
The above table highlights Harvest's performance for the third quarter of 2005,
and the preceding 7 quarters.
Net revenues and net operating income have trended steadily higher over the
eight quarters shown above. The significantly higher revenue and funds flow in
the third quarter of 2005 relative to the second quarter of 2005 is primarily
due to higher production from the Hay River acquisition, stronger crude oil
prices and narrower heavy oil differentials early in the quarter. The most
significant increase in revenue occurred through the third and fourth quarters
of 2004, as a result of the two acquisitions completed in 2004, which closed in
June and September. The increasing revenue trend since the fourth quarter of
2003 is also attributable to the strong commodity price environment through 2004
and 2005.
Net income reflects both cash and non-cash items. Changes in non-cash items,
including depletion, depreciation and accretion (DD&A) expense, 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 from period to period. 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. The main reason for the volatility in net
income (loss) between quarters in 2005 is due to the changes in the fair value
of our derivative instruments. We ceased hedge accounting for all of our
derivative instruments in October 2004 switching to a "mark to market"
accounting methodology and this has accounted for increased volatility in our
earnings. 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.
Funds Flow from Operations is an important measure for an energy royalty trust
because it represents the source for cash distributions to Unitholders. Funds
Flow from Operations is also the means by which we finance repayment of debt and
capital expenditures which are used to replace produced reserves, contributing
to sustainability. Our low payout ratio is a key competitive advantage in
creating future sustainability. 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
-6-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
factors by hedging (generally referred to herein as 'derivatives' or 'derivative
contracts') a portion of our production volumes. This takes several forms
including establishing a fixed floor for future commodity prices, and mitigating
the impact of fluctuating heavy oil price differentials and currency exchange
rates.
REVENUES
Three months ended September 30 Nine months ended September 30
-------------------------------------- -------------------------------------
2005 2004 Change 2005 2004 Change
- ------------------------------------------------------------------------------ -------------------------------------
Oil and natural gas sales ($/BOE) 60.39 44.83 35% 49.27 40.43 22%
Royalty expense ($/BOE) (11.28) (7.47) 51% (8.37) (6.78) 23%
- ------------------------------------------------------------------------------ -------------------------------------
Net revenues ($/BOE) 49.11 37.36 31% 40.90 33.65 22%
- ------------------------------------------------------------------------------ -------------------------------------
Net revenues ($ millions) 169.7 85.1 99% 399.8 168.9 137%
- ------------------------------------------------------------------------------ -------------------------------------
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 nine month
periods ending September 30, 2005 increased 99% and 137%, respectively, over the
same periods in 2004. In addition, the increase in third quarter revenues
reflect two months of production and net revenue from the Hay River properties.
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 37,549 BOE/d, third quarter 2005 sales volumes were 52% higher than the
24,759 BOE/d realized in the three month period ended September 30, 2004 and
were in line with expectations. Volumes averaged 35,807 BOE/d for the first nine
months of 2005, and were 95% higher than the 18,317 BOE/d realized in the same
period in 2004. The increase in production year-over-year is due to the volumes
associated with properties acquired in June and September 2004, the acquisition
of the Hay River properties in August 2005, as well as successful development
and optimization work within all of our core areas. Third quarter 2005 natural
gas production was 24,574 mcf/day compared to 27,114 mcf/day in the first
quarter. The decrease is due to natural declines. We are working on
incorporating natural gas development projects into our 2006 budget to help
offset these natural declines. Our second quarter natural gas production of
28,857 mcf/day reflects positive prior period adjustments relating to previously
acquired natural gas wells. We anticipate that future natural gas production
will be consistent with the volumes reported in the third quarter.
The average daily sales volumes by product were as follows:
THREE MONTHS ENDED SEPTEMBER 30
-----------------------------------------------------
2005 2004
-------------------------- -------------------------- ------------
VOLUME WEIGHTING Volume Weighting % Change
-------------------------- -------------------------- ------------
Light oil (Bbl/d) 10,076 27% 9,087 36% 11%
Medium oil (Bbl/d) 8,792 23% 5,416 22% 62%
Heavy oil (Bbl/d) 13,735 37% 7,894 32% 74%
- ---------------------------------------------------------------------------------------------
Total oil (Bbl/d) 32,603 87% 22,397 90% 46%
Natural gas liquids (Bbl/d) 850 2% 377 2% 125%
- ---------------------------------------------------------------------------------------------
Total oil and natural gas
liquids (Bbl/d) 33,453 89% 22,774 92% 47%
Natural gas (mcf/d) 24,574 11% 11,909 8% 106%
- ---------------------------------------------------------------------------------------------
Total oil equivalent (BOE/d) 37,549 100% 24,759 100.0% 52%
- ---------------------------------------------------------------------------------------------
-7-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30
-----------------------------------------------------
2005 2004
-------------------------- -------------------------- ------------
VOLUME WEIGHTING Volume Weighting % Change
-------------------------- -------------------------- ------------
Light oil (Bbl/d) 9,949 28% 6,461 35% 54%
Medium oil (Bbl/d) 6,669 19% 4,553 25% 46%
Heavy oil (Bbl/d) 13,906 39% 6,271 34% 122%
- ---------------------------------------------------------------------------------------------
Total oil (Bbl/d) 30,524 86% 17,285 94% 77%
Natural gas liquids (Bbl/d) 810 2% 190 1% 326%
- ---------------------------------------------------------------------------------------------
Total oil and natural gas
liquids (Bbl/d) 31,334 88% 17,475 95% 79%
Natural gas (mcf/d) 26,839 12% 5,049 5% 432%
- ---------------------------------------------------------------------------------------------
Total oil equivalent (BOE/d) 35,807 100% 18,317 100% 95%
- ---------------------------------------------------------------------------------------------
Third quarter 2005 production was impacted by an unscheduled outage at our
Suffield property, which caused production to be shut-in for just over 2 days.
This was immediately followed by a heavy rain fall which delayed the
installation of additional equipment and further impacted production levels for
a total of approximately 6 days. This downtime, in addition to scheduled
turnarounds and wet ground conditions experienced in other areas in Alberta and
Saskatchewan, resulted in lower realized oil production in the third quarter
relative to capacity.
With the closing of the Hay River, B.C. property acquisition on August 2, 2005,
we acquired approximately 5,200 BOE/d of medium gravity crude oil.. While
current production levels are between 38,000 to 39,000 BOE/d, we continue to
estimate that our full year 2005 production will average between 36,250 and
36,750 BOE/d.
REALIZED COMMODITY PRICES
The following table provides a breakdown of our third quarter and year to date
2005 and 2004 average commodity prices by product type before realized losses on
derivative contracts.
THREE MONTHS ENDED SEPTEMBER 30 NINE MONTHS ENDED SEPTEMBER 30
--------------------------------------------------------------------------------------
2005 2004 Change 2005 2004 Change
- ------------------------------------------------------------------------------- -----------------------------------------
Product prices:
Light oil ($/bbl) $ 70.57 $ 53.46 32% $ 61.94 $ 46.52 33%
Medium oil ($/bbl) 60.14 43.54 38% 49.75 39.89 25%
Heavy oil ($/bbl) 52.37 37.64 39% 39.98 35.67 12%
Natural gas liquids ($/bbl) 54.23 45.69 19% 46.17 37.37 24%
Natural gas ($/mcf) 10.69 6.22 72% 8.31 5.83 43%
--------------------------------------------------------------------------- -----------------------------------------
Average BOE ($/BOE) $ 60.39 $ 44.83 35% $ 49.27 $ 40.43 22%
- ---------------------------------------------------------------------------------------------------------------------------
Realized loss on derivative
contracts ($/BOE)(1) (6.85) (7.22) (5%) (6.76) (7.52) (10%)
Realized price after hedging ($/BOE) $ 53.45 $ 37.61 42% $ 42.52 $ 32.91 29%
- ---------------------------------------------------------------------------------------------------------------------------
(1) INCLUDES AMOUNTS REALIZED ON WTI, HEAVY PRICE DIFFERENTIAL AND FOREIGN
EXCHANGE CONTRACTS, AND EXCLUDES AMOUNTS REALIZED ON ELECTRICITY CONTRACTS.
Average realized prices continued to strengthen during the third quarter and
were 35% higher during the period compared to the third quarter of 2004. For the
first nine months of 2005, our average realized prices were 22% higher than the
same period in 2004. In the three and nine months ended September 30, 2005, the
realized losses on crude oil and foreign exchange derivative contracts totaled
$23.7 million and $66.0 million, respectively. This is higher than the $16.5
million and $37.8 million losses realized in the three and nine months ended
September 30, 2004, respectively and is primarily attributable to higher
commodity prices in 2005 relative to 2004.
-8-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
Relative to the second quarter of 2005, our per BOE realized revenues were
$14.72 higher, yet we did not experience a corresponding increase in the
realized losses on our derivative contracts. In fact, our realized loss on
derivative contracts decreased from $7.49 per BOE in the second quarter of 2005
to $6.85 per BOE in the third quarter of 2005, attributable to the expiry of
contracts with fixed price ceilings at June 30, 2005 and higher production
volumes. All of our WTI price swap and collar contracts, which provide a fixed
ceiling on WTI prices, expire at the end of 2005. All of our 2006 and 2007
hedges provide a firm floor while still allowing Harvest to participate in
upward oil price movements. As a result, we anticipate lower hedge losses in
2006 then 2005 assuming similar world oil prices. For the nine month period
ended September 30, 2005, the realized loss on derivative contracts per BOE was
$6.76 per BOE compared to $7.52 per BOE in the same period the previous year.
Despite a 42% increase in the price of WTI to September 30, 2005, the reported
decline in hedging losses per BOE reflects the evolution of our hedging
strategy, which provides firm floors with upside participation. Examples of such
contracts include `indexed puts' and `participating swaps', and additional
information on these and other commodity derivative contracts can be found in
the "Derivative Contracts" section of this MD&A. We anticipate that these
structures will enable us to realize oil prices that are closer to spot price
levels during 2006 and 2007 than would have been the case with our 2004 hedging
instruments which were primarily swaps and collars. The table below provides an
example of the impact of Harvest's 2006 commodity derivative contracts in light
of varying WTI oil price levels. This data is designed to provide readers with
directional information only.
Average Annual Oil Price Assumed ($U.S.) Harvest Average WTI Oil Price After Hedging ($U.S.)
- ---------------------------------------- ---------------------------------------------------
$35.00 WTI $41.19
$55.00 WTI $50.29
$75.00 WTI $69.88
==============================================================================================
At the time of writing, we have hedged against downward WTI price movements on
approximately 70% of our total 2005 net crude oil production, approximately 79%
of our estimated 2006 net crude oil production, and approximately 24% of our
estimated 2007 net crude oil production (based on an assumption of flat
production through 2007). The majority of our remaining 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. For
example, Harvest would participate in approximately 70% of any increases in WTI
prices above the floor price during 2006, and approximately 90% of any increases
in WTI prices above the floor during 2007 (assuming a $60.00 WTI price and flat
production). We believe that this hedging format provides a good balance between
downside protection and upside participation for our unitholders.
Three months ended September 30 Nine months ended September 30
--------------------------------------- -------------------------------------
Benchmarks 2005 2004 Change 2005 2004 Change
- ------------------------------------------------------------------------------------------- -------------------------------------
West Texas Intermediate crude oil (US$ per barrel) $ 63.19 $ 43.88 44% $ 55.40 $ 39.11 42%
Edmonton Par light crude ($ per barrel) $ 76.51 $ 56.32 36% $ 67.91 $ 50.83 34%
Lloyd blend crude oil ($ per barrel) $ 53.30 $ 40.87 30% $ 43.46 $ 36.74 18%
Bow river blend crude oil ($ per barrel) $ 54.94 $ 41.55 32% $ 44.80 $ 37.70 19%
Natural Gas Liquids ($ per barrel) $ 58.39 $ 44.83 30% $ 53.79 $ 41.49 30%
AECO natural gas ($ per mcf) $ 9.29 $ 6.21 50% $ 7.85 $ 6.54 20%
U.S. / Canadian dollar exchange rate 1.201 1.307 -8% 1.224 1.328 -8%
Bank of Canada interest rate 2.82% 2.31% 22% 2.77% 2.44% 14%
- ---------------------------------------------------------------------------------------------------------------------------------
The benchmark price of WTI crude oil has the greatest impact on our revenues as
the majority of the Trust's production is crude oil. Foreign exchange also has
an impact on our revenues as oil prices are denominated in U.S. dollars, so a
strengthening Canadian dollar against the U.S. dollar has a negative impact on
our revenues. Given our third quarter production weighting to natural gas of
approximately 11%, fluctuations in natural gas prices also have an impact,
albeit a smaller one, on our revenue.
The unusual hurricane activity in the third quarter combined with the tight
overall crude oil balance in the world has resulted in unprecedented prices for
crude oil. Relative to the significant increases in the benchmark price of WTI,
the realized price for our physical crude oil streams was somewhat different.
This is partly due to the strengthening Canadian dollar versus the US dollar,
which negatively impacts our realized price in Canadian dollars, as well as
changes in crude quality differentials. Thus, although WTI increased 44% from
the third quarter of 2004, our light oil price increased 30%. The differential
between heavy and light crude oil prices widened early in 2005 reflecting the
attractiveness of the lighter blends to refiners as capacity to convert heavy
oil barrels to light oil products became constrained. As the table below
demonstrates, the benchmark Lloyd Blend (LLB) and Bow River differentials
narrowed through the third quarter compared to the first and
second quarters of
-9-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
2005. Approximately 80% our medium and heavy production prices are based on the
Bow River Blend benchmark (adjusted for stream quality), which is reflected as a
percentage discount to the Edmonton Light price. The discount will vary due to
seasonality and refinery demand.
Differential Benchmarks Q1 2005 Q2 2005 Q3 2005
- --------------------------------------------------------------------------------------
Bow River blend differential to Edmonton Light 36.6% 39.6% 28.2%
Lloyd Blend (LLB) differential to Edmonton Light 39.4% 39.7% 30.3%
======================================================================================
Differentials narrowed between May and August and our medium and heavy gravity
crudes were positively impacted as a result. Towards the end of the third
quarter of 2005, however, heavy oil price differentials did begin to widen
again. Overall, average heavy oil differentials in the third quarter of 2005
were significantly lower than the second quarter despite a US$10.00 per barrel
increase in the price of WTI in the third quarter. The widening differential
trend observed at the end of the third quarter has continued into the fourth
quarter. However, we have proactively mitigated our exposure to this volatility
by hedging the differential to WTI on 10,000 bbl/day or 87% of our net heavy oil
production through the end of 2006 at a ratio very close to long term historical
averages (29%). Had our differential hedges been in place for the nine month
period ending September 30, 2005, our total gain on those contracts would have
been $9 million. In addition to the pricing support realized from our hedging
program, our medium oil production from the Hay River property commands a higher
premium over the benchmark Bow River blend price compared to our other medium
gravity oil production.
Natural gas prices in the third quarter were also at all time highs. The natural
gas supply / demand imbalance is tighter than in recent years after the shut-ins
caused by the hurricanes in the major production areas offshore the US Gulf
Coast. Due to the prospect of increased demand caused by cold weather, and the
need to substitute high priced heating oil with natural gas, natural gas prices
have remained very well supported. We have benefited from these higher prices by
maintaining a portfolio that is almost exclusively tied to the daily spot price
of natural gas traded at the AECO "C" hub. We have not hedged any of our natural
gas production at this time, and have fully benefited from the increase in
natural gas prices. Our realized natural gas prices exceed AECO due to the
natural gas produced in our more significant properties having a higher than
average heat content.
ROYALTIES
In the third quarter of 2005, royalties as a percentage of revenues before
hedging loss, were approximately 18.7% compared to 16.7% in the third quarter of
2004. The new Hay River properties acquired in August 2005 have a higher royalty
rate, which increased our average royalty rate in the third quarter, and is
estimated to increase our overall royalty rates to approximately 18% to 19% for
the balance of 2005. For the nine month period ended September 30, 2005,
royalties as a percent of revenue were 17.0%, compared to 16.8% in the same
period in 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 3.1% with Saskatchewan revenues which makes up approximately 20%
of Harvest's total. This surcharge, along with the impact of the higher royalty
Hay River property, increased our royalty rate from 16% in the second quarter of
2005 to 18.7% in the third quarter, and caused the slight increase compared to
the nine months ended September 30, 2004.
OPERATING EXPENSES
Three months ended September 30 Nine months ended September 30
------------------------------ ---------------------------------
($ PER BOE) 2005 2004 Change 2005 2004 Change
- ----------------------------------------------------------------- ---------------------------------
Operating expense $ 9.39 $ 8.58 9% $ 9.05 9.51 (5%)
Realized gains on electricity
derivative contracts (0.43) (0.24) 79% (0.18) (0.29) (38%)
- ----------------------------------------------------------------- ---------------------------------
Net operating expense $ 8.96 $ 8.34 7% $ 8.87 $ 9.22 (4%)
====================================================================================================
The decrease in operating expenses (before gains on electricity derivative
contracts), during the nine months ended September 30, 2005 compared to the same
period of 2004 reflects lower cost assets purchased late in 2004, as well as the
effect of operating cost reduction projects completed since then. 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 as a result of the downtime described
under "Sales Volumes". This negatively impacted the third quarter operating cost
per BOE. The Hay River properties acquired in August 2005 have lower operating
costs at approximately
-10-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
$7.75 per BOE, which can help to partially offset rising operating costs per
BOE. We expect our full year 2005 operating expenses to average between $8.75
and $9.00 per BOE.
Operating costs per BOE declined slightly from the second quarter ($9.08/BOE),
but not as much as had been anticipated with the impact of the lower cost Hay
properties. The is primarily attributable to weather related delays lengthening
rig times for services, non-hedged power cost increases and the impact of the
volume shortfalls discussed previously. For the three and nine month periods
ended September 30, 2005, approximately 28% of our operating costs are related
to the consumption of electricity. The third quarter demonstrated continued
volatility for Alberta electricity prices despite the recently added generation
of the Genesee #3 power plant. July settled at the lowest average monthly pool
price of the year at $37.75 only to be followed by the two highest average
monthly prices in the year in August and September at $88.33 and $74.30/MWh,
respectively. July's unit availability was excellent, however August was plagued
with coal fired plant outages. September saw slightly fewer coal fired outages
but an increased number of gas units on maintenance outages. Management has
utilized fixed price electricity contracts to mitigate electricity price risk
within Alberta, which has benefited us due to the rising price of natural gas
and increased volatility in power costs in the latter part of 2005.
Approximately 82% of our estimated Alberta electricity usage is hedged at an
average price of $48.31 per MWh through December 2006, and we successfully
entered into two new hedges for 2007 and 2008 that secure a power price of
$55.00 per MWh. Assuming we maintained flat electricity consumption in through
2008, we would have protected approximately 60% of our expected power
consumption from price spikes and volatility. Our electricity hedges will help
moderate the impact of future cost swings, as will realizing the benefits of
capital projects undertaken in 2004 and to date in 2005 that have been dedicated
to power efficiency projects.
Three months ended September 30 Nine months ended September 30
------------------------------ ---------------------------------
Benchmark Price 2005 2004 Change 2005 2004 Change
- ----------------------------------------------------------------- ---------------------------------
Alberta Power Pool Electricity
price ($ per MWh) $ 66.79 $ 54.33 23% 54.72 54.43 1%
====================================================================================================
GENERAL AND ADMINISTRATION EXPENSES ("G&A")
Three months ended September 30 Nine months ended September 30
---------------------------------------- -----------------------------------------
($MILLIONS EXCEPT PER BOE) 2005 2004 Change 2005 2004 Change
- ----------------------------------------------------------------------------- -----------------------------------------
G&A $ 3.8 1.8 111% 9.9 4.5 120%
Per BOE ($/BOE) 1.09 0.79 38% 1.02 0.90 13%
G&A - non-cash unit compensation expense 9.2 0.4 2200% 15.1 0.8 1788%
Per BOE ($/BOE) 2.66 0.18 1377% 1.54 0.16 863%
- ----------------------------------------------------------------------------- -----------------------------------------
Total G&A $ 13.0 $ 2.2 491% $ 25.0 $ 5.3 372%
Per BOE ($/BOE) $ 3.75 $ 0.97 287% $ 2.56 1.06 142%
========================================================================================================================
The increase in cash G&A, excluding non-cash unit right compensation expense, is
the result of higher staff and system expenses associated with the additional
properties in our portfolio. In addition, a portion of our cash G&A is related
to our unit right compensation plan to the extent rights were exercised for
cash. For the three and nine month periods ended September 30, 2005, cash unit
right compensation expense was $800,000 and $980,000, respectively. For the same
periods in 2004, there were no cash costs incurred relating to the unit right
compensation plan. For 2005, we anticipate that Harvest's cash G&A per BOE will
be between $1.00 and $1.10 per BOE, before unit right compensation expenses. As
expected, there was not a significant increase in cash G&A expenses associated
with the Hay acquisition.
General and administration expenses charged against income in the third quarter
of 2005 totaled $13.0 million ($3.75/BOE) compared to $2.2 million ($0.97/BOE)
in the same quarter in 2004. For the nine month period ended September 30, 2005,
G&A charged against income totaled $25.0 million ($2.56/BOE) compared to $5.3
million ($1.06/BOE) in the same period in 2004.
The significant increase in total G&A in 2005 compared to 2004 is a result of a
prospective change in accounting for Unit appreciation rights (UARs). In the
third quarter of 2004, the Plan was modified so UAR holders could settle in cash
and therefore we now value vested UARs at the difference between exercise price
and market price at each reporting period end to determine the related liability
at that date. Changes in the assumptions used in determining this liability,
such as our Trust Unit price, the exercise price and the number of UARs vested
at each accounting period will cause this liability to fluctuate and the
difference is reflected as an expense on the consolidated statement of income.
INTEREST EXPENSE
Three months ended September 30 Nine months ended September 30
------------------------------------- -------------------------------------
2005 2004 Change 2005 2004 Change
($MILLIONS) (RESTATED) (RESTATED)
- ----------------------------------------------------------------------------------------- -------------------------------------
Interest on short term debt $ 1.1 $ 3.5 (69%) $ 4.0 $ 4.6 (13%)
Amortization of deferred charges - short term debt - 0.5 (100%) 2.5 1.8 39%
- -------------------------------------------------------------------------------------------------------------------------------
Total interest on short term debt 1.1 4.0 (73%) $ 6.5 $ 6.4 2%
Interest on long term debt 7.0 2.7 159% 20.0 5.0 300%
Amortization of deferred charges - long term debt 0.7 0.2 250% 1.5 0.4 250%
- -------------------------------------------------------------------------------------------------------------------------------
Total interest on long term debt 7.7 2.9 166% 21.5 5.4 298%
- -------------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 8.8 $ 6.9 28% $ 28.0 $ 11.8 136%
===============================================================================================================================
-11-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
In the three and nine month periods ended September 30, 2005, cash interest on
short term debt totaled $1.1 million and $4.0 million, compared to $3.5 million
and $4.6 million for the same periods in 2004. Interest on short term debt
relates to the interest paid on our outstanding bank debt, and for 2004,
interest on our equity bridge loan. Cash interest on long term debt totaled $7.0
million and $20.0 million in the third quarter and nine months ended September
30, 2005, and $2.7 million and $5.0 million in the same periods in 2004. Of the
interest on long term debt, $5.9 million in the three month period and $17.9
million in the nine month period ended September 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%)
debt instrument, a natural hedge to currency exchange rates, and a fourth year
redemption feature. For the three and nine month periods ending September 30,
2005, the remaining $1.1 million and $2.1 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 deficit 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 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. Interest on short-term debt is lower in the third quarter of
2005 than 2004 as bank debt levels are substantially lower. Bank debt was
partially repaid with the proceeds from the senior note issuance in 2004.
Our third quarter total interest expense and amortization of deferred charges of
$8.8 million is higher than the $6.9 million reflected in the third quarter of
2004. For the nine month period ended September 30, 2005 total interest expense
and amortization of deferred charges was $27.9 million compared to $11.8 million
for the same period in 2004. The increase in total interest expense in 2005 is
due to the senior notes.
DEPLETION, DEPRECIATION AND ACCRETION (DD&A)
Three months ended September 30 Nine months ended September 30
------------------------------------ ------------------------------------
($MILLIONS EXCEPT PER BOE) 2005 2004 Change 2005 2004 Change
- ---------------------------------------------------------------------------------- ------------------------------------
Depletion and depreciation $ 40.4 $ 24.4 66% $ 109.3 $ 44.1 148%
Depletion of capitalized asset retirement costs 6.2 2.5 148% 11.6 6.0 93%
Accretion on asset retirement obligation 2.4 1.2 100% 7.0 2.9 141%
- -----------------------------------------------------------------------------------------------------------------------
Total depletion, depreciation and accretion $ 49.0 $ 28.1 74% $ 127.9 $ 53.0 141%
Per BOE ($/BOE) $ 14.18 $ 12.34 15% $ 13.09 $ 10.56 24%
=======================================================================================================================
Relative to the third quarter of 2004 and the nine month period ended September
30, 2004, our higher DD&A is primarily attributable to the significant
acquisitions completed in June and September 2004 and August 2005, and the
resulting higher DD&A rates are justified due to the higher netback production
acquired in each of these acquisitions. We anticipate full year 2005 DD&A rates
to range between $13 and $15 per BOE.
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 $1 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 third quarter of
2005, the Canadian dollar strengthened against the U.S. dollar, and we incurred
unrealized gains on our senior notes of $15.6 million. This amount was partially
offset by realized settlements of amounts held on deposit denominated in U.S.
dollars. The net result for the third quarter 2005 was a foreign exchange gain
of $14.0 million. In the third quarter of 2004, we did not have any U.S. dollar
denominated debt and consequently, did not record significant foreign exchange
gains or losses in that period.
For the nine month period ended September 30, 2005, we realized a foreign
exchange gain of $8.6 million, compared to a foreign exchange gain of $565,000
for the same period in 2004. Again, the gain in 2005 reflects the impact of a
stronger Canadian dollar on our senior notes.
-12-
HARVEST ENERGY TRUST 3RD 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 as at the balance sheet date 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 each 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 $80.7 million as at
September 30, 2005. The difference between this value and the mark-to-market
amount at December 31, 2004 ($15.4 million) is reflected as an unrealized loss
in the nine month period ended September 30, 2005. Please refer to Note 11 to
the consolidated financial statements for further information.
The following table provides a reconciliation of the changes in Harvest's
mark-to-market position on its derivative contracts from January 1, 2005 to
September 30, 2005.
($MILLIONS) AS AT SEPTEMBER 30, 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) 10.0 12.5
- -------------------------------------------------------------------------------------------------------------------
Closing mark-to-market position (80.7) (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 September 30, 2005, we recorded a net realized loss on
all derivative contracts of $22.2 million ($6.85/BOE), and a net unrealized
loss, including amortization of deferred charges and gains, of $3.9 million
($1.14/BOE) for a total loss of $26.1 ($7.56/BOE) million. For the nine month
period ended September 30, 2005, we recorded a realized loss on all derivative
contracts of $64.3 million ($6.76/BOE), and an unrealized loss including
amortization of deferred charges and gains, of $73.5 ($7.52/BOE) million for a
total loss of $137.8 million ($14.09/BOE).
The realized loss portion reflects the effective cost of our hedges related to
production during the period.
Realized losses on derivative contracts for the three months ended June 30, 2005
were $23.3 million ($7.49/BOE). The decrease from $23.3 million in the second
quarter to $22.2 million in the third quarter of 2005 is due to the expiration
of contracts with fixed price ceilings, higher volumes in the third quarter, and
higher gains realized on our electricity hedges. However, that portion of our
realized losses relating specifically to our crude oil hedges increased from
$23.3 million in the second quarter of 2005 to $24.0 million in the third
quarter of 2005 due to a US$10.02 increase in the benchmark WTI crude oil price
from US$53.17 in the second quarter to US$63.19 in the third quarter of 2005.
Our losses relative to the increase in WTI were lower in the third quarter
compared to the second quarter of 2005, due to the expiration of hedge contracts
noted above. Assuming a similar pricing environment in 2006, we would expect
lower losses than those realized in 2005 because we have no production hedged
with fixed price derivative instruments, such as swaps and collars in 2006 or
2007.
The table below provides a summary of gains and losses on derivative contracts:
-13-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
Three months
ended
September 30,
THREE MONTHS ENDED SEPTEMBER 30, 2005 2004
------------------------------------------------------- ---------------
($THOUSANDS) Oil Currency Electricity Total Total
- ----------------------------------------------------------------------------------------------------------- ---------------
Unrealized (losses) / gains on derivative contracts (7,285) 704 3,396 (3,185) (19,664)
Realized (loss) / gain on derivative contracts (23,984) 332 1,470 (22,182) (15,912)
Amortization of deferred charges relating to
derivative contracts (1,207) - - (1,207) -
Amortization of deferred gains relating to derivative
contracts - - 444 444 -
- ----------------------------------------------------------------------------------------------------------- ---------------
Total (losses) / gains on derivative contracts (32,476) 1,036 5,310 (26,130) (35,576)
===========================================================================================================================
Three months
ended
September 30,
THREE MONTHS ENDED SEPTEMBER 30, 2005 2004
------------------------------------------------------- ---------------
($THOUSANDS) Oil Currency Electricity Total Total
- ----------------------------------------------------------------------------------------------------------- ---------------
Unrealized (losses) / gains on derivative contracts (71,801) (3,488) 9,982 (65,307) (23,906)
Realized (loss) / gain on derivative contracts (67,042) 1,004 1,783 (64,255) (36,311)
Amortization of deferred charges relating to
derivative contracts (9,551) - - (9,551) (5,490)
Amortization of deferred gains relating to derivative
contracts - - 1,334 1,334 -
- ----------------------------------------------------------------------------------------------------------- ---------------
Total (losses) / gains on derivative contracts (148,394) (2,484) 13,099 (137,779) (65,707)
===========================================================================================================================
PREPAID EXPENSES AND DEPOSITS
Our prepaid expenses and deposits balance of $1.8 million includes $463,000 of
amounts which are held on margin with counterparties to our derivative
contracts. The balance held on margin of $463,000 is substantially lower than
the second quarter 2005 balance of $44.5 million due to the successful transfer
of several of our derivative contracts to an alternate counterparty that
requires lower margin deposits. Cash released from these deposits was used to
repay bank debt.
DEFERRED CHARGES AND DEFERRED GAINS
The deferred charges asset balance on the balance sheet is comprised of two main
components: deferred financing charges and deferred assets related to the
discontinuation of hedge accounting. The deferred financing charges relate
primarily to the issuance of the senior notes, convertible debentures and bank
debt and are amortized over the life of the corresponding debt.
DEFERRED CHARGES
($THOUSANDS) As at September 30, 2005 As at December 31, 2004
- ----------------------------------------------------------------------- ----------------------------------------------------
ON DIS- On Dis-
CONTINUATION Continuation Financing
OF HEDGE FINANCING DISCOUNT ON of Hedge Costs Discount On
FINANCING COSTS SENIOR NOTES TOTAL Financing (restated) Senior Notes Total
- ----------------------------------------------------------------------- ----------------------------------------------------
Opening Balance 10,759 12,781 2,000 25,540 - 1,989 - 1,989
Additions - 5,063 - 5,063 25,705 20,971 2,075 48,751
Transferred to - -
unit issue - -
costs - (1,402) - (1,402) - (5,721) - (5,721)
Amortization (9,551) (3,992) (222) (13,765) (14,946) (4,458) (75) (19,479)
- ----------------------------------------------------------------------- ----------------------------------------------------
Closing Balance 1,208 12,450 1,778 15,436 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
-14-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
derivative contracts asset or liability. The deferred amount is recognized in
income in the period in which the underlying transaction is recognized.
For the nine month period ended September 30, 2005, $9.6 million of the deferred
charge and $1.3 million of the deferred gain was amortized and recorded in gains
and losses on derivative contracts. At September 30, 2005, a $1.2 million
deferred charge and an $843,000 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. No goodwill was recorded in association with
the Hay River acquisition in August 2005, as the fair value of assets acquired
approximated the total consideration paid.
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
future income tax expense (recovery) for the three and nine month period ended
September 30, 2005 of $1.2 million and $(28.6) million, respectively, compared
to $(9.8) million and $(14.0) million for the same periods in 2004. The
significant increase in the future income tax recovery in the nine month period,
despite positive earnings before taxes in the period, is due to the accounting
earnings being attributable to non-corporate subsidiaries of the Trust. The
corporate subsidiaries of the Trust earned an accounting loss in this period.
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 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, and for changes to any assumptions used in
the estimation of the ARO.
Our asset retirement obligation has increased by approximately $10.4 million in
the nine months ended September 30, 2005 mainly due to the additional obligation
recorded in connection with the Hay River properties as well as the accretion of
the asset retirement obligation.
NON-CONTROLLING INTEREST
At September 30, 2005, we have recorded a non-controlling interest amount on our
consolidated balance sheet of $3.0 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 regarding exchangeable shares
(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
-13-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
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 ultimately converted to Trust Units. The total
number of exchangeable shares converted in the nine months ended September 30,
2005 was 263,865, leaving a balance of exchangeable shares of 191,682 at
September 30, 2005 compared to a balance of 455,547 at January 1, 2005. The
exchange ratio at September 30, 2005 was 1:1.14463, which would result in an
additional 219,405 trust units if all of the exchangeable shares were converted
at the end of the third quarter.
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 income or loss attributed to
the non-controlling interest holders during the period. This allocation is
calculated on a monthly basis and as such, we may report net income on a
quarterly basis and continue to allocate a loss to the exchangeable shareholders
due to conversions during the period and net losses reported in any given month
within the period. The total net income (loss) attributed to non-controlling
interest holders for the three and nine months ended September 30, 2005 was
$219,000 and $(156,000) ($40,000 - three and nine months ended September 30,
2005), 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 third
quarter of 2005, our distribution payout ratio of 45% (2004 - 45%) (calculated
by dividing distributions to Unitholders by Funds Flow from Operations) resulted
in excess Funds Flow from Operations available for our capital expenditure
programs. Our payout ratio for the nine month period ended September 30, 2005
was 46% (excluding the special distribution of 2004 income paid in Trust Units
in April) compared to 55% for the same period in 2004. In the previous quarter,
we announced a 25% increase to our monthly distribution level, effective with
the July distribution, payable in August. In the third quarter, we announced a
further 40% increase to our monthly distribution level to $0.35 per Trust Unit
per month. Management anticipates that this level could be maintained through
2006, while maintaining a significant capital program, in almost any WTI price
scenario because of our hedging program. This increase in distributions is a
reflection of the success of our strategy to date.
As at September 30, 2005, Harvest's net debt decreased to $418.2 million from
$429.6 million at December 31, 2004.
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 continue repayment of our outstanding bank debt. It is also important
to note that following the August implementation of our new Distribution
Reinvestment, Premium Distribution and Optional Trust Unit Purchase Plan ("DRIP
Plan"), the participation level in the DRIP Plan has risen to approximately 40%.
This participation directly reduces the cash component of our monthly
distribution payments and affords us additional financial flexibility.
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
continue repaying bank debt through the balance of 2005 and through 2006.
Currently, we have $350 million of undrawn borrowing capacity under our credit
facility.
-16-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
AS AT SEPTEMBER 30, As at December 31,
($ MILLIONS) 2005 2004 Change
- ----------------------------------------------------------------------------------------------------------------------
Bank debt $ 34.6 $ 75.5 (54%)
Working capital deficit (surplus) excluding bank debt(1) 28.4 27.8 (2%)
Senior notes, due 2011 290.7 300.5 (3%)
Convertible debentures, due 2009-2010 64.5 25.8 150%
- ----------------------------------------------------------------------------------------------------------------------
Net debt obligations $ 418.2 $ 429.6 (3%)
- ----------------------------------------------------------------------------------------------------------------------
Annualized quarterly funds flow(2) $ 414.0 $ 211.5 96%
Net debt to funds flow (times) 1.0 2.0 (50%)
======================================================================================================================
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 THIRD
QUARTER GIVEN THE NATURE OF OUR OIL PRICE HEDGES.
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 September 30, 2005
and 2004, we declared $46.7 million and $18.4 million, respectively, in
distributions payable to unitholders ($0.25 per Trust Unit declared in July, and
$0.35 per Unit declared in each of August and September 2005). Prior to the July
distribution declaration, Harvest had paid a consistent $0.20 per Trust Unit per
month since our inception in December 2002. For the purposes of the cash flow
statements, distributions are reported on a cash paid basis, however, we accrue
distributions declared as at each period end.
Year to date in 2005, distributions declared total $109.0 million, including the
payment of a special one-time distribution relating to undistributed 2004
taxable income of $10.7 million, compared to $39.7 million declared during the
same period in 2004. The higher level of distributions paid in 2005 reflects the
rising distributions paid per unit, as well as an increased number of Trust
Units outstanding compared to the same period in 2004. The increase in Trust
Units outstanding is primarily due to the issuance of 6.5 million Trust Units on
August 2, 2005 and the continued conversion of convertible debentures.
Our DRIP Plan gives Canadian Unitholders the option to reinvest their cash
distributions back into Harvest Units or in the Premium Distribution(TM)
component, to receive a cash payment equal to 102% of the regular distribution
amount. Enrollment in either the distribution reinvestment or Premium
Distribution(TM) component enables Unitholders to make additional purchases of
Trust Units directly from treasury through the Optional Trust Unit Purchase
Plan. Both components of the DRIP Plan reduce the net cash outlay Harvest is
required to make on a monthly basis. Management anticipates that for the balance
of 2005, participation in the DRIP Plan will be approximately 40%, the same
level as that experienced in September.
Distribution payments to U.S. Unitholders are subject to 15% Canadian
withholding tax. 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 were listed for trading on the NYSE on July 21, 2005. This
listing has provided Harvest's unitholders with additional liquidity, and
Harvest with greater access to the U.S. capital markets. From time to time the
Trust may require external financing, in the form of either debt or 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.
Of the convertible debentures outstanding at September 30, 2005, approximately
$13.1 million have converted into Units through November 7th, 2005 and we
anticipate continued conversions of in-the-money debentures through 2005.
-16-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
A breakdown of our outstanding Trust Units and potentially dilutive elements is
as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
AS AT As at As at
SEPTEMBER 30, 2005 December 31, 2004 September 30, 2004
- ----------------------------------------------------------------------------------------------------------------------------------
Market price of Trust Units at end of period ($/unit) 38.00 22.95 20.79
Trust Units outstanding 51,558,576 41,788,500 36,874,829
Exchangeable shares outstanding(1) 191,682 455,547 552,972
Trust Units represented by Exchangeable shares 219,405 485,003 583,961
Total market value of Trust Units at end of period(2) ($millions) $ 1,968 $ 970 $ 779
9% Convertible debentures(3), face value ($000) $ 1,898 $ 10,700 $ 24,915,000
8% Convertible debentures(4), face value ($000) $ 5,758 $ 15,159 $ 71,219,000
6.5% Convertible debentures(5), face value ($000) $ 56,827 $ - $ -
Trust Unit rights outstanding(6) 1,573,099 1,128,387 1,230,225
Total Trust Units, diluted(7) 55,679,556 45,099,038 44,851,365
- ----------------------------------------------------------------------------------------------------------------------------------
NOTE 1 EXCHANGEABLE SHARES ARE EXCHANGEABLE INTO TRUST UNITS AT THE ELECTION
OF THE HOLDER AT ANY TIME. THE EXCHANGE RATIO IN EFFECT ON SEPTEMBER
30, 2005 WAS 1.14463:1, AND ON DECEMBER 31, 2004 WAS 1.06466:1. THE
SEPTEMBER 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. (PRIOR TO APRIL 1, 2005, THE
CONVERSION PRICE WAS $14.00) IF DEBENTURE HOLDERS CONVERTED ALL
OUTSTANDING DEBENTURES IN THIS SERIES AT SEPT. 30, 2005 AND DECEMBER
31, 2004, AN ADDITIONAL 137,040 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. (PRIOR TO APRIL 1, 2005, THE
CONVERSION PRICE WAS $16.25) IF DEBENTURE HOLDERS CONVERTED ALL
OUTSTANDING DEBENTURES IN THIS SERIES AT SEPT. 30, 2005 AND DECEMBER
31, 2004, AN ADDITIONAL 358,307 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 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 $31.00 PER TRUST UNIT. IF DEBENTURE HOLDERS CONVERTED ALL
OUTSTANDING DEBENTURES IN THIS SERIES AT SEPT. 30, 2005 AND DECEMBER
31, 2004, AN ADDITIONAL 1,833,129 AND NIL 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 6 EXERCISABLE AT AN AVERAGE PRICE OF $16.70 PER TRUST UNIT AS AT
SEPTEMBER 30, 2005, AND $10.09 PER TRUST UNIT AS AT DECEMBER 31, 2004.
ALSO INCLUDES UNIT AWARD INCENTIVE PLAN RIGHTS OF 35,024 AS AT
SEPTEMBER 30, 2005 AND 10,662 AT DECEMBER 31, 2004. EACH UNIT AWARD
INCENTIVE PLAN RIGHT CAN BE CONVERTED INTO ONE TRUST UNIT ONCE VESTED
WITH NO ADDITIONAL CONSIDERATION.
NOTE 7 FULLY DILUTED UNITS DIFFER FROM DILUTED UNITS FOR ACCOUNTING
PURPOSES. FULLY DILUTED INCLUDES TRUST UNITS OUTSTANDING AS AT
SEPTEMBER 30, 2005 OR DECEMBER 31, 2004 PLUS THE IMPACT OF THE
CONVERSION OR EXERCISE OF EXCHANGEABLE SHARES, TRUST UNIT RIGHTS, UNIT
AWARD RIGHTS AND CONVERTIBLE DEBENTURES IF COMPLETED AT SEPTEMBER 30,
2005 OR DECEMBER 31, 2004.
AS AT As at As at
($MILLIONS) SEPTEMBER 30, 2005 December 31, 2004 September 30, 2004
- ------------------------------------------------------------------------------------------------------------------------------
Total market capitalization(1) $ 1,967.6 $ 970.2 103%
Net debt 418.2 429.6 (3%)
- ------------------------------------------------------------------------------------------------------------------------------
Enterprise value (total capitalization)(2) $ 2,385.8 $ 1,399.8 70%
- ------------------------------------------------------------------------------------------------------------------------------
Net debt as a percentage of enterprise value3 (%) 18% 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.
NOTE 3 THIS RATIO CHANGED FOLLOWING THE $175 MILLION TRUST UNIT AND $75
MILLION CONVERTIBLE DEBENTURE FINANCING WHICH CLOSED ON AUGUST 2, 2005.
AS OF THAT DATE, THE RATIO WAS APPROXIMATELY 25%.
CONTRACTUAL OBLIGATIONS
Our contractual obligations have not changed significantly from those disclosed
in the MD&A and financial statements for the year ended December 31, 2004.
OFF BALANCE SHEET ARRANGEMENTS
We have a number of immaterial operating leases in place on moveable field
equipment, vehicles and office space. The leases require periodic lease payments
and are recorded as either operating costs or G&A. We also finance our annual
insurance premiums, whereby a portion of the annual premium is deferred and paid
monthly over the balance of the term.
RELATED PARTY TRANSACTIONS
A corporation controlled by one of our directors sublets office space from us
and we provide administrative services to that corporation on a cost recovery
basis. See Note 13 to the Consolidated Financial Statements.
CAPITAL ASSET EXPENDITURES
Three months ended September 30, 2005 Nine months ended September 30
------------------------------------- -------------------------------------
($MILLIONS) 2005 2004 Change 2005 2004 Change
- ---------------------------------------------------------------------------------- -------------------------------------
Development capital expenditures
excluding acquisitions & non-cash items $ 31.7 $ 13.2 140% $ 81.0 $ 31.7 156%
Non-cash capital additions 1.9 - 3.0 -
- ------------------------------------------------------------------------------------------------------------------------
Total development capital expenditures 33.6 13.2 155% 84.0 31.7 165%
Net property acquisitions 209.7 513.8 (59%) 239.3 590.9 (60%)
- ------------------------------------------------------------------------------------------------------------------------
Total net capital asset expenditures $ 243.3 $ 527.0 (54%) $ 323.3 $ 622.6 (48%)
========================================================================================================================
Development capital expenditures in the three and nine month periods ending
September 30, 2005, include non-cash capital additions of approximately $1.9
million and $3.0 million, respectively relating to non-cash UAR costs that have
been capitalized. The increase in development capital expenditures in the three
and nine months ended September 30, 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 our
acquisitions. Subsequent to the end of the quarter, we increased our 2005 full
year capital
-18-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
budget to approximately $130 million, which reflects increased development
opportunities identified by our operations teams, as well as some minor working
interest acquisitions in our core areas. We anticipate that the production
impact of this additional capital will be predominantly realized in the second
quarter of 2006.
For the three month period ended September 30, 2005, net property acquisitions
totaled $209.7 million and were primarily for the Hay River acquisition,
excluding $26 million paid in the second quarter. For the nine month period
ended September 30, 2005, net property acquisitions totaled $239.3 million. The
Hay River acquisition was financed initially with bank debt, which was
subsequently paid off with the issuance of $75 million of convertible debentures
and $175 million of equity. Property acquisition expenditures for the same
periods in 2004 were $513.8 million and $590.9 million, respectively. The
acquisition of Storm Energy took place in the second quarter of 2004 and the
acquisition of the EnCana properties in the third quarter of 2004, represent the
majority of the acquisition expenditures for the nine month ended September 30,
2004. The Storm Energy acquisition was financed with $75 million of debt and the
remainder with Trust Units and Exchangeable Shares. The EnCana acquisition was
financed with the credit facility, the equity bridge notes and an offering of
equity and convertible debentures.
We closed the acquisition of the Hay River property on August 2, 2005, and added
5,000 BOE/d of medium oil production, 19.8 mmBOE of proved plus probable
reserves, 54,000 net acres of undeveloped land, and numerous future drilling
locations. We will continue to be active in analyzing potential acquisition
opportunities. However, in the event the acquisition market becomes too
expensive and we do not see the potential to create value by purchasing assets,
we have a sufficient drilling location inventory to keep us active for the next
2 to 3 years.
-19-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
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 September 30, 2005 and our existing hedging program, and are
provided for directional information only.
Variable
---------------------------------------------------------------------------------------------
WTI Heavy Oil AECO Crude Oil Canadian Bank Foreign Exchange
Price/bbl Price as % of WTI Price/mcf Production Prime Rate Rate Cdn. / U.S.
- ----------------------------------------------------------------------------------------------------------------------------------
Assumption U.S.$55.00 36.4% C$9.00 39,000 boe/d 4.75% 1.17
Change U.S.$1.00 1% C$1.00 1,000 boe/d 1% 0.01
ANNUALIZED IMPACT ON:
Funds flow from operations ($000's) $6,066 $1,220 $7,286 $17,456 $393 $3,821
Per Trust Unit, basic $0.11 $0.02 $0.14 $0.33 $0.01 $0.07
Per Trust Unit, diluted $0.11 $0.02 $0.13 $0.31 $0.01 $0.07
Payout ratio 1.1% 0.2% 1.4% 3.4% 0.1% 0.7%
==================================================================================================================================
As noted above, our commodity price risk management program provides significant
downside price protection, while allowing Harvest to participate in upward price
movements. Thus, cash flow sensitivities are less extreme with WTI price
declines than with price increases.
Oil price derivative contracts in place as at September 30, 2005 are summarized
in the table below. The prices shown for collars, indexed puts and participating
swaps are floor prices.
2005 2006 2007
--------------------------------- --------------------------------- ---------------------------------
Volume (bbls/d) Pricing ($/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 8,719 $ 46.04 5,000 50.00
WTI Participating Swaps(1) - - 11,271 $ 39.73
WTI Participating Swaps(2) - - 5,000 $ 49.03 2,479 (49.03)
==================================================================================================================================
(1)50% UPSIDE PARTICIPATION
(2)75% UPSIDE PARTICIPATION.
Heavy and medium gravity crude oil trade at a price discount to WTI. Our
differential hedge contracts effectively fix the percentage discount from light
oil prices we receive on the sale of a portion of our medium and heavy gravity
crude oil. By defining the price differential between the heavy oil benchmark
and the light oil WTI benchmark, we have mitigated the uncertainty caused by
fluctuating heavy oil price differentials.
The percent of WTI shown in the table below represents the average of all
outstanding contracts used to hedge the heavy oil price differential to WTI.
2005 2006
---------------------------------- ---------------------------------
Volume (bbls/d) Percent of WTI Volume (bbls/d) Percent of WTI
- ------------------------------------------------------------------ ---------------------------------
OIL PRICE DIFFERENTIAL SWAP CONTRACTS
Sept 2005 - Dec 2006 contracts 10,000 28.7% 5,000 28.7%
- ----------------------------------------------------------------------------------------------------
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.
-20-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
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 (1,064)
Increase (decrease) in net income:
Interest expense(2) (751) (3,386) (1,443) (1,186)
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.
-21-
HARVEST ENERGY TRUST 3RD QUARTER 2005
- --------------------------------------------------------------------------------
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 any of our derivative instruments, we do not expect
these pronouncements to have a significant impact on our consolidated financial
results. However, we do have unrealized foreign exchange gains and losses.
NON-MONETARY TRANSACTIONS
The AcSB has issued Section 3831, NON-MONETARY TRANSACTIONS, which replaces
Section 3830, and requires all non-monetary transactions to be measured at fair
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 a material impact on our results of
operations or financial position.
-22-
HARVEST ENERGY TRUST 3RD 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.
In addition to the risks outlined in our 2004 annual MD&A, we have identified a
possible risk relating to the future tax treatment of income trusts in Canada.
In a consultation paper issued on September 8, 2005, the Canadian Federal
Government expressed concerns about several policy issues arising from the
recent proliferation of income trusts in Canada. This paper communicates the
government's concerns over how the tax treatment of trusts impacts the Canadian
economy, with specific reference to federal tax revenues. The government has
requested comments and feedback from interested stakeholders regarding the tax
treatment of income trusts through December 31, 2005. The government of Alberta
has expressed similar concerns regarding the impact of energy trusts on tax
revenues, although it has acknowledged the benefits from the contributions made
by trusts to Alberta and the energy industry in general. It is possible that
changes imposed by the Canadian or Alberta governments could have an impact on
the Trust's cost of capital, or our ability to raise capital in Canada or in the
United States.
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.
-22-
HARVEST ENERGY TRUST
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(THOUSANDS OF CANADIAN DOLLARS)
================================================================================
(RESTATED, NOTE 2)
SEPTEMBER 30, 2005 December 31, 2004
- --------------------------------------------------------------------------------------------------
ASSETS
Current assets
Accounts receivable $ 84,621 $ 44,028
Current portion of derivative contracts [NOTE 11] 19,405 8,861
Prepaid expenses and deposits 1,758 3,014
Future income tax 30,795 3,101
- --------------------------------------------------------------------------------------------------
136,579 59,004
Deferred charges [NOTE 11] 15,436 25,540
Long term portion of derivative contracts [NOTE 11] 2,409 3,710
Capital assets [NOTE 3] 1,129,016 918,397
Goodwill 43,832 43,832
- --------------------------------------------------------------------------------------------------
$ 1,327,272 $ 1,050,483
==================================================================================================
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities [NOTE 4] $ 118,285 $ 76,251
Cash distribution payable 17,966 8,358
Current portion of derivative contracts [NOTE 11] 92,500 27,927
Bank debt -- 75,519
- --------------------------------------------------------------------------------------------------
228,751 188,055
Bank debt 34,649 --
Deferred gains [NOTE 11] 843 2,177
Long term portion of derivative contracts [NOTE 11] 9,977 --
Convertible debentures [NOTES 1, 2 AND 10] 60,800 25,750
Senior notes 290,675 300,500
Asset retirement obligation [NOTE 5] 100,511 90,085
Future income tax 36,833 37,772
- --------------------------------------------------------------------------------------------------
763,039 644,339
Non-controlling interest [NOTES 1,2 AND 9] 3,012 6,895
Unitholders' equity
Unitholders' capital [NOTE 7] 703,641 465,524
Equity component of convertible debentures
[NOTES 1 AND 10] 3,620 116
Accumulated deficit (146,040) (66,391)
- --------------------------------------------------------------------------------------------------
561,221 399,249
- --------------------------------------------------------------------------------------------------
$1, 327,272 $ 1,050,483
==================================================================================================
Commitments, contingencies and guarantees [Note 14]
See accompanying notes to these consolidated financial statements.
-24-
HARVEST ENERGY TRUST
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME (UNAUDITED)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT PER TRUST UNIT AMOUNTS)
================================================================================
(RESTATED, NOTE 2) (RESTATED, NOTE 2)
THREE MONTHS Three Months NINE MONTHS Nine Months
ENDED Ended ENDED Ended
SEPTEMBER 30, 2005 September 30, 2004 SEPTEMBER 30, 2005 September 30, 2004
- -------------------------------------------------------------------------------------------------------------------------------
REVENUE
Oil and natural gas sales $ 208,628 $ 102,112 $ 481,672 $ 202,902
Royalty expense (38,974) (17,016) (81,824) (34,046)
- -------------------------------------------------------------------------------------------------------------------------------
169,654 85,096 399,848 168,856
EXPENSES
Operating 32,441 19,538 88,424 47,717
General and administrative 12,971 2,175 25,046 5,255
Interest on short-term debt 1,083 4,010 6,452 6,422
Interest on long-term debt 7,682 2,920 21,460 5,357
Depletion, depreciation and accretion 48,969 28,062 127,944 53,002
Foreign exchange loss (gain) (13,974) 725 (8,607) (565)
Derivative contracts [NOTE 11] 26,130 35,576 137,779 65,707
- -------------------------------------------------------------------------------------------------------------------------------
115,302 93,006 398,498 182,895
- -------------------------------------------------------------------------------------------------------------------------------
Income(loss) before taxes and 54,352 (7,910) 1,350 (14,039)
non-controlling interest
TAXES
Large corporations tax 76 120 831 256
Future income tax expense (recovery) 1,195 (9,810) (28,633) (13,976)
- -------------------------------------------------------------------------------------------------------------------------------
1,271 (9,690) (27,802) (13,720)
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) BEFORE
NON-CONTROLLING INTEREST 53,081 1,780 29,152 (319)
Non-controlling interest [NOTES 1, 2
AND 9] 219 40 (156) 40
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 52,862 1,740 29,308 (359)
Accumulated deficit, beginning of
period,
as previously reported (152,211) (36,269) (65,694) (13,069)
Retroactive changes in accounting
policies - (205) (697) -
- -------------------------------------------------------------------------------------------------------------------------------
Accumulated deficit, beginning of (152,211) (36,474) (66,391) (13,069)
period,
as restated
Distributions (46,691) (18,434) (108,957) (39,740)
- -------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED INCOME, END OF PERIOD $ (146,040) $ (53,168) $ (146,040) $ (53,168)
===============================================================================================================================
Net income (loss) per trust unit, basic
[NOTE 7] $ 1.09 $ 0.06 $ 0.66 $ (0.02)
Net income (loss) per trust unit,
diluted [NOTE 7] $ 1.08 $ 0.06 $ 0.64 $ (0.02)
- -------------------------------------------------------------------------------------------------------------------------------
See accompanying notes to these consolidated financial statements.
-25-
HARVEST ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT PER TRUST UNIT AMOUNTS)
================================================================================
(RESTATED, NOTE 2) (RESTATED, NOTE 2)
THREE MONTHS Three Months Nine Months
ENDED Ended NINE MONTHS ENDED Ended
SEPTEMBER 30, 2005 September 30, 2004 SEPTEMBER 30, 2005 September 30, 2004
- ------------------------------------------------------------------------------------------------------------------------------
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net income(loss) for the period $ 52,862 $ 1,740 $ 29,308 $ (359)
Items not requiring cash
Depletion, depreciation and
accretion 48,969 28,062 127,944 53,002
Unrealized foreign exchange loss
(gain) (13,829) 492 (8,038) 1,256
Amortization of deferred finance
charges 707 686 3,992 2,228
Unrealized loss on derivative
contracts 3,948 19,664 73,524 29,396
Non-cash interest expense 187 15 342 16
Future income tax expense
(recovery) 1,195 (9,810) (28,633) (13,976)
Non-controlling interest 219 40 (156) 40
Non-cash unit right compensation
expense 9,250 378 15,129 769
- ------------------------------------------------------------------------------------------------------------------------------
103,508 41,267 213,412 72,372
Settlement of asset retirement
obligation (1,169) (154) (2,333) (307)
Change in non-cash working capital
[NOTE 12] 29,810 (9,093) (25,867) (12,405)
- ------------------------------------------------------------------------------------------------------------------------------
132,149 32,020 185,212 59,660
FINANCING ACTIVITIES
Trust unit issuance, net of issue
costs 167,595 166,063 167,507 165,932
Issue of equity bridge notes - 5,000 - 30,000
Repayment of equity bridge notes
[NOTES 6 AND 13] - (20,000) - (45,000)
Issuance of convertible debentures
[NOTE 10] 75,000 100,000 75,000 160,000
Issue costs for convertible
debentures (3,223) (4,500) (3,223) (7,166)
Financing costs (1,518) (3,951) (2,052) (3,973)
Net increase (reduction) in bank debt (103,442) 257,037 (40,871) 279,771
Cash distributions (29,286) (11,226) (74,314) (28,728)
Change in non-cash working capital
[NOTE 12] 5,960 2,126 5,647 1,892
- ------------------------------------------------------------------------------------------------------------------------------
111,086 490,549 127,694 552,728
INVESTING ACTIVITIES
Additions to capital assets (31,655) (13,182) (81,032) (31,695)
Property acquisitions (210,631) (513,815) (241,473) (515,942)
Property dispositions 965 - 2,177 -
Corporate acquisition - - - (75,000)
Change in non-cash working capital
[NOTE 12] (1,914) 4,428 7,422 10,249
- ------------------------------------------------------------------------------------------------------------------------------
(243,235) (522,569) (312,906) (612,388)
Increase in cash and short-term
investments - - - -
Cash, beginning of period - - - -
- ------------------------------------------------------------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
- ------------------------------------------------------------------------------------------------------------------------------
Cash interest payments $ 13,041 $ 1,654 $ 17,257 $ 4,375
Cash tax payments $ 1,733 $ 461 $ 2,079 $ 527
Cash distributions declared per trust unit $ 0.95 $ 0.60 $ 2.15 $ 1.80
==============================================================================================================================
See accompanying notes to these consolidated financial statements.
-26-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
1. SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements of Harvest Energy Trust
(the "Trust") have been prepared by management in accordance with Canadian
generally accepted accounting principles ("Canadian GAAP"). The preparation
of financial statements requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingencies, if any, as at the date of the financial
statements and the reported amounts of revenues and expenses during the
period. In the opinion of management, these financial statements have been
prepared within reasonable limits of materiality. Except as noted below,
these interim consolidated financial statements follow the same significant
accounting policies as described and used in the consolidated financial
statements of the Trust for the year ended December 31, 2004 and should be
read in conjunction with that report. Certain comparative figures have been
reclassified to conform to the current period's presentation.
These consolidated financial statements include the accounts of Harvest
Energy Trust, its wholly owned subsidiaries and its proportionate interest
in a partnership with a third party.
a) Convertible debentures
The Trust presents its convertible debentures in their debt and equity
component parts, where applicable, as follows:
(i) The debt component represents the total discounted present
value of the semi-annual interest obligations to be satisfied
by cash and the principal payment due at maturity, using the
rate of interest that would have been applicable to a
non-convertible debt instrument of comparable term and risk at
the date of issue. Typically, this results in a lower
accounting value assigned to the debt component of the
convertible debentures compared to the principal amount due at
maturity. The debt component amount presented on the balance
sheet increases over the term of the relevant debenture to the
full face value of the outstanding debentures. The difference
is reflected as increased interest expense with the result
that adjusted interest expense reflects the effective yield of
the debt component of the convertible debenture.
(ii) The equity component of the convertible debentures is
presented under "Unitholders' Equity" in the consolidated
balance sheet. The equity component represents the value
ascribed to the conversion right granted to the holder. This
amount remains unchanged in "Unitholders' Equity" until
conversion of the debentures into Trust Units by the holders,
at which time a proportionate amount is transferred to
Unitholders' capital.
b) Non-controlling interest
Non-controlling interest represents the exchangeable shares issued by a
subsidiary of the Trust to third parties which are ultimately only
exchangeable for Trust Units. These exchangeable shares were issued as
partial consideration for the acquisition of Storm Energy Ltd. in 2004.
Non-controlling interest on the consolidated balance sheet reflects the
fair value of the exchangeable shares at issuance together with a
portion of the Trust's subsequent accumulated earnings or loss
attributable to the non-controlling interest. Net income or loss is
reduced by the portion of earnings attributable to the non-controlling
interest. As the exchangeable shares are converted to Trust Units, the
non-controlling interest on the consolidated balance sheet is reduced
on a pro-rata basis together with a corresponding increase in
Unitholders' capital.
-27-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
2. CHANGES IN ACCOUNTING POLICY
a) 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 - DISCLOSURE AND PRESENTATION"
("Section 3860"). 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.
CONVERTIBLE DEBENTURES
The convertible debentures may be redeemed at the option of the Trust
on or after a predetermined date, and may, at the option of the Trust,
be redeemed through the issuance of units. The number of units issued
varies depending on the weighted average market price of the units for
the preceding 20 consecutive trading days, five days prior to the
settlement date.
The convertible debentures also have an option that allows the holder
to convert the debentures into a fixed number of units. In accordance
with CICA handbook section 3860, the convertible debentures have been
reclassified from equity to long term debt with a portion, representing
the value of the equity conversion feature, remaining in equity.
EQUITY BRIDGE NOTES
Under the terms of the equity bridge notes, the interest and principal
may have been repaid, at the option of the Trust, with Trust Units. The
number of Trust Units issued would have been dependent on the market
value of the units at the time of issue. As at September 30, 2004, $10
million of equity bridge notes were outstanding and at December 31,
2004 there were no equity bridge notes payable. For the three and nine
month periods ended September 30, 2004 and the year ended December 31,
2004, interest payments were made related to these notes. In accordance
with the amended CICA handbook section 3860, these notes would have
been classified as debt rather than equity. The interest associated
with these notes has been reflected in these consolidated financial
statements as a direct charge to income rather than to equity as it was
previously classified.
b) Exchangeable shares
On January 19, 2005, the CICA issued EIC-151 "EXCHANGEABLE SECURITIES
ISSUED BY SUBSIDIARIES OF INCOME TRUSTS" ("EIC-151") 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. (the "Corporation") are transferable and, in
accordance with EIC-151, have been reclassified to non-controlling
interest on the consolidated balance sheets. In addition, a provision
for non-controlling interest is reflected in the consolidated
statements of income. Prior periods have been retroactively restated to
reflect this presentation.
-28-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
c) Impact of changes in accounting policy
AS REPORTED CHANGE UPON CHANGE UPON AS RESTATED
DECEMBER 31, ADOPTION OF CICA ADOPTION OF DECEMBER 31, 2004
BALANCE SHEET 2004 SECTION 3860 EIC -151
----------------------------------- -------------------- --------------------- -------------------- ---------------------
Deferred charges $ 24,507 $ 1,033 $ - $ 25,540
Convertible debentures - debt - 25,750 - 25,750
Non-controlling interest - - 6,895 6,895
Unitholders' capital 465,131 335 58 465,524
Exchangeable shares 6,728 - (6,728) -
Convertible debentures-equity 24,696 (24,580) - 116
Accumulated deficit (65,694) (472) (225) (66,391)
----------------------------------- -------------------- --------------------- -------------------- ---------------------
INCOME STATEMENT THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Interest on long-term debt - as reported $ - $ -
Add: interest on convertible debentures 2,741 4,974
Add: amortization of deferred financing costs 179 383
-------------------------------------------------------------------------------------------------------------------------
Interest on long-term debt - as restated $ 2,920 $ 5,357
=========================================================================================================================
INCOME STATEMENT THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Interest on short-term debt - as reported $ 3,037 $ 3,919
Add: interest on equity bridge notes 466 658
Add: amortization of deferred financing costs(1) 507 1,845
-------------------------------------------------------------------------------------------------------------------------
Interest on short-term debt - as restated $ 4,010 $ 6,422
=========================================================================================================================
(1) PREVIOUSLY CLASSIFIED AS FINANCE CHARGES
THREE MONTHS ENDED NINE MONTHS ENDED
INCOME STATEMENT SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Non-controlling interest - as reported $ - $ -
Add: non-controlling interest 40 40
-------------------------------------------------------------------------------------------------------------------------
Non-controlling interest - as restated 40 40
-------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Net income - as reported $ 5,166 $ 5,696
Less: amortization of deferred financing costs (179) (383)
Less: interest on equity bridge notes (466) (658)
Less: interest on convertible debentures (2,741) (4,974)
Less: non-controlling interest (40) (40)
-------------------------------------------------------------------------------------------------------------------------
Net income (loss) - as restated $ 1,740 $ (359)
=========================================================================================================================
INCOME (LOSS) PER UNIT THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Basic as reported $ 0.07 $ -
Basic as restated 0.06 (0.02)
Diluted as reported 0.0 -
Diluted as restated 0.06 (0.02)
=========================================================================================================================
-29-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
3. ACQUISITIONS
On August 2, 2005, the Trust completed the acquisition of the Hay River
Properties. The Trust acquired certain oil and natural gas producing
properties for total consideration of approximately $238 million, which was
settled with cash.
This transaction has been accounted for using the purchase price method.
The following summarizes the estimated fair value of the assets acquired
and liabilities assumed at the date of acquisition.
----------------------------------------------------------------------------------------------------------
ALLOCATION OF PURCHASE PRICE: AMOUNT
----------------------------------------------------------------------------------------------------------
Working capital deficit $ (2,644)
Capital assets 244,995
Asset retirement obligation (4,568)
----------------------------------------------------------------------------------------------------------
$ 237,783
==========================================================================================================
CONSIDERATION FOR THE ACQUISITION:
Cash $ 237,783
----------------------------------------------------------------------------------------------------------
The above amounts are estimates made by management based on currently
available information. Amendments may be made to the purchase equation as
the cost estimates and balances are finalized.
4. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
SEPTEMBER 30, 2005 DECEMBER 31, 2004
----------------------------------------------------------------------------------------------------------------------
Trade accounts payable $ 26,889 $ 13,697
Accrued interest 11,537 5,993
Trust unit incentive plans 21,503 9,774
Premium on derivative contracts 2,209 4,500
Accrued closing adjustments on asset
acquisition - 13,546
Other accrued liabilities 55,017 27,139
Large corporations tax payable 1,130 1,602
----------------------------------------------------------------------------------------------------------------------
$ 118,285 $ 76,251
======================================================================================================================
5. ASSET RETIREMENT OBLIGATION
The Trust's asset retirement obligation results from its net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Trust estimates the total
undiscounted amount of its asset retirement obligation is approximately
$369.9 million, the majority of which will be settled between 2015 and
2026. A credit-adjusted risk-free rate of 10 percent was used to calculate
the fair value of the asset retirement obligation on the consolidated
balance sheet.
A reconciliation of the asset retirement obligation is provided below:
THREE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30, 2005 SEPTEMBER 30, 2004
-----------------------------------------------------------------------------------------------------------------------
Balance, beginning of period $ 94,042 $ 50,007
Revision of estimates - -
Liabilities incurred 5,253 45,134
Liabilities settled (1,169) (154)
Accretion expense 2,385 1,213
-----------------------------------------------------------------------------------------------------------------------
Balance, end of period $ 100,511 $ 96,200
=======================================================================================================================
-30-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
NINE MONTHS ENDED NINE MONTHS ENDED YEAR ENDED
SEPTEMBER 30, 2005 SEPTEMBER 30, 2004 DECEMBER 31, 2004
-------------------------------------------------------------------------------------------------------------------------
Balance, beginning of period $ 90,085 $ 42,009 $ 42,009
Revision of estimates 45 - (8,704)
Liabilities incurred 5,688 51,611 53,488
Liabilities settled (2,333) (307) (929)
Accretion expense 7,026 2,887 4,221
-------------------------------------------------------------------------------------------------------------------------
Balance, end of period $ 100,511 $ 96,200 $ 90,085
=========================================================================================================================
6. EQUITY BRIDGE NOTES
No equity bridge notes were outstanding at September 30, 2005.
On June 29, 2004 and July 9, 2004, the Trust drew $25 million and $5
million respectively, under an equity bridge note agreement with a
corporation controlled by a director of the Corporation. On August 11,
2004, the Trust repaid $20 million of this balance with proceeds from
subscription receipts issued [Note 7] and on December 30, 2004, repaid the
remaining balance. Interest in respect of the equity bridge notes accrues
at 10% per annum and is a charge to income.
On January 26 and 29, 2004, the Trust repaid two equity bridge notes
outstanding in the amounts of $7.4 million and $17.6 million, respectively.
During the nine months ended September 30, 2004, the Trust also paid
accrued and outstanding interest in the amount of $1.5 million.
7. UNITHOLDERS' CAPITAL
(a) Authorized
The authorized capital consists of an unlimited number of Trust Units.
(b) Issued
Number of Trust Units Amount
(000s) (restated Note 2)
-----------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2003 17,109 $ 117,407
Issued pursuant to corporate acquisition 2,721 40,183
Conversion of subscription receipts 12,167 175,200
Convertible debenture conversions-9% series 3,521 49,287
Convertible debenture conversions-8% series 5,221 84,226
Equity component of convertible debenture conversions-9% series - 14
Equity component of convertible debenture conversions-8% series - 632
Exchangeable share retraction 152 2,200
Distribution reinvestment plan issuance 752 12,553
Unit appreciation rights exercise 145 721
Issue costs - (16,899)
-----------------------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2004 41,788 $ 465,524
=======================================================================================================================
-31-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
Number of Trust Units Amount
(000s) (restated Note 2)
-----------------------------------------------------------------------------------------------------------------------
Issued 6,508 175,053
Unit appreciation rights exercise 187 6,845
Convertible debenture conversions-9% series 635 8,800
Convertible debenture conversions-8% series 581 9,339
Convertible debenture conversions-6.5% series 586 16,999
Equity component of convertible debenture conversions-9% series - 3
Equity component of convertible debenture conversions-8% series - 70
Equity component of convertible debenture conversions-6.5% series 1,195
Exchangeable share retraction 289 3,727
Distribution reinvestment plan issuance (including premium drip) 519 14,357
Special distribution 465 10,678
Issue costs - (8,949)
-----------------------------------------------------------------------------------------------------------------------
AS AT SEPTEMBER 30, 2005 51,558 $ 703,641
=======================================================================================================================
On February 28, 2005, the Trust declared a special distribution of 2004
income to be made to unitholders' effective as at December 31, 2004. The
special distribution was paid in units, with each unitholder of record on
March 31, 2005 receiving 0.01098 of a Trust Unit per Trust unit held on
that date.
On August 17, 2005, the Trust implemented a premium distribution program.
The premium distribution program enables investors to receive a cash
payment equal to 102% of the regular distribution amount. The impact to the
Trust is the same as the regular DRIP whereby it settles distributions with
units, rather than cash.
(c) Per Trust Unit information
The following table summarizes the Trust Units and net income (loss)
used in calculating income (loss) per Trust Unit:
NET INCOME ADJUSTMENTS:
THREE MONTHS Three Months NINE MONTHS Nine Months
ENDED Ended ENDED Ended
SEPTEMBER 30, 2005 September 30, 2004 SEPTEMBER 30, 2005 September 30, 2004
--------------------------------------------------------------------------------------------------------------------------
Net income (loss), basic 52,862 1,740 29,308 (359)
Non-controlling interest 219 - (156) -
--------------------------------------------------------------------------------------------------------------------------
Net income (loss), diluted(1) 53,081 1,740 29,152 (359)
==========================================================================================================================
-32-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
WEIGHTED AVERAGE TRUST UNIT ADJUSTMENTS:
NUMBER OF UNITS (000S) THREE MONTHS Three Months NINE MONTHS Nine Months
ENDED Ended ENDED Ended
SEPTEMBER 30, 2005 September 30, 2004 SEPTEMBER 30, 2005 September 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Weighted average Trust Units 48,306 29,058 44,612 20,938
outstanding, basic
Effect of exchangeable shares 268 - 301 -
Effect of unit appreciation
rights 791 642 806 -
-------------------------------------------------------------------------------------------------------------------------
Weighted average Trust Units
outstanding, diluted(1) 49,365 29,700 45,719 20,938
=========================================================================================================================
NOTE 1 WEIGHTED AVERAGE TRUST UNITS, DILUTED, DOES NOT INCLUDE THE IMPACT
OF THE CONVERSION OF THE CONVERTIBLE DEBENTURES AS THE IMPACT WOULD
BE ANTI-DILUTIVE. TOTAL UNITS EXCLUDED AMOUNT TO 509 AND 1,409 FOR
THE THREE AND NINE MONTH PERIOD ENDED SEPTEMBER 30, 2005,
RESPECTIVELY (9,001 AND 9,921 - FOR THE THREE MONTHS AND NINE MONTHS
ENDED SEPTEMBER 30, 2004). WEIGHTED AVERAGE TRUST UNITS, DILUTED,
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 DO NOT INCLUDE THE
IMPACT OF THE TRUST UNIT APPRECIATION RIGHTS AS THE IMPACT WOULD BE
ANTI-DILUTIVE. TOTAL UNITS EXCLUDED WERE 571 FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 2004. WEIGHTED AVERAGE TRUST UNITS, DILUTED, FOR
THE THREE MONTH PERIOD ENDED SEPTEMBER 30, 2004 AND THE NINE MONTHS
ENDED SEPTEMBER 30, 2004 EXCLUDES THE IMPACT OF EXCHANGEABLE SHARES
AS THE IMPACT WOULD BE ANTI-DILUTIVE. TOTAL UNITS EXCLUDED WERE 611
AND 265 RESPECTIVELY.
8. TRUST UNIT INCENTIVE PLANS
As at September 30, 2005, a total of 1,538,075 unit appreciation rights
were outstanding under the regular Trust Unit incentive plan at an average
exercise price of $16.70. This represents 3% of the total Trust Units
outstanding.
For the three and nine month periods ended September 30, 2005, the Trust
incurred non-cash compensation costs related to this incentive plan of
$10.8 million and $17.5 million, respectively ($378,000 and $769,000 -
three and nine month periods ended September 30, 2004, respectively). For
the three months ended September 30, 2005, $8.9 million ($378,000 -
September 30, 2004) of this amount was expensed and reflected as general
and administrative costs in the statement of income, and $1.9 million (nil
- September 30, 2004) of costs associated with personnel whose compensation
is reflected in capital asset costs was capitalized. For the nine months
ended September 30, 2005 $14.6 million ($769,000 - September 30, 2004) was
expensed and $2.9 million (nil - September 30, 2004) was capitalized.
-33-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
The following summarizes the Trust Units reserved for issuance under the
Trust Unit incentive plan:
NINE MONTHS ENDED Year ended
SEPTEMBER 30, 2005 December 31, 2004
-------------------------------------------------------------------------------------------------------------------------
Number of Unit
NUMBER OF UNIT WEIGHTED AVERAGE Appreciation Weighted Average
APPRECIATION RIGHTS EXERCISE PRICE Rights Exercise Price
-------------------------------------------------------------------------------------------------------------------------
Outstanding, beginning of period 1,117,725 $ 11.92 1,065,150 $ 9.04
Granted 744,725 26.18 445,600 16.47
Exercised (253,975) 9.14 (253,750) 8.30
Cancelled (70,400) 18.84 (139,275) 10.91
-------------------------------------------------------------------------------------------------------------------------
Outstanding before exercise price 1,538,075 18.86 1,117,725 11.92
reductions
Exercise price reductions - (2.16) - (1.83)
-------------------------------------------------------------------------------------------------------------------------
Outstanding, end of period 1,538,075 $ 16.70 1,117,725 $ 10.09
=========================================================================================================================
Exercisable before exercise price 208,300 $ 10.32 206,688 $ 8.89
reductions
Exercise price reductions - (3.72) - (2.64)
-------------------------------------------------------------------------------------------------------------------------
Exercisable, end of period 208,300 $ 6.60 206,688 $ 6.25
=========================================================================================================================
The following table summarizes information about unit appreciation rights
outstanding at September 30, 2005.
NUMBER EXERCISE NUMBER EXERCISE
EXERCISE PRICE EXERCISE PRICE OUTSTANDING AT PRICE NET OF REMAINING EXERCISABLE AT PRICE NET OF
BEFORE PRICE NET OF PRICE SEPTEMBER 30, PRICE CONTRACTUAL SEPTEMBER 30, PRICE
REDUCTIONS REDUCTIONS 2005 REDUCTIONS(a) LIFE (YEARS)(a) 2005 REDUCTIONS(a)
---------------------------------------------------------------------------------------------------------------------------
$8.00 - 10.21 $3.75 - $5.96 330,625 $ 3.88 2.2 124,375 $ 3.88
$10.30 - $13.15 $6.55 - $10.15 169,250 8.79 3.0 50,625 8.15
$13.35 - $17.95 $10.54 -$15.78 216,125 12.98 3.7 21,550 12.60
$18.55 - $25.68 $16.72 - $24.45 617,575 22.56 4.4 11,750 17.62
$27.49 - $36.92 $26.93 - $36.92 204,500 30.20 4.8 - n/a
===========================================================================================================================
$8.00 - $36.92 $3.75 - $36.92 1,538,075 $ 16.70 3.7 208,300 $ 6.60
===========================================================================================================================
(a) BASED ON WEIGHTED AVERAGE UNIT APPRECIATION RIGHTS OUTSTANDING
When the Trust adopted the fair value method of accounting for its Trust
Unit incentive plan on January 1, 2003, it was required to calculate the
pro forma impact of having adopted that method from the date all rights
were initially granted.
For purposes of those calculations the fair value of each Trust Unit right
has been estimated on the grant date using the following:
September 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Expected volatility 23.3%
Risk free interest rate 4.0%
Expected life of the trust unit rights 4 years
Estimated annual distributions per unit(a) $2.40
=========================================================================================================================
(a) BASED ON THE ANNUAL DISTRIBUTION RATE AT THE TIME THE ASSUMPTIONS WERE
MADE.
-34-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
As at September 30, 2004 for the purposes of pro forma disclosures, the
expense related to all of the Trust Unit rights issued prior to December
31, 2002 is reflected in pro forma net income as shown below:
(RESTATED NOTE 2) (RESTATED NOTE 2)
Three Months Ended Nine Months Ended
September 30, 2004 September 30, 2004
-------------------------------------------------------------------------------------------------------------------------
Net income (loss) As reported $ 1,740 $ (359)
Pro forma 1,357 (1,507)
Income (loss) per unit - basic As reported $ 0.06 $ (0.02)
Pro forma $ 0.05 $ (0.07)
Income (loss) per unit - diluted As reported $ 0.06 $ (0.02)
Pro forma $ 0.05 $ (0.07)
=========================================================================================================================
UNIT AWARD INCENTIVE PLAN
At September 30, 2005, 35,024 units were outstanding under the Unit Award
Incentive Plan. The Trust recorded compensation expense of $248,000 and
$487,000 for the three and nine month periods ended September 30, 2005,
respectively (nil - three and nine month periods ended September 30, 2004)
related to this plan. For the three and nine month periods ended September
30, 2005, $77,100 (nil - three and nine month periods September 30, 2004)
was capitalized relating to the unit award incentive plan.
-----------------------------------------------------------------------------------------------------------------------
NINE MONTHS ENDED Year ended
NUMBER SEPTEMBER 30, 2005 December 31, 2004
-----------------------------------------------------------------------------------------------------------------------
Outstanding, beginning of period 10,662 -
Granted 23,466 15,000
Adjusted for distributions 896 662
Cancelled - (5,000)
-----------------------------------------------------------------------------------------------------------------------
Outstanding, end of period 35,024 10,662
=======================================================================================================================
9. EXCHANGEABLE SHARES
(a) Authorized
Harvest Operations Corp., a wholly-owned subsidiary of the Trust, is
authorized to issue an unlimited number of exchangeable shares without
nominal or par value.
-35-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
(b) Issued
EXCHANGEABLE SHARES, SERIES 1 NINE MONTHS ENDED Year Ended
(NUMBER) SEPTEMBER 30, 2005 December 31, 2004
----------------------------------------------------------------------------------------------------------------------
Outstanding, beginning of period 455,547 -
Issued pursuant to corporate acquisition - 600,587
Shareholder retractions (263,865) (145,040)
----------------------------------------------------------------------------------------------------------------------
Outstanding, end of period 191,682 455,547
----------------------------------------------------------------------------------------------------------------------
Exchange ratio at end of period 1:1.14463 1:1.06466
======================================================================================================================
(c) Non-controlling interest
The Trust retroactively applied EIC-151 "Exchangeable Securities Issued
by a Subsidiary of an Income Trust" at January 1, 2005. The
non-controlling interest on the consolidated balance sheet consists of
the fair value of the exchangeable shares upon issuance plus the
accumulated earnings attributable to such non-controlling interest less
conversions to date. The non-controlling interest on the statement of
income represents the share of net income or loss attributable to the
non-controlling interest based on the Trust Units issuable for
exchangeable shares in proportion to total Trust Units issued and
issuable at each period end.
The following is a summary of the non-controlling interest:
(restated, Note 2)
SEPTEMBER 30, 2005 December 31, 2004
-----------------------------------------------------------------------------------------------------------------------
Non-controlling interest, beginning of period $ 6,895 $ -
Issue of exchangeable shares - 8,870
Exchanged for Trust Units (3,727) (2,200)
Current period (loss) income attributable to non-controlling interest (156) 225
-----------------------------------------------------------------------------------------------------------------------
NON-CONTROLLING INTEREST, END OF PERIOD 3,012 6,895
-----------------------------------------------------------------------------------------------------------------------
ACCUMULATED (LOSS) INCOME ATTRIBUTABLE TO NON-CONTROLLING INTEREST 69 225
=======================================================================================================================
10. CONVERTIBLE DEBENTURES
The following is a summary of certain terms of the Trust's outstanding
series of convertible debentures:
INTEREST ORIGINAL EARLIEST REDEMPTION
ISSUE DATE RATE FACE VALUE CONVERSION PRICE MATURITY DATE
-----------------------------------------------------------------------------------------------------------------------
January 29, 2004 9% $60 million $13.85 per trust unit(a) May 31, 2009 May 31, 2007
August 10, 2004 8% $100 million $16.07 per trust unit(a) September 30, 2009 September 30, 2007
August 2, 2005 6.5% $75 million $31.00 per trust unit December 31, 2010 December 31, 2008
=======================================================================================================================
(a) THE CONVERSION PRICE FOR THE 9% DEBENTURES AND THE 8% DEBENTURES CHANGED FROM $14.00 AND $16.25 PER UNIT
RESPECTIVELY, AS A RESULT OF THE SPECIAL DISTRIBUTION DESCRIBED IN NOTE 7.
On August 2, 2005 the Trust issued $75 million of 6.5% convertible
unsecured subordinated debentures due December 31, 2010. Interest on the
debentures is payable semi-annually in arrears in equal installments on
June 30 and December 31 in each year, commencing December 31, 2005. The
debentures are convertible into fully paid and non-assessable Trust Units
at the option of the holder at any time prior to the close of business on
the earlier of December 31, 2010 and the business day immediately preceding
the date specified by the Trust for redemption of the debentures, at a
conversion
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
price of $31.00 per Trust Unit plus a cash payment for accrued interest and
in lieu of any fractional Trust Units resulting on the conversion. The
debentures may be redeemed by the Trust at its option in whole or in part
subsequent to December 31, 2008, at a price equal to $1,050 per debenture
between January 1, 2009 and December 31, 2009 and at $1,025 per debenture
between January 1, 2010 and December 31, 2010. Any redemption will include
accrued and unpaid interest at such time. Under both redemption options,
the Trust may elect to pay both the principal and accrued interest in the
form of Trust Units at a price equal to 95% of the weighted average trading
price for the preceding 20 consecutive trading days, 5 days prior to
settlement date.
As at January 1, 2005, the Trust adopted the amended CICA Handbook Section
3860 relating to the classification of liabilities that may be settled with
a variable number of equity instruments such as Trust Units. The adoption
has resulted in the convertible debentures being classified as debt rather
than equity, with a portion remaining in equity representing the value of
the conversion feature. As the debentures are converted, a portion of the
debt and equity amounts are transferred to Unitholders' capital. The debt
balance associated with the convertible debentures accretes over time to
the amount owing on maturity and such increases in the debt balance are
reflected as non-cash interest expense in the statement of income.
The following table summarizes the issuance and subsequent conversions of
the convertible debentures:
9% SERIES 8% SERIES 6.5% SERIES TOTAL
----------------- ------------------- ------------------- -------
NUMBER AMOUNT NUMBER AMOUNT NUMBER AMOUNT AMOUNT
-------------------------------------------------------------------------------------------------------------------
January 29, 2004
issuance 60,000 $ 60,000 - $ - $ - - $ 60,000
August 10, 2004
issuance - - 100,000 100,000 - - 100,000
Portion allocated
to equity - (17) - (745) - - (762)
Accretion of non-cash
interest expense - 2 - 23 - - 25
Converted into
Trust Units (49,300) (49,287) (84,841) (84,226) - - (133,513)
-------------------------------------------------------------------------------------------------------------------
As at December 31, 2004 10,700 $ 10,698 15,159 $ 15,052 - $ - $ 25,750
-------------------------------------------------------------------------------------------------------------------
August 2, 2005 issuance 75,000 75,000 75,000
Portion allocated to
equity - - - - - (4,932) (4,932)
Accretion of non-cash
interest expense - - - 9 - 111 120
Converted into
Trust Units (8,802) (8,800) (9,401) (9,339) (18,173) (16,999) (35,138)
-------------------------------------------------------------------------------------------------------------------
As at September 30, 2005 1,898 $ 1,898 5,758 $ 5,722 56,827 $53,180 $ 60,800
===================================================================================================================
-37-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
The following table summarizes the reclassification of the equity component
of convertible debentures to Unitholders' capital:
9% SERIES 8% SERIES 6.5% SERIES
EQUITY VALUE EQUITY VALUE EQUITY VALUE TOTAL
----------------------------------------------------------------------------------------------------------------------------
January 29, 2004 issuance, net $ 17 $ - $ - $ 17
August 10, 2004 issuance, net - 745 - 745
Converted into Trust Units (14) (632) - (646)
----------------------------------------------------------------------------------------------------------------------------
As at December 31, 2004 $ 3 $ 113 $ - $ 116
August 2, 2005 issuance, net - - 4,720 4,720
Converted into Trust Units, net (3) (70) (1,143) (1,216)
----------------------------------------------------------------------------------------------------------------------------
As at September 30, 2005 $ - $ 43 $ 3,577 $ 3,620
============================================================================================================================
11. FINANCIAL INSTRUMENTS
The Trust is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the normal
course of operations.
(a) INTEREST RATE RISK
The Trust is exposed to interest rate risk on its bank debt; the
Trust's other debt has fixed interest rates.
(b) CREDIT RISK
Substantially all accounts receivable are due from customers in the oil
and natural gas industry and are subject to normal industry credit
risks. Concentration of credit risk is mitigated by having a broad
customer base, including a number of companies engaged in joint
operations with the Trust. The Trust periodically assesses the
financial strength of its partners and customers, including parties
involved in marketing or other commodity arrangements. The carrying
value of accounts receivable reflects management's assessment of the
associated credit risks.
(c) FOREIGN EXCHANGE RATE RISK
The Trust is exposed to the risk of changes in the Canadian/US dollar
exchange rate on sales of commodities that are denominated in US
dollars or directly influenced by US dollar benchmark prices. In
addition, the Trust's senior notes are denominated in US dollars
(US$250 million). These notes act as an economic hedge to help offset
the impact of exchange rate movements on commodity sales during the
year. As at September 30, 2005 the full balance of the notes is still
outstanding and is not repayable until October 15, 2011. Interest is
payable semi-annually on the notes in US dollars.
(d) COMMODITY RISK
The Trust is exposed to fluctuations in prices for oil and natural gas
and the differentials between prices received for light oil versus
those received for medium and heavy gravity oil. The Trust uses
derivative financial instruments to manage its commodity price
exposure. Under the terms of certain of the derivative instruments, the
Trust is required to provide security if the contracts favour the
counterparty. The Trust is also exposed to counterparty risk on
balances due if the contracts favour the Trust. This risk is managed by
diversifying the Trust's derivative portfolio among a number of
counterparties and by dealing with large investment grade institutions.
-38-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
The following is a summary of the oil sales price derivative contracts
as at September 30, 2005.
OIL PRICE SWAP CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
----------------------------------------------------------------------------------------------------------------------
Daily Quantity Term Price per Barrel (U.S.$) Mark to Market Gain (Loss)
-------------- ---- ------------------------ --------------------------
500 bbl/d October - December 2005 $24.00 $ (2,243)
PARTICIPATING SWAP CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
----------------------------------------------------------------------------------------------------------------------
8,750 bbl/d January - December 2006 $38.16 (b) $ (50,466)
5,000 bbl/d July - December 2006 $45.17(b) (9,992)
5,000 bbl/d January 2006 - June 2007 $49.03(c) (7,757)
OIL PRICE COLLAR CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
----------------------------------------------------------------------------------------------------------------------
1,500 bbl/d October - December 2005 $28.17 - 32.10 ($22.33)(a) $ (5,431)
2,000 bbl/d October - December 2005 $28.00 - 42.00 (5,122)
======================================================================================================================
(a) THE TRUST HAS SOLD PUT OPTIONS AT THE AVERAGE PRICE DENOTED IN
PARENTHESIS, FOR THE SAME VOLUMES AS THE ASSOCIATED COMMODITY
CONTRACTS. THE COUNTERPARTY MAY EXERCISE THESE OPTIONS IF THE
RESPECTIVE INDEX FALLS BELOW THE SPECIFIED PRICE ON A MONTHLY
SETTLEMENT BASIS.
(b) THIS PRICE IS A FLOOR. THE TRUST REALIZES THIS PRICE PLUS 50% OF THE
DIFFERENCE BETWEEN SPOT PRICE AND THIS PRICE.
(c) THIS PRICE IS A FLOOR. THE TRUST REALIZES THIS PRICE PLUS 75% OF THE
DIFFERENCE BETWEEN SPOT PRICE AND THIS PRICE.
OIL PRICE INDEXED PUT CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
----------------------------------------------------------------------------------------------------------------------
Daily Quantity Term Type Price per Bbl (U.S.$) Mark to Market Gain (Loss)
----------------------------------------------------------------------------------------------------------------------
4,000 bbl/d October - December 2005 Long Put $30.00 $ 44
1,972 bbl/d October - December 2005 Short Call $30.00 (7,621)
1,972 bbl/d October - December 2005 Long Call $40.00 5,528
7,000 bbl/d October - December 2005 Long Put $35.00(2) $ (244)
2,380 bbl/d October - December 2005 Short Call $35.00 (7,935)
2,380 bbl/d October - December 2005 Long Call $45.00 5,415
7,500 bbl/d October - December 2005 Long Put $40.00 $ 3
3,675 bbl/d October - December 2005 Short Call $40.00 (10,302)
3,675 bbl/d October - December 2005 Long Call $50.00 6,449
7,500 bbl/d January - June 2006 Long Put $34.00 $ 678
3,750 bbl/d January - June 2006 Short Call $34.00 (25,526)
3,750 bbl/d January - June 2006 Long Call $44.00 18,208
5,000 bbl/d January - December 2006 Long Put $55.00 $ 6,532
2,500 bbl/d January - December 2006 Short Call $55.00 (15,353)
2,500 bbl/d January - December 2006 Long Call $65.00 8,618
2,500 bbl/d January - December 2006 Short Call $70.00 (6,271)
2,500 bbl/d January - December 2006 Long Call $83.00 2,802
5,000 bbl/d January - December 2007 Long Put $50.00 $ 7,676
2,500 bbl/d January - December 2007 Short Call $50.00 (18,350)
2,500 bbl/d January - December 2007 Long Call $60.00 11,912
2,500 bbl/d January - December 2007 Short Call $70.00 (7,381)
2,500 bbl/d January - December 2007 Long Call $83.00 3,923
----------------------------------------------------------------------------------------------------------------------
(1) EACH GROUP OF A LONG PUT, SHORT CALL AND A LONG CALL REFLECT AN
"INDEXED PUT OPTION". THESE SERIES OF PUTS AND CALLS SERVE TO FIX A
FLOOR PRICE WHILE RETAINING UPWARD PRICE EXPOSURE ON A PORTION OF PRICE
MOVEMENTS ABOVE THE FLOOR PRICE.
(2) HARVEST PAYS A PREMIUM OF U.S.$1.00 PER BBL ON 7,000 BBL/D FOR EACH
MONTH IN WHICH WTI EXCEEDS U.S.$50.00/BBL.
-39-
OIL PRICE DIFFERENTIAL SWAP CONTRACT BASED ON BOW RIVER CRUDE BLEND
-----------------------------------------------------------------------------------------------------------------------
Daily Quantity Term Percent of WTI (%) Mark to Market Gain
-----------------------------------------------------------------------------------------------------------------------
4,000 bbl/d October 2005 - June 2006 29.9 $ 2,129
5,000 bbl/d October 2005 - December 31, 2006 27.5 $ 4,325
4,000 bbl/d July - December 2006 29.58 $ 549
OIL PRICE DIFFERENTIAL SWAP CONTRACT BASED ON WAINWRIGHT CRUDE BLEND
-----------------------------------------------------------------------------------------------------------------------
1,000 bbl/d October 2005 - June 2006 29.9 $ 1,709
1,000 bbl/d July - December 2006 29.58 $ 841
The following is a summary of electricity price physical and financial swap
contracts entered into by Harvest to fix the cost of future electricity
usage as at September 30, 2005.
SWAP CONTRACTS BASED ON ELECTRICITY PRICES
-------------------------------------------------------------------------------------------------------------------------
Weighted Average Term Average Price Mark to Market Gain
Quantity per Megawatt
-------------------------------------------------------------------------------------------------------------------------
25 MWH October - December 2005 Cdn $48.00 $ 1,998
35 MWH January - December 2006 Cdn $48.58 6,394
25 MWH January - December 2007 Cdn $55.00 1,752
25 MWH January - December 2008 Cdn $55.00 657
SWAP CONTRACTS BASED ON ELECTRICITY HEAT RATE
-------------------------------------------------------------------------------------------------------------------------
Quantity Term Heat Rate Mark to Market Loss
-------------------------------------------------------------------------------------------------------------------------
5 MW October - December 2005 8.40 GJ/MWh $ (271)
NATURAL GAS CONTRACTS
-------------------------------------------------------------------------------------------------------------------------
Quantity Term Price per GJ Mark to Market Gain
-------------------------------------------------------------------------------------------------------------------------
1,008 GJ/day October - December 2005 6.05/GJ 448
The following is a put option related to the US/Canadian dollar exchange
rate intended to mitigate the impact of a strengthening Canadian dollar on
realized commodity prices.
FOREIGN CURRENCY CONTRACT
-------------------------------------------------------------------------------------------------------------------------
Monthly Contract Amount Term Type Contract Rate Mark to Market Gain
-------------------------------------------------------------------------------------------------------------------------
U.S. $8.33 million July - December 2005 Long Put 1.20 Cdn / US $ 1,012
=========================================================================================================================
At September 30, 2005, the net unrealized loss position reflected on the
balance sheet for all the derivative contracts outstanding at that date was
approximately $80.7 million.
For the three and nine month periods ended September 30, 2005, the total
unrealized loss recognized in the statement of income, including
amortization of deferred charges and gains, was $3.9 million ($19.7 million
- three months ended September 30, 2004) and $73.5 million ($29.4 million -
three months ended September 30, 2004), respectively. The realized gains
and losses on all derivative contracts are included in the period in which
they are incurred. These amounts are reflected in gains and losses on
derivative contracts on the statement of income.
-40-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
At October 1, 2004, the Trust discontinued hedge accounting for all of its
derivative financial instruments. For those contracts where hedge
accounting had previously been applied, a deferred charge or gain was
recorded equal to the fair value of the contracts at the time hedge
accounting was discontinued with a corresponding amount recorded in the
derivative contracts balance. The deferred charge or gain is subsequently
recognized in income in the period in which the underlying transaction is
recognized.
For the three and nine month periods ended September 30, 2005, $1.2 million
and $9.6 million, respectively (nil - three months ended September 30, 2004
and $5.5 million-nine months ended September 30, 2004) of the deferred
charge and $444,000 and $1.3 million, respectively (nil - three months
ended September 30, 2004 and nil - nine months ended September 30, 2004) of
the deferred gain has been amortized and recorded in gains and losses on
derivative contracts in the statement of income. At September 30, 2005,
$1.2 million ($10.8 million - December 31, 2004) and $843,000 ($2.2 million
- December 31, 2004) has been recorded as a deferred charge and a deferred
gain, respectively on the balance sheet relating to derivatives.
DEFERRED CHARGES - ASSET NINE MONTHS ENDED Year Ended
SEPTEMBER 30, 2005 December 31, 2004
----------------------------------------------------------------------------------------------------------------------
Balance, beginning of period $ 25,540 $ 1,989
Deferred charge related to derivative contracts recorded upon
adoption of Accounting Guideline 13 - 5,490
Deferred charge related to derivative contracts
recorded upon discontinuing hedge accounting - 20,215
Discount on senior notes - 2,075
Financing costs incurred 5,063 20,971
Financing costs transferred to unit issue costs on conversion
of debentures (1,402) (5,721)
Amortization of deferred charges related to derivative
contracts(1) (9,551) (14,946)
Accretion of senior notes discount(2) (222) (75)
Amortization of deferred financing costs(2) (3,992) (4,458)
----------------------------------------------------------------------------------------------------------------------
Balance, end of period $ 15,436 $ 25,540
======================================================================================================================
AS AT As at
COMPRISED OF: SEPTEMBER 30, 2005 December 31, 2004
Derivative asset $ 1,208 $ 10,759
Financing costs 12,450 12,781
Discount on senior notes 1,778 2,000
----------------------------------------------------------------------------------------------------------------------
$ 15,436 $ 25,540
======================================================================================================================
-41-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
NINE MONTHS ENDED Year Ended
DEFERRED GAINS - LIABILITY SEPTEMBER 30, 2005 December 31, 2004
----------------------------------------------------------------------------------------------------------------------
Balance, beginning of period $ 2,177 $ -
Deferred gains related to derivative contracts
recorded upon discontinuing hedge accounting - 2,527
Amortization of deferred gains related to derivative (350)
contracts(1) (1,334)
----------------------------------------------------------------------------------------------------------------------
Balance, end of period $ 843 $ 2,177
======================================================================================================================
(1) RECORDED WITHIN GAINS AND LOSSES ON DERIVATIVE CONTRACTS.
(2) RECORDED WITHIN INTEREST EXPENSE ON LONG-TERM DEBT AND SHORT-TERM
DEBT.
12. CHANGE IN NON-CASH WORKING CAPITAL
THREE MONTHS Three Months NINE MONTHS Nine Months
ENDED Ended ENDED Ended
SEPTEMBER 30, September 30, SEPTEMBER 30, September 30,
2005 2004 2005 2004
-------------------------------------------------------------------------------------------------------------------------
Changes in non-cash working capital items:
Accounts receivable $ (18,292) $ (23,167) $ (40,593) $ (36,856)
Current portion of derivative contracts assets (9,596) - (10,544) -
Prepaid expenses and deposits 44,171 (620) 1,256 (3,141)
Future income tax (20,832) - (27,694) -
Accounts payable and accrued liabilities 16,613 21,740 42,034 47,658
Cash distribution payable 9,212 3,325 9,608 3,949
Current portion of derivative contracts
liabilities 54,209 13,601 64,573 23,333
-------------------------------------------------------------------------------------------------------------------------
$ 75,485 $ 14,879 $ 38,640 $ 34,943
-------------------------------------------------------------------------------------------------------------------------
Changes relating to operating activities $ 29,810 $ (9,093) $ (25,867) $ (12,405)
Changes relating to financing activities 5,960 2,126 5,647 1,892
Changes relating to investing activities (1,914) 4,428 7,422 10,249
Add: Non-cash changes 41,629 17,418 51,438 35,207
-------------------------------------------------------------------------------------------------------------------------
$ 75,485 $ 14,879 $ 38,640 $ 34,943
=========================================================================================================================
13. RELATED PARTY TRANSACTIONS
During the nine month period ended September 30, 2004, a director and a
corporation controlled by a director of Harvest Operations Corp. issued an
additional $30 million of equity bridge notes. The Trust repaid $45 million
of equity bridge notes and paid $1.5 million of accrued interest during the
nine month period ended September 30, 2004. See Note 6.
A corporation controlled by a director of Harvest Operations Corp. sublets
office space from and is provided administrative services by the Trust on a
cost recovery basis.
14. COMMITMENTS, CONTINGENCIES AND GUARANTEES
From time to time, the Trust is involved in litigation or has claims
brought against it in the normal course of business operations. Management
of the Trust is not currently aware of any claims or actions that would
materially affect the Trust's reported financial position or results from
operations.
In the normal course of operations, management may also enter into certain
types of contracts that require the Trust to indemnify parties against
possible third party claims, particularly when these contracts relate to
purchase and sale agreements. The terms of such contracts vary and
generally a maximum is not explicitly stated; as such the overall
-42-
HARVEST ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED SEPTEMBER 30, 2005
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT WHERE NOTED)
================================================================================
maximum amount of the obligations cannot be reasonably estimated.
Management does not believe payments, if any, related to such contracts
would have a material affect on the Trust's reported financial position or
results from operations.
The Trust has letters of credit outstanding in the amount of approximately
$5.1 million related to electricity infrastructure usage. These letters are
provided pursuant to the secured senior credit facility. These letters
expire throughout 2005, and are expected to be renewed as required.
The following is a summary of the Trust's contractual obligations and
commitments as at September 30, 2005:
REMAINING PAYMENTS DUE BY PERIOD
------------------------------------------------------------------------------------
2005 2006 - 2007 2008 - 2009 THEREAFTER TOTAL
---------------- ---------------- ---------------- ---------------- ----------------
Debt repayments (1) $ - $ 34,649 $ - $ 290,675 $ 325,324
Operating leases 372 2,869 2,869 956 7,066
-----------------------------------------------------------------------------------------------------------------------
Total contractual obligations $ 372 $ 37,518 $ 2,869 $ 291,631 $ 332,390
=======================================================================================================================
(1) INCLUDES LONG-TERM AND SHORT-TERM DEBT. ASSUMES THAT THE OUTSTANDING
CONVERTIBLE DEBENTURES ARE EITHER EXCHANGED AT THE HOLDERS' OPTION FOR
UNITS OR ARE REDEEMED FOR UNITS AT THE TRUST'S OPTION. THE INITIAL
MATURITY OF THE TRUST'S BANK DEBT HAS BEEN EXTENDED TO JULY 31, 2006
WITH A ONE YEAR TERM-OUT OPTION AVAILABLE TO THE TRUST.
-43-