1 EXHIBIT 99.3
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MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's discussion and analysis ("MD&A") of the financial condition and
results of operations of Harvest Energy Trust should be read in conjunction with
our audited consolidated financial statements and accompanying notes for the
year ended December 31, 2004. In this MD&A, reference to "Harvest", "we", "us"
or "our" refers to Harvest Energy Trust and all of its controlled entities on a
consolidated basis. The information and opinions concerning our future outlook
are based on information available at March 24, 2005.
All references are to Canadian dollars unless otherwise indicated. Tabular
amounts are in thousands of dollars unless otherwise stated. Natural gas volumes
are converted to barrels of oil equivalent ("BOE") using the ratio of six
thousand cubic feet ("6 mcf") to one (1) barrel of oil ("bbl"). BOEs 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.
CERTAIN FINANCIAL REPORTING MEASURES
We use certain financial reporting measures that are commonly used as benchmarks
within the oil and natural gas industry. These measures include: "Cash Flow from
Operations", "Net Debt", "Payout Ratio", "Net Operating Income" and "Operating
Netbacks". These measures are not defined under Canadian generally accepted
accounting principles ("GAAP") and should not be considered in isolation or as
an alternative to conventional GAAP measures. Certain of these measures are not
necessarily comparable to a similarly titled measure of another company or
trust. When these measures are used, they are defined as "non-GAAP" and should
be given careful consideration by the reader.
Specifically, management uses Cash Flow from Operations as cash flow from
operating activities before changes in non-cash working capital and settlement
of asset retirement obligations. Under GAAP, this measure is defined as funds
flow, and the accepted definition of cash flow from operating activities is net
of changes in non-cash working capital and settlement of asset retirement
obligations. Cash Flow from Operations as presented is not intended to represent
an alternative to net earnings, cash flow from operating activities or other
measures of financial performance calculated in accordance with Canadian GAAP.
Management believes our usage of Cash Flow from Operations is a better indicator
of our ability to generate cash flows from future operations. Net Debt, Payout
Ratio, Net Operating Income, and Operating Netbacks are additional non-GAAP
measures used extensively in the Canadian energy trust sector for comparative
purposes. Net Debt includes total debt outstanding, any working capital deficit,
the face value of convertible debentures outstanding, and equity bridge notes.
(Note: for accounting purposes in 2004, convertible debentures and equity bridge
notes were classified as equity and not debt. In 2005, accounting rule changes
will result in these amounts being presented as debt.). Payout Ratio is the
ratio of distributions to total Cash Flow from Operations. Net Operating Income
is net revenue (gross revenue less royalties) less operating expenses. Operating
Netbacks are always reported on a per BOE basis, and include gross revenue,
royalties and operating expenses, net of any realized gains and losses on
related derivative contracts.
FORWARD-LOOKING INFORMATION
This MD&A contains forward-looking statements. These statements are subject to
certain risks and uncertainties that could cause actual results to differ
materially from those included in the forward-looking statements. The words
"believe," "expect," "intend," "estimate" or "anticipate" and similar
expressions, as well as future or conditional verbs such as "will," "should,"
"would," and "could" often identify forward-looking statements. Specific forward
looking statements contained in this MD&A include, among others, statements
regarding our:
o expected financial performance in future periods;
o expected increases in revenue attributable to its development and production
activities;
o estimated capital expenditures for fiscal 2005 and subsequent periods;
o competitive advantages and ability to compete successfully;
o intention to continue adding value through drilling and exploitation
activities;
o emphasis on having a low cost structure;
o intention to retain a portion of our cash flows after distributions to repay
indebtedness and invest in further development of our properties;
o reserve estimates and estimates of the present value of our future net cash
flows;
o methods of raising capital for exploitation and development of reserves;
o factors upon which we will decide whether or not to undertake a development or
exploitation project;
o plans to make acquisitions and expected synergies from acquisitions made;
o expectations regarding the development and production potential of our
properties; and
o treatment under government regulatory regimes.
With respect to forward-looking statements contained in this MD&A, we have made
assumptions regarding, among other things:
o future oil and natural gas prices and differentials between light, medium and
heavy oil prices;
2 EXHIBIT 99.3
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o the cost of expanding our property holdings;
o our ability to obtain equipment in a timely manner to carry out development
activities;
o our ability to market oil and natural gas successfully to current and new
customers;
o the impact of increasing competition;
o our ability to obtain financing on acceptable terms; and
o our ability to add production and reserves through our development and
exploitation activities.
Some of the risks that could affect our future results and could cause results
to differ materially from those expressed in our forward-looking statements
include:
o the volatility of oil and natural gas prices, including the differential
between the price of light, medium and heavy oil;
o the uncertainty of estimates of oil and natural gas reserves;
o the impact of competition;
o difficulties encountered during the drilling for and production of oil and
natural gas;
o difficulties encountered in delivering oil and natural gas to commercial
markets;
o foreign currency fluctuations;
o the uncertainty of our ability to attract capital;
o changes in, or the introduction of, new government regulations relating to the
oil and natural gas business;
o costs associated with developing and producing oil and natural gas;
o compliance with environmental regulations;
o liabilities stemming from accidental damage to the environment;
o loss of the services of any of our senior management or directors; and
o adverse changes in the economy generally.
The information contained in this MD&A, including the information provided under
the heading "Operational and Other Business Risks" identifies additional factors
that could affect our operating results and performance. We urge you to
carefully consider those factors. Our forward-looking statements are expressly
qualified in their entirety by this cautionary statement. Our forward looking
statements are only made as of the date of this MD&A and we undertake no
obligation to publicly update these forward-looking statements to reflect new
information, subsequent events or otherwise.
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 have operations in four core
areas: North Central Alberta, East Central Alberta, Southern Alberta and
Southeast Saskatchewan.
Since inception, we have followed a strategy designed for sustainability. We
retain significant cash flows for reinvestment, and focus on realizing per Unit
accretion in reserves, production, cash flow and net asset value when reviewing
potential acquisitions and capital projects.
2004 FINANCIAL AND OPERATING HIGHLIGHTS
The table below provides a summary of our financial and operating results for
both the three and twelve month periods ended December 31, 2004 and 2003.
Readers should note that the fourth quarter of 2004 was the first full operating
quarter that included production from both of the significant acquisitions
completed in 2004. Detailed commentary on individual items within this table is
provided elsewhere in this MD&A.
3 EXHIBIT 99.3
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THREE MONTHS ENDED DECEMBER 31 TWELVE MONTHS ENDED DECEMBER 31
FINANCIAL ($000S EXCEPT WHERE NOTED) 2004 2003 % Change 2004 2003 % Change
- ---------------------------------------------------------------------------------------------------------------------------------
(RESTATED)(6) (RESTATED)(6)
Revenue, net of royalties $ 107,446 $ 33,575 220% $ 277,095 $ 102,939 169%
Cash flow from operations(5) 53,545 13,699 291% 130,003 46,492 180%
Per Trust Unit, basic(5) 1.31 0.85 54% 5.13 3.69 39%
Per Trust Unit, diluted(5) 1.27 0.82 55% 4.91 3.58 37%
Distributions per Trust Unit, declared(7) 0.60 0.60 0% 2.40 2.40 0%
Payout ratio(2)(5) 46% 75% (39%) 50% 66% (24%)
Capital asset additions (excluding
acquisitions) 8,873 4,334 105% 42,662 27,209 57%
Acquisitions -- 80,271 (100%) 706,000 108,700 549%
Net debt (excluding derivative
contracts)(3)(5) 429,671 78,555 447% 429,671 78,555 447%
Weighted average Trust Units
outstanding, basic(4) 40,937 16,175 153% 25,324 12,591 101%
Trust Units outstanding, end of period 41,788 17,109 144% 41,788 17,109 144%
Trust Units, fully diluted(8), end of period 45,088 18,174 148% 45,088 18,174 148%
=================================================================================================================================
OPERATING
- ---------------------------------------------------------------------------------------------------------------------------------
Daily Sales Volumes(10)
Light oil (bbl/day) 12,228 4,079 200% 7,911 1,028 670%
Medium oil (bbl/day) 3,644 4,662 (22%) 4,324 4,286 1%
Heavy oil (bbl/day) 15,120 5,756 163% 8,495 5,444 56%
Natural gas liquids (bbl/day) 1,309 70 1770% 471 64 636%
Natural gas (mcf/d) 28,338 1,744 1525% 10,903 1,311 732%
- ---------------------------------------------------------------------------------------------------------------------------------
Total (BOE/d)(1) 37,024 14,858 149% 23,019 11,040 109%
=================================================================================================================================
OPERATING NETBACK(5) ($/BOE)
- ---------------------------------------------------------------------------------------------------------------------------------
Revenues $ 37.77 $ 29.13 30% $ 39.33 $ 29.62 33%
Realized loss on derivative contracts (4.91) (2.18) 125% (6.47) (4.67) 39%
Royalites (6.23) (4.66) 34% (6.44) (4.07) 58%
As a percent of revenue (%) 16.5% 16% 3% 16.4% 13.8% 19%
Operating expense(9) (7.37) (9.50) (22%) (8.48) (8.94) (5%)
- ---------------------------------------------------------------------------------------------------------------------------------
Operating netback(5) $ 19.26 $ 12.79 51% $ 17.94 $ 11.94 50%
- ---------------------------------------------------------------------------------------------------------------------------------
(1) All calculations required to convert natural gas to a crude oil equivalent
(BOE) have been made using a ratio of 6 mcf of natural gas to 1 barrel of crude
oil. BOEs may be misleading, particularly if used in isolation. The BOE
conversion ratio is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.
(2) Ratio of distributions to cash flow from operations.
(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 and the accounting liability related to our Trust Unit
incentive plan. Equity bridge notes and convertible debentures are reflected as
equity on our consolidated balance sheet in accordance with Canadian GAAP. In
2005, GAAP will require these amounts to be reflected as debt.
(4) Reflects both Trust Units and exchangeable shares.
(5) These are non-GAAP measures; please refer to "Certain Financial Reporting
Measures" included in our MD&A.
(6) Restated to reflect the adoption of new CICA recommendations to account for
asset retirement obligations. See Note 3 to the Consolidated Financial
Statements.
(7) As if the Trust Unit was held throughout the period.
(8) Fully diluted units differ from diluted units for accounting purposes. Fully
diluted includes Trust Units outstanding as at December 31 plus the impact of
the conversion or exercise of exchangeable shares, Trust Unit rights and
convertible debentures if completed at December 31.
(9) Includes realized gain on electricity derivative contracts of $0.18 and
$0.24 for fourth quarter and full year 2004, respectively, and $0.26 and $0.39
for the same periods in 2003.
(10) Harvest classifies its oil production as light, medium and heavy according
to NI 51-101 guidance.
2004 HIGHLIGHTS
When reviewing our 2004 results, readers are reminded that the Storm acquisition
took place on June 30, 2004, and the EnCana acquisition became effective on
September 2, 2004. The combination of these two events significantly impacted
our operations and financial results for the latter part of 2004 as well as
comparability between quarters.
o The Storm acquisition represented approximately 4,000 BOE/d of light oil and
natural gas properties in the Red Earth area of North Central Alberta, for
consideration of $192.2 million;
o The EnCana acquisition of $526 million ($511.4 million after adjustments) for
properties in East Central and Southern Alberta added approximately 19,000
BOE/d of production. Additionally, our reserve life index increased to 8 and
we diversified our product mix by increasing our natural gas production
weighting to approximately 13%;
4 EXHIBIT 99.3
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o We successfully closed a financing of U.S.$250 million, 7-year 7 7/8% senior
notes on October 14, 2004 creating additional financial flexibility and
providing entry into the U.S. financial markets. The proceeds from the
financing were used to substantially repay outstanding bank debt used to
finance the EnCana acquisition;
o We have successfully integrated the new North Central, East Central and
Southern Alberta personnel and assets into our existing operations.
Development and optimization work on all properties commenced immediately
after the closing of each transaction.
2004 BENCHMARK PERFORMANCE AND 2005 OUTLOOK
The table below provides a summary of our performance during 2004 against
objectives identified in our 2003 annual report, and outlines our objectives for
2005.
2004 OBJECTIVE 2004 PERFORMANCE 2005 OUTLOOK
- ------------------------------------------------------------------------------------------------------------------------------
Build on success achieved in 2003 by Through our internal capital Continue to develop and maximize
adding proved reserves and extending development program, increased Total returns from our assets.
reserve life index (RLI). Proved reserves by 7.4 mmBOE, after
adjusting for production. Corporate RLI
extended to 8 years through development
and acquisition.
Execute on accretive acquisitions that Completed Storm acquisition in June, Continue to evaluate acquisition
offer strategic fit, cost reductions, and increasing production at that time to opportunities, and capitalize on those
improvement of portfolio quality. approximately 19,000 BOE/d and RLI to where value can be added. If
6.7. High netback production and
light acquisition market is not
accessible, oil added to asset mix.
Completed exploit existing
inventory of EnCana acquisition in
September, opportunities for
development. increasing production
in the fourth quarter to average
approximately 37,000 BOE/d. High
netback production and natural gas
added to asset portfolio.
Invest $35 million of capital in Invested approximately $43 million in Invest approximately $75 million in
development program. development capital through the year, capital development.
recording Proved plus Probable
Finding & Development (F&D) costs
of $4.15/BOE and Total Proved F&D
costs of $5.42/BOE.
Maintain average production between 15,000 2004 production averaged 23,019 BOE/d; Production to average between 34,000
and 15,500 BOE/d. fourth quarter 2004 production averaged and 36,000 BOE/d.
37,024 BOE/d.
Attain average royalty rate between 15 and 2004 royalty rate averaged 16.4%, while Maintain average royalty rate between
17% and operating expense per BOE between operating expenses per BOE 15 and 17%, and maintain operating
between $10.00 and $10.50. averaged approximately $8.48 for the expenses per BOE between $7.75 and
full year and $7.37 in the fourth $8.50.
quarter.
Pay $0.20 per Unit per month distribution 2004 distributions totaled $2.40 per Maintain consistent $0.20 distribution
through 2004. Trust Unit. level through 2005.
SUMMARY OF HISTORICAL QUARTERLY RESULTS
The table and discussion below highlight our performance for the previous eight
quarters on select measures. Our Initial Public Offering took place in December
of 2002.
5 EXHIBIT 99.3
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- -------------------------------------------------------------------------------------------------------------------------------
(RESTATED - REFER TO NOTE 3 OF THE CONSOLIDATED FINANCIAL
STATEMENTS)
2004 2003
-------------------------------------------- ----------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
- ------------------------------------------------------------------------------ ----------------------------------------------
Revenue, net of royalties $ 107,446 $ 85,424 $ 44,752 $ 39,473 $ 33,575 $ 24,706 $ 21,350 $ 23,308
Operating expense(3) (25,113) (18,993) (13,600) (13,674) (12,984) (9,661) (6,596) (6,804)
- -------------------------------------------------------------------------------------------------------------------------------
Net operating income(1) $ 82,333 $ 66,431 $ 31,152 $ 25,799 $ 20,591 $ 15,045 $ 14,754 16,504
Net income (loss) 12,536 5,166 1,594 (1,065) 5,495 5,488 1,064 3,469
Per Trust Unit, basic(2) 0.29 0.07 0.02 (0.13) 0.30 0.44 0.09 0.33
Per Trust Unit, diluted(2) 0.28 0.07 0.02 (0.13) 0.29 0.43 0.09 0.32
Cash flow from operations(1) 53,545 44,459 17,160 14,839 13,699 16,758 9,546 6,489
Per Trust Unit, basic(1),(2) 1.31 1.50 0.99 0.87 0.85 1.35 0.84 0.62
Per Trust Unit, diluted(1),(2) 1.27 1.47 0.96 0.84 0.82 1.31 0.82 0.60
SALES VOLUMES
- -------------------------------------------------------------------------------------------------------------------------------
Crude oil (bbl/d) 30,992 22,397 14,775 14,626 14,497 11,054 9,371 8,034
Natural gas liquids (bbl/d) 1,309 377 141 50 70 77 67 43
Natural gas (mcf/d) 28,338 11,909 2,249 915 1,744 1,453 1,161 875
- -------------------------------------------------------------------------------------------------------------------------------
Total (BOE/d) 37,024 24,759 15,291 14,829 14,858 11,373 9,632 8,223
===============================================================================================================================
(1) This is a non-GAAP measure as referred to under "Certain Financial
Reporting Measures".
(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.
(3) Reflects the gains and losses on electricity derivative contracts.
Net revenues and net operating income have trended higher since the first
quarter of 2003, with significant increases occurring in the third and fourth
quarters of 2004. The revenue increase since 2003 is primarily attributable to
increasing production volumes and the strong commodity price environment during
2004. The two significant acquisitions completed in 2004, which closed in June
and September, both contributed to the significant increases in third and fourth
quarter production volumes, revenue and cash flow.
Net income reflects both cash and non-cash items. The non-cash items, including
depletion, depreciation and accretion (DD&A), foreign exchange, unrealized gain
or loss on derivatives, Trust Unit right compensation expense and future income
taxes can cause net income to vary significantly. However, these items do not
impact the cash flow available for distribution to Unitholders, and therefore
management believes net income may be a less meaningful measure of performance
for a royalty trust such as Harvest. Net income (loss) has not reflected the
same trend as net revenues or cash flows due mainly to the inclusion of
unrealized mark-to-market gains and losses on derivative contracts.
Cash flow from operations is a key measure for a royalty trust as it represents
the key source of cash distributions for Unitholders. Excluding the substantial
non-recurring foreign exchange gain realized in the third quarter of 2003, our
cash flow from operations has demonstrated a steady upward trend. Cash flows can
be impacted by factors outside of management's control such as commodity prices
and currency exchange rates. We strive to mitigate the impact of these factors
by using hedging (sometimes referred to as `derivatives' or `derivative
contracts' herein) to fix future commodity prices and currency exchange rates on
a portion of our transactions.
6 EXHIBIT 99.3
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2003 2004
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
CASH FLOW FROM OPERATIONS ($MILLIONS) 6.5 9.5 16.8 13.7 14.8 17.2 44.5 53.5
2003 2004
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
OPERATING NETBACK ($/BOE) 10.72 12.71 11.01 12.79 12.41 13.59 21.94 19.26
SUMMARY OF HISTORICAL ANNUAL RESULTS
Year ended December 31
----------------------------------------------
($ MILLIONS EXCEPT PER TRUST UNIT AMOUNTS) 2004 2003 2002
- --------------------------------------------------------------------------------------------------
(RESTATED) (RESTATED)
Net revenue $ 277.1 $102.9 $20.0
Net income 18.2 15.5 4.8
Per Trust Unit, basic 0.47 1.16 3.47
Per Trust Unit, fully diluted 0.45 1.13 3.27
Total assets 1,046.3 256.4 108.4
Total long-term financial liabilities 300.5 - -
Distributions per Trust Unit, declared ($/Unit) $ 2.40 $2.40 $0.20
==================================================================================================
REVENUES
Three months ended December 31 Year ended December 31
--------------------------------------- --------------------------------------
2004 2003 % Change 2004 2003 % Change
- -------------------------------------------------------------------------- --------------------------------------
Oil and natural gas sales ($/BOE) $ 37.77 $ 29.13 30% $ 39.33 $ 29.62 33%
Royalty expense, net ($/BOE) (6.23) (4.66) 34% (6.44) (4.07) 58%
- -------------------------------------------------------------------------- --------------------------------------
Net revenues ($/BOE) $ 31.54 $ 24.47 29% $ 32.89 $ 25.55 29%
- -------------------------------------------------------------------------- --------------------------------------
Net revenues ($millions) $ 107.4 $ 33.6 220% $ 277.1 $ 102.9 169%
====================================================================================================================
Our net revenue is impacted by production volumes, commodity prices, currency
exchange rates and royalty rates. As a result of the acquisitions we completed
during 2004, and the rising crude oil price environment, our revenues in the
three and twelve month periods ending December 31, 2004 increased substantially
over the same periods in 2003. Despite this, the increases in our fourth quarter
2004 revenues were slightly offset by widening heavy oil differentials, and a
strengthening Canadian dollar. Changes in realized prices, volumes and royalty
rates are discussed below. The impact of our hedging activities on current and
future results is discussed under "Derivative Contracts".
SALES VOLUMES
The average daily sales volumes by product were as follows:
Three Months Ended December 31 Year Ended December 31
------------------------------------ ----------------------------------
2004 2003 % Change 2004 2003 % Change
- ----------------------------------------------------------------------- ----------------------------------
Light oil (Bbl/d) 12,228 4,079 200% 7,911 1,028 670%
Medium oil (Bbl/d) 3,644 4,662 -22% 4,324 4,286 1%
Heavy oil (Bbl/d) 15,120 5,756 163% 8,495 5,444 56%
- ----------------------------------------------------------------------- ----------------------------------
Total oil (Bbl/d) 30,992 14,497 114% 20,730 10,758 93%
Natural gas liquids (Bbl/d) 1,309 70 1770% 471 64 636%
- ----------------------------------------------------------------------- ----------------------------------
Total liquids (Bbl/d) 32,301 14,567 122% 21,201 10,822 96%
Natural gas (mcf/d) 28,338 1,744 1525% 10,903 1,311 732%
- ----------------------------------------------------------------------- ----------------------------------
Total oil equivalent (BOE/d) 37,024 14,858 149% 23,019 11,040 109%
- ----------------------------------------------------------------------- ----------------------------------
Sales volumes averaged 37,024 BOE/d in the fourth quarter of 2004, compared to
14,858 BOE/d for the same period in 2003. The fourth quarter production
breakdown is representative of our new commodity mix following the Storm and
EnCana transactions. Full year 2004 average production of 23,019 BOE/d was 109%
higher than the 11,040 BOE/d averaged in 2003. The higher average
7 EXHIBIT 99.3
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production realized in 2004 compared to 2003 is primarily attributable to the
two significant acquisitions of Storm and the EnCana properties. In addition,
the natural gas component of our production was approximately 13% in the fourth
quarter, up from only 2% in the fourth quarter of 2003. In October 2003, we
acquired approximately 5,500 BOE/d of production, the full impact of which was
not realized until 2004.
For 2005, we anticipate production volumes to average between 34,000 and 36,000
BOE/day.
We do not intentionally manage to a specific production mix. The production mix
is a result of our strategy of targeting accretive acquisitions and capitalizing
on opportunities, rather than targeting specific commodity types. The product
mix changed significantly in 2004 with the addition of light oil from the Storm
acquisition and natural gas from the EnCana acquisition.
2003 2004
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
QUARTERLY AVERAGE PRODUCTION VOLUMES (BOE/D) 8,223 9,632 11,373 14,858 14,829 15,291 24,759 37,024
REALIZED COMMODITY PRICES
The following table provides a breakdown of our 2004 and 2003 average commodity
prices by product before realized losses on derivative contracts.
Three months ended December 31 Year ended December 31
------------------------------- --------------------------------
Product Prices 2004 2003 % Change 2004 2003 % Change
- ---------------------------------------------------------- --------------------------------
Light oil ($/bbl) $53.64 $35.56 51% $48.70 $35.56
Medium oil ($/bbl) 35.55 30.13 18% 38.78 32.18 21%
Heavy oil ($/bbl) 28.73 24.92 15% 31.11 27.34 14%
Natural gas liquids
($/bbl) 33.19 29.18 14% 41.10 29.92 37%
Natural gas ($/mcf) 5.68 6.01 -5% 6.30 6.70 -6%
- ---------------------------------------------------------- --------------------------------
Total ($/BOE) $37.77 $29.13 30% 39.33 29.62 33%
- ---------------------------------------------------------- --------------------------------
Realized derivative
contract losses ($/BOE)(1) $(4.91) $(2.18) 125% $(6.47) $(4.67) 39%
- ---------------------------------------------------------- --------------------------------
Net realized price ($/BOE) $32.86 $26.95 22% $32.86 $24.95 32%
===============================================================================================
(1) These amounts are included in gains and losses on derivative contracts on
the income statement.
In 2004, our revenues were impacted by realized losses on oil price swaps and
collars that were implemented in 2002 and 2003. These hedge contracts capped our
ability to realize upside on West Texas Intermediate ("WTI") price movements.
The majority of these types of oil price derivative contracts expired at the end
of 2004. Consequently, we will be able to realize net prices closer to spot
price levels in 2005. At the time of writing, we had entered into oil price
derivative contracts on approximately 75% of our 2005 net crude oil production,
and approximately 40% of our 2006 net crude oil production. The majority of the
2005 and 2006 commodity derivative contracts that we have in place provide a
fixed crude oil floor price, while retaining the ability to participate in
upward price appreciation. Examples of such contracts include `indexed puts' and
`participating swaps', and additional information on these and other commodity
derivative contracts can be found in the "Derivative Contracts" section of this
MD&A.
Three Months Ended December 31 Year Ended December 31
---------------------------------- ----------------------------------
Benchmarks 2004 2003 % Change 2004 2003 % Change
- ------------------------------------------------------------------------------------ ----------------------------------
West Texas Intermediate crude oil (US$ per
barrel) 48.28 31.18 54.8% 41.40 30.99 33.6%
Edmonton light crude oil ($ per barrel) 58.58 41.05 42.7% 53.20 43.77 21.5%
Lloyd blend crude oil ($ per barrel) 35.00 27.31 28.2% 36.30 31.48 15.3%
Bow river blend crude oil ($ per barrel) 35.66 28.17 26.6% 37.19 32.39 14.8%
AECO natural gas ($ per mcf) 7.51 5.96 26.0% 6.80 6.67 1.9%
Canadian / U.S. dollar exchange rate 0.819 0.760 7.8% 0.770 0.713 8.0%
- ---------------------------------------------- -- ----------- ----------- ---------- -- ----------- ------------ ---------
8 EXHIBIT 99.3
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Through 2004, the benchmark price of WTI crude oil rose steadily, opening the
year at U.S.$32.40, hitting a high of U.S.$55.67 on October 25th, and closing
the year at U.S.$43.45. These historically high prices for crude oil can be
attributed to strong demand growth, particularly in China, and economic
expansion in the U.S. OPEC was slow to respond to the demand increases and
worldwide inventories dropped to near all-time lows measured by days of demand
cover. This increased demand on OPEC left the cartel with little room for spare
capacity, which caused further uncertainty and extreme price volatility. This
tight supply/demand balance was compounded by continued unrest in the Middle
East, fears of terrorism interrupting the supply chain, and concerns regarding
tight refining capacity. In 2005, we anticipate these strong global fundamentals
to be sustained, resulting in another robust environment for WTI prices.
However, we see the potential for periods of weakness and the possibility for
reduced economic growth in key demand markets such as the U.S. having a more
serious impact on world oil prices.
Given Harvest's production mix, which includes medium and heavy crude oil, the
benefits of high WTI prices were tempered due to wider medium and heavy crude
price differentials in 2004. Heavy differentials reached a high in the fourth
quarter of U.S.$19.79 per barrel below WTI for Lloyd Blend crude, a benchmark
for medium and heavy crude oil prices in Western Canada. In an environment of
rising WTI prices, it is expected that differentials will widen, but this effect
was exacerbated in the fourth quarter because of stagnation in the heavy refined
product market and an increase in the supply of heavy sour crude from OPEC. As a
result of this widening differential, our realized price on medium and heavier
grade crude oil was constricted. Through 2004, this impact was mitigated by
4,250 BOE/d of hedges on the heavy crude differential. We currently have no
differential hedges beyond 2004. We will continue to monitor the market with a
view to reducing the impact of changing differentials on realized prices. The
market for heavy oil price financial derivatives is not well established and we
may need to enter into other forms of transactions to achieve this objective.
Our acquisitions in 2004 have helped reduce our exposure to heavy oil
differentials by diversifying our commodity mix.
In addition to hedging, we also strive to maximize the price received for our
heavy oil production by marketing into streams that offer better pricing, using
our natural gas liquids production as a hedge against the cost of condensate and
utilizing heated pipelines to reduce blending requirements. If the price of WTI
remains high in 2005, we expect differentials to remain wide versus historical
levels, but narrow from those experienced in the fourth quarter of 2004.
In 2004, the Canadian dollar continued its strengthening trend, which began in
2002. This dampened the revenue gains from the rising WTI price for Canadian oil
producers. The Canadian dollar reached a twelve year high on November 26, 2004
of $0.8493. This compares to the year end 2003 level of $0.7738 and the December
31, 2004 level of $0.8308. As a result of our U.S. dollar denominated senior
notes, which were issued in October 2004, we have a partial natural hedge
against currency exchange rates. In addition to this natural hedge, we have
hedged U.S.$8.3 million per month through 2005, with a floor at U.S.$0.8333. The
long term outlook for the Canadian dollar remains robust, as Canada continues to
experience strong demand for its commodities.
After completing the acquisition of properties in East Central and Southern
Alberta in September of 2004, our natural gas weighting increased from
approximately 2% to approximately 13% of total production. As a result, the
impact of natural gas prices has become more significant to us. Natural gas
demand growth remains strong, particularly for electricity generation. Recently
the price has become more closely related to oil pricing as the effects of fuel
switching to high sulphur fuel oil now set a floor, rather than a ceiling, on
the price of natural gas. During 2004, the price of natural gas at AECO
experienced volatility due primarily to storage and weather related issues, and
reached a peak of $8.19/GJ on October 27th and a low of $4.60/GJ on November
19th. It is expected that natural gas prices will remain healthy in 2005 with
the potential for considerable price spikes should WTI prices remain strong and
primary markets experience either a warm summer or a cold winter season. We have
not, as yet, hedged any of our natural gas price exposure.
We anticipate that our gas production as a percentage of total production may
decline slightly in 2005 as the 2005 capital budget does not include a
proportionate amount for natural gas property development.
ROYALTIES
We pay Crown, freehold or overriding royalties to the owners of mineral rights
from which production is generated. These royalties vary for each property and
product and our Crown royalties are based on a sliding scale dependent on
production volumes and commodity prices. In certain situations, such as with
some heavy oil production, the Alberta Energy and Utilities Board grants royalty
'holidays', effectively eliminating royalties on a specific well or group of
wells.
For the three months ended December 31, 2004, our net royalties as a percentage
of revenue were 16.5% ($21.2 million), compared to 16.0% ($6.4 million) in the
same period in 2003, despite stronger commodity prices. The small increase in
the royalty rate in the fourth quarter 2004 compared with the same period in
2003, relative to the 30% increase in net prices, is attributable to the lower
royalty rate of the properties acquired in September.
9 EXHIBIT 99.3
------------
For the full year 2004, our net royalties as a percentage of revenue were 16.4%
($54.2 million), compared to 13.8% ($16.4 million) in 2003. The higher royalty
rate for full year 2004 compared to 2003 is primarily due to the higher royalty
rates on the North Central Alberta properties and the Southeast Saskatchewan
properties, which were acquired in the second quarter of 2004 and the fourth
quarter of 2003, respectively. For 2005, we are anticipating our royalty rate as
a percentage of net revenues to be between 15 and 17%.
OPERATING EXPENSE
Three months ended December 31 Year ended December 31
--------------------------------- ------------------------------
($ PER BOE) 2004 2003 % Change 2004 2003 % Change
- -------------------------------------------------------------------- ------------------------------
Operating expense $7.55 $9.76 (23%) $8.72 $9.33 (7%)
Realized gains on electricity
derivative contracts (0.18) (0.26) (31%) (0.24) (0.39) (38%)
- -------------------------------------------------------------------- ------------------------------
Net operating expense $7.37 $9.50 (22%) $8.48 $8.94 (5%)
====================================================================================================
Our operating expenses (before the impact of realized gains on electricity
derivative contracts) for the three and twelve month periods ending December 31,
2004 were $25.7 million ($7.55/BOE) and $73.4 million ($8.72/BOE), respectively.
For the same respective periods in 2003 (before the impact of realized gains on
electricity derivative contracts), operating expenses were $13.3 million
($9.76/BOE) and $37.6 million ($9.33/BOE). The decrease in 2004 compared to 2003
is primarily due to the acquisition of lower operating cost properties from
Storm and EnCana, slightly offset by the acquisition of the higher operating
cost properties in Southeast Saskatchewan in the fourth quarter of 2003. The
2004 operating cost figures are in line with our previous guidance issued in
mid-2004.
To help control operating expenses, a portion of our capital spending program is
directed towards operating cost reduction initiatives such as water disposal,
fluid handling and power reduction projects. We strive to minimize operating
costs, which contributes to stronger netbacks, and can extend reserve life by
making the extraction of reserves more economical later in the life of the
property.
Electricity costs represent a significant portion of our operating costs, so
efforts are constantly focused on ways to reduce electricity costs. In 2004,
approximately 37% of our operating expenses related to electricity consumption,
compared to approximately 60% in 2003. This reduction is a result of two
factors. We handle significant volumes of water on our East Central Alberta oil
production and processing and disposing of the water requires a large amount of
electricity. In 2004, as part of our ongoing initiatives to control costs, we
found a more efficient method to dispose of produced water, by injecting it into
a different reservoir at vacuum, and reduced power costs in this core area. In
addition, a large portion of the new properties acquired in 2004 do not require
as much electricity in relation to other operating costs.
During 2004, monthly electricity costs varied from $42.46 per megawatt hour
(MWh) to $67.13/MWh. Through the application of electricity hedges, our exposure
to volatile and rising costs was tempered. Alberta is a deregulated market and
electricity prices are expected to remain volatile through 2005 and into 2006.
We continue to mitigate this risk through hedging and are working on a variety
of site optimization opportunities to minimize power consumption. We anticipate
realizing further benefits from our electricity hedges in 2005 and 2006.
Approximately 85% and 70% of our estimated Alberta electricity usage for 2005
and 2006 are hedged at an average price of $47.50/MWh. This hedging activity
should keep our 2005 electricity costs close to levels experienced in 2004, with
operating costs in 2005 expected to average between $7.75/BOE and $8.50/BOE.
Three Months Ended December 31 Year Ended December 31
---------------------------------- ----------------------------------
Benchmark Price 2004 2003 % Change 2004 2003 % Change
- ---------------------------------------------------------------------- ----------------------------------
Alberta Power Pool electricity
price ($ per MWh) $54.94 $54.77 0.3% $54.59 $62.99 (13%)
==========================================================================================================
10 EXHIBIT 99.3
------------
GENERAL AND ADMINISTRATIVE (G&A) EXPENSE
THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31
------------------------------------ -------------------------------
($MILLIONS EXCEPT PER BOE) 2004 2003 % CHANGE 2004 2003 % CHANGE
- -------------------------------------------------------------------- -----------------------------------
G&A $ 3.3 $ 2.1 57% $ 8.6 $ 4.1 110%
Per BOE ($/BOE) 0.98 1.50 (35%) 1.02 1.02 0%
Unit right compensation expense 10.6 0.1 10500% 11.4 0.2 5600%
Per BOE ($/BOE) 3.11 0.15 1973% 1.35 0.06 2150%
- -------------------------------------------------------------------- -----------------------------------
Total G&A $ 13.9 $ 2.2 532% $ 20.0 $ 4.3 365%
Per BOE ($/BOE) $ 4.09 $ 1.65 148% $ 2.37 $ 1.08 119%
========================================================================================================
The majority of our G&A expenses are related to salaries and other staffing
costs. The portion of G&A charged against income in the fourth quarter of 2004
totaled $13.9 million ($4.09/BOE) compared to $2.2 million ($1.65/BOE) for the
fourth quarter of 2003. For the twelve month period ended December 31, 2004, G&A
expense totaled $20.0 million ($2.37/BOE) compared to $4.3 million ($1.08/BOE)
for the same period in 2003.
The increase in G&A on a per BOE basis of 148% in the fourth quarter of 2004
compared to the same period in 2003 is the result of unit right compensation
expense and annual bonuses paid and accrued for 2004.
A modification to our Unit Incentive Rights Plan in the fourth quarter of 2004
resulted in a prospective change in accounting for unit appreciation rights
(UARs). In previous quarters, UARs were valued at the date they were granted
using a mathematical option valuation model and an expense was charged to G&A
based on that valuation. Following the prospective accounting change, we now
value vested UARs at the difference between exercise price and market price at
each reporting period end to determine the related liability at the end of the
period. Changes in the assumptions used in determining this liability, such as
our Trust Unit price, the exercise price and the number of UARs vested at each
accounting period will cause this liability to fluctuate and the difference is
reflected as expense on the consolidated statement of income. For the fourth
quarter of 2004, this non-cash amount in G&A accounted for $2.57/BOE.
In addition, approximately $1.8 million of UARs exercised and settled for cash
in the fourth quarter were charged to income. Annual bonuses paid and accrued
impacted the fourth quarter by approximately $0.28 per BOE. In 2005, we expect
cash G&A expenses to average between $0.90-$1.00 on a per BOE basis.
INTEREST EXPENSE
THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31
------------------------------------- --------------------------------
($MILLIONS) 2004 2003 % CHANGE 2004 2003 % CHANGE
- ------------------------------------------------------------------------- --------------------------------
Interest on short term debt $ 3.7 $ 2.2 68% $ 9.4 $ 5.6 68%
Interest on long term debt 5.5 -- -- 5.5 -- --
- ------------------------------------------------------------------------- --------------------------------
Total interest expense $ 9.2 $ 2.2 318% $ 14.9 $ 5.6 166%
===========================================================================================================
Interest expense in the three and twelve month periods ended December 31, 2004
was higher than in the same periods in 2003, primarily due to higher average
debt balances resulting from the property acquisitions completed in the last
half of 2004. Interest expense will be higher in 2005 than in the full year 2004
for this same reason. In addition, due to changes in generally accepted
accounting principles, our convertible debentures will be reflected as debt,
rather than equity, in 2005. This will result in interest on our convertible
debentures being reflected in interest on long-term debt and reflected in net
income.
Interest expense reflects the interest accrued on our outstanding bank debt and
senior notes as well as amortization of related financing costs. Interest on our
bank debt is levied at the prime rate plus 0 to 2.25% depending on our debt to
cash flow ratio. Our outstanding convertible debentures have fixed interest
rates at 9% for the first series (issued in January 2004) and 8% for the second
series (issued in August 2004). The large number of conversions of convertible
debentures during 2004 has reduced the balance of both series, and will result
in lower interest expense on these debentures in 2005 than 2004. We issued
long-term U.S. dollar denominated senior notes in October 2004, which bear
interest at 7 7/8% and mature on October 15, 2011. Issuing the senior notes
enabled us to repay our bank bridge loan and a significant portion of the senior
credit facility balance incurred with the acquisition of properties in
September. Undertaking the long term senior note issue provides us with a
natural hedge against fluctuations in currency exchange rates, increased
financial flexibility and access to the U.S. capital markets.
11 EXHIBIT 99.3
------------
DEPLETION, DEPRECIATION AND ACCRETION EXPENSE
THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31
------------------------------------ -------------------------------
($MILLIONS EXCEPT PER BOE) 2004 2003 % CHANGE 2004 2003 % CHANGE
- ----------------------------------------------------------------------- -------------------------------
Depletion and depreciation $ 44.7 $ 9.2 386% $ 88.8 $ 29.4 202%
Depletion of capitalized asset
retirement costs 3.8 1.6 138% 9.8 4.5 118%
Accretion on asset
retirement obligation 1.3 0.7 86% 4.2 1.8 133%
- ----------------------------------------------------------------------- -------------------------------
Total depletion, depreciation
and accretion $ 49.8 $ 11.5 333% $102.8 $ 35.7 188%
Per BOE ($/BOE) $ 14.62 $ 8.41 74% $12.20 $ 8.86 38%
========================================================================================================
In the fourth quarter of 2004, our overall depletion, depreciation and accretion
(DD&A) rate per BOE is higher compared to the same period in 2003, primarily due
to the acquisitions made in 2004. The higher DD&A rate reflects the higher value
netback for the acquired properties.
FOREIGN EXCHANGE GAIN
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 and any U.S. dollar deposits and cash balances. For the
year ended December 31, 2004, a foreign exchange gain of $7.1 million compares
to a foreign exchange gain of $4.4 million in 2003. The higher gain in 2004 was
primarily driven by the strengthening of the Canadian dollar to the U.S. dollar
during the period the senior notes were outstanding.
DERIVATIVE CONTRACTS
All of our hedging activities are carried out pursuant to policies approved by
the Board of Directors of Harvest Operations Corp. Management intends to
facilitate stable, long-term monthly distributions by reducing the impact of
volatility in commodity prices. As part of our risk management policy,
management utilizes a variety of derivative instruments (including swaps,
options and collars) to manage commodity price, foreign currency and interest
rate exposures. These instruments are commonly referred to as `hedges' but may
not receive hedge treatment for accounting purposes. Management also enters into
electricity price and heat rate based derivatives to assist in maintaining
stable operating costs. We reduce our exposure to credit risk associated with
these financial instruments by only entering into transactions with financially
sound, credit worthy counterparties.
When there is a high degree of correlation between the price movements in a
derivative financial instrument and the item designated as being `hedged' and
management documents the effectiveness of this relationship, we may employ hedge
accounting. Effective January 1, 2004, we implemented CICA Accounting Guideline
13, "Hedging Relationships" (AcG-13), which addresses the identification,
designation and effectiveness of financial contracts for the purpose of applying
hedge accounting. Under this guideline, financial derivative contracts must be
designated to the underlying revenue or expense stream that they are intended to
hedge, and then tested to ensure they remain sufficiently effective in order to
continue hedge accounting. As of October 1, 2004, we ceased to apply hedge
accounting to our derivative contracts. As a result, from October 1, 2004 all of
our derivatives are marked-to-market with the resulting gain or loss reflected
in earnings for the reporting period. The mark-to-market valuation represents
the amount that would be required to settle the contract on the period end date.
Collectively our contracts had a mark-to-market unrealized non-cash loss
position on the balance sheet of $15.4 million as at December 31, 2004. Please
refer to Note 16 in the consolidated financial statements for further
information.
For 2004, we recorded a realized loss on commodity derivative contracts of $52.4
million, and an unrealized loss of $11.3 million. The realized loss portion
reflects the revenue lost due to the derivative contracts in effect during that
period. In 2003, we recorded a hedging loss of $18.9 million. Derivative
contract losses in 2005, assuming similar commodity price levels, will be
smaller than those experienced in 2004 as the volume of production hedged with
swaps and collars with price ceilings has diminished.
DEFERRED CHARGES AND DEFERRED GAINS
The deferred charges asset balance on the balance sheet is comprised of two main
components: deferred financing charges and deferred assets related to the
discontinuation of hedge accounting. The deferred financing charges relate
primarily to the issuance of the senior notes and bank debt and are amortized
over the life of the debt. On the initial adoption of AcG-13, we recorded a
deferred charge of $5.5 million, relating to the contracts not qualifying for
hedge accounting at the time of adoption.
12 EXHIBIT 99.3
------------
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 of $20.2 million and a deferred gain
of $2.5 million was recorded equal to the fair value of the contracts at the
time hedge accounting was discontinued, and a corresponding amount was recorded
as a derivative contracts asset or liability. The deferred amount is recognized
in income in the period in which the underlying transaction is recognized.
For the year ended December 31, 2004, $14.9 million of the deferred charge and
$350,000 of the deferred gain has been amortized and recorded in gains and
losses on derivative contracts. At December 31, 2004, $10.8 million has been
recorded as a deferred charge, with $2.2 million recorded as a deferred gain
related to derivative contracts.
GOODWILL
Goodwill is the residual amount that results when the purchase price of an
acquired business exceeds the fair value for accounting purposes of the net
identifiable assets and liabilities of that acquired business. In June 2004, we
completed a Plan of Arrangement with Storm Energy Ltd., and acquired certain oil
and natural gas producing properties in North Central Alberta for total
consideration of $192.2 million. This transaction has been accounted for using
the purchase price method, and resulted in Harvest recording goodwill of $43.8
million in 2004. This goodwill balance will be assessed annually for impairment
or more frequently if events or changes in circumstances occur that would
reasonably be expected to reduce the fair value of the acquired business to a
level below its carrying amount.
FUTURE INCOME TAXES
Future income taxes reflect the net tax effects of temporary differences between
the carrying amounts of assets and liabilities of our corporate operating
subsidiaries for financial reporting purposes and the related income tax
balances. Future income taxes arise, for example, as depletion and depreciation
expense recorded against capital assets differs from claims under related tax
pools. Future taxes also arise when tax pools associated with assets acquired
are different from the purchase price recorded for accounting purposes. While we
realized a recovery of future income taxes during the year, the overall future
tax liability on the balance sheet increased due to the future income taxes
booked on the acquisition of Storm Energy Ltd. (described previously under
"Goodwill").
We recorded future income tax expense of $3.6 million for the three month period
ended December 31, 2004, and a recovery of $4.9 million for the three months
ended December 31, 2003. Future income tax recoveries for the twelve month
periods ended December 31, 2004 and 2003 were $10.4 million and $9.0 million,
respectively.
ASSET RETIREMENT OBLIGATIONS (ARO)
Effective January 1, 2004, we adopted CICA Handbook Section 3110 "Accounting for
Asset Retirement Obligations". In connection with a property acquisition or
development expenditure, we will record the fair value of the ARO as a liability
in the year in which an obligation to reclaim and restore the related asset is
incurred. Our ARO costs are capitalized as part of the carrying amount of the
assets, and are depleted and depreciated over our estimated net proved reserves.
Once the initial ARO is measured, it must be adjusted at the end of each period
to reflect the passage of time as well as changes in the estimated future cash
flows that underlie the obligation.
Our asset retirement obligation has increased by $48.1 million in 2004 mainly
due to the acquisitions of the North Central, East Central and Southern Alberta
assets during the year.
LIQUIDITY AND CAPITAL RESOURCES
Our drilling and operational enhancement programs, as well as current financial
commitments, are expected to be financed from cash flow from operations (see
"Certain Financial Reporting Measures" in this MD&A). Our cash distributions to
Unitholders are financed solely from cash flow from operations. In 2004, our
distribution payout ratio of 50% (calculated by dividing distributions to
Unitholders into cash flow from operations) resulted in significant free cash
flow available for our capital expenditure programs and debt repayment.
Management anticipates sufficient cash flow from operations in 2005 to be
available for the planned capital development program of $75 million, expected
distributions of $0.20 per Unit per month and to repay a portion of outstanding
bank debt. Given our significant amount of oil price hedges in place, management
believes cash flows in 2005 will exceed cash distributions and budgeted capital
expenditures under most WTI price scenarios.
Should commodity prices stay strong, heavy oil differentials narrow and the
Canadian dollar stabilize, we should have sufficient cash flow to repay a
significant portion of our outstanding bank debt by the end of 2005. It is also
important to note that to the extent our Unitholders elect to receive
distributions in the form of Trust Units rather than cash under our Distribution
Reinvestment plan (DRIP), this further reduces net cash outlays. During 2004,
DRIP participation was approximately 21%.
13 EXHIBIT 99.3
------------
2003 2004
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
PAYOUT RATIO (%) 93 73 45 75 69 64 41 46
The table below provides an analysis of our debt structure, including some key
debt ratios. We believe that the current capital structure is appropriate given
our low payout ratio and the significant hedges in place. We intend to use cash
flow after distributions and capital expenditures to repay bank debt.
YEAR ENDED DECEMBER 31
-------------------------------------
($ MILLIONS) 2004 2003 % Change
- --------------------------------------------------------------------------------------------------
Bank debt $ 75.5 $ 63.3 19%
Senior notes 300.5 -- --
Working capital deficit (surplus) excluding bank debt(2) 27.8 (9.8) -384%
Equity bridge notes -- 25.0 --
Convertible debentures 25.9 -- --
- --------------------------------------------------------------------------------------------------
Net debt obligations $ 429.7 $ 78.5 447%
- --------------------------------------------------------------------------------------------------
Fourth quarter cash flow annualized $ 214.2 $ 54.8 291%
Trailing net debt to cash flow (times)1 2.0 1.4 43%
==================================================================================================
(1) Reflects realized hedging losses which were significant in the fourth
quarter given the nature of our oil price hedges, which were primarily collars
and swaps. Our hedges in 2005 are primarily instruments which do not place a cap
on WTI price realizations.
(2) Excludes current portion of derivative contracts assets and liabilities and
Trust Unit incentive plan liability.
From time to time we may require additional external financing, in the form of
either debt or equity, to further our business plan of maintaining production
and reserves through acquisitions and capital expenditures. Our 2005 capital
expenditure budget is likely not sufficient to maintain current production
levels, but our cash flow from operations is expected to be at least sufficient
to pay our distributions to Unitholders and fund our capital spending program.
We strive to maintain financial flexibility that will enable us to capitalize on
acquisition opportunities as they arise or increase our capital spending budget.
In financing any new acquisitions, we will likely access both the debt and
equity markets in appropriate amounts so as to maintain a supportable capital
structure. We target debt to cash flow between 1.0 to 1.5 times, but are
comfortable with slightly higher levels immediately following an acquisition
provided adequate hedging is in place to support forecasted cash flows. Our
ability to obtain 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 our management to alter our current business plan.
As a result of the acquisition of assets in East Central and Southern Alberta in
September, our bank credit facility increased to $325 million. Proceeds from the
issuance of the U.S.$250 million senior notes were used to partially repay
amounts drawn under the credit facility. Outstanding bank debt plus working
capital deficiency at December 31, 2004 totaled $103.3 million, leaving
approximately $222 million undrawn. The amount available under the bank credit
facility may be redetermined by our lenders from time to time based on lenders'
estimates of future cash flows from our oil and natural gas properties. Thus,
our ability to draw on this facility may change. We may draw under this
facility, or complete additional financings in the form of senior notes,
convertible debentures or Trust Units to expand the capital program or to
finance additional acquisitions. We may also utilize bridge financing, similar
to that used in 2003 and 2004, if required.
Our bank debt will be repaid or refinanced in June 2005 with a similar facility.
As lenders calculate the amount of such facilities using conservative price
assumptions, management does not anticipate a significant change to the amount
available under the new facility. The long term to maturity of the senior notes
allows us significant flexibility in determining how that particular debt is
refinanced.
14 EXHIBIT 99.3
------------
A breakdown of our outstanding Trust Units and potentially dilutive instruments
are as follows:
AS AT DECEMBER 31
----------------------------------------------
($ AMOUNTS ARE IN 000S) 2004 2003 % Change
- ---------------------------------------------------------------------------------------------------------
Trust Units outstanding 41,788,500 17,109,006 144%
Exchangeable shares outstanding 455,547 -- --
Trust Units represented by Exchangeable Shares (1) 485,003 -- --
Market price of Trust Units at end of period ($/unit) 22.95 14.07 63%
Total market value of Trust Units at end of period (2) $ 970,177 $ 240,724 303%
9% Convertible debentures (3) $ 10,700 $ -- --
8% Convertible debentures (4) $ 15,159 $ -- --
Trust Unit rights outstanding (5) 1,117,725 1,065,150 5%
Total Trust Units, diluted 45,088,376 18,174,156 148%
- ----------------------------------------------------------------------------------------------------------
(1) Exchangeable shares are exchangeable into Trust Units at the election of the
holder at any time. Based on the exchange ratio in effect on December 31, 2004
of 1.06466.
(2) Including Trust Units outstanding and assuming exchange of all exchangeable
shares.
(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 $14.00
per Trust Unit. If Debenture holders converted all outstanding debentures in
this series at December 31, 2004 an additional 764,286 Trust Units would be
issuable.
(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 $16.25
per Trust Unit. If Debenture holders converted all outstanding debentures in
this series at December 31, 2004 an additional 932,862 Trust Units would be
issuable.
(5) Exercisable at an average price of $10.09 per Trust Unit as at December 31,
2004. (6) Fully diluted units differ from diluted units for accounting purposes.
Fully diluted includes Trust Units outstanding as at December 31 plus the impact
of the conversion of exercise of exchangeable shares, Trust Unit rights and
convertible debentures if completed at December 31.
AS AT DECEMBER 31
--------------------------------------------
($MILLIONS) 2004 2003 % Change
- --------------------------------------------------------------------------------------------------------
Total market capitalization (1) $ 970.2 $ 240.7 303%
Net debt 429.7 78.5 447%
- --------------------------------------------------------------------------------------------------------
Enterprise value (total capitalization) (2) $ 1,399.9 $ 319.2 339%
- --------------------------------------------------------------------------------------------------------
Net debt as a percentage of enterprise value (%) 31% 25% 24%
========================================================================================================
(1) Reflects conversion of exchangeable shares into Trust Units.
(2) Enterprise value as presented does not have any standardized meaning
prescribed by Canadian GAAP and therefore it may not be comparable with the
calculation of similar measures for other entities. Total capitalization is not
intended to represent the total funds we have received from equity and debt.
The increase in net debt as at December 31, 2004 compared to 2003 is primarily
the result of the Storm and EnCana acquisitions. Of the convertible debentures
outstanding at December 31, 2004, $6.6 million have converted into Units through
March 24, 2005 and we anticipate continued conversions through 2005.
CONTRACTUAL OBLIGATIONS
We have entered into the following contractual obligations:
MATURITY
-------------------------------------------------------------------------
LESS THAN
ANNUAL CONTRACTUAL OBLIGATION ($ THOUSANDS) TOTAL 1 YEAR YEARS 1 - 3 YEARS 4 - 5 AFTER 5 YEARS
- -----------------------------------------------------------------------------------------------------------------------
Short and long-term debt 376,019 75,519 -- -- 300,500
Interest on short and long-term debt 163,024 25,997 70,993 47,329 18,705
Interest on convertible debentures 10,008 2,176 6,527 1,305 --
Operating and premise leases 7,094 400 4,304 2,390 --
Transportation and storage commitments 99 35 39 25 --
Capital commitments 700 700 -- -- --
Asset retirement obligations 334,803 -- 729 3,648 330,426
- -----------------------------------------------------------------------------------------------------------------------
Total 891,747 104,827 82,592 54,697 649,631
- -----------------------------------------------------------------------------------------------------------------------
As at December 31, 2004, Harvest had entered into physical and financial
contracts for production with average deliveries of approximately 23,524 barrels
per day in 2005 and 12,500 barrels per day in 2006. We have also entered into
financial contracts to
15 EXHIBIT 99.3
------------
minimize our exposure to fluctuating electricity prices and the U.S./Canadian
dollar exchange rate. Please see Note 16 to the consolidated financial
statements for further details.
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
One of our directors and a corporation controlled by that director had advanced
$25 million to Harvest pursuant to the equity bridge notes as at December 31,
2003. On January 2, 2004 we paid $665,068 in accrued interest on these notes. On
January 26 and 29, 2004 we repaid the principal amount and paid $185,232 of
interest accrued since December 31, 2003. The notes were amended on June 29,
July 7 and July 9, 2004. These notes were then re-drawn by $30 million and
repaid as to $20 million on August 11, 2004 and $10 million on December 30,
2004. The notes accrued interest at 10% per annum, were secured by a fixed and
floating charge on the assets of Harvest and were subordinate to the interest of
the senior secured lenders pursuant to Harvest Operations' credit facility.
We had the option to settle the quarterly interest payments under the equity
bridge notes with cash or the issue of Trust Units. If we elected to issue Trust
Units, the number of Trust Units to be issued to settle a quarterly interest
payment would be the equivalent to the quarterly payment amount divided by 90%
of the most recent ten-day weighted average trading price. We had the option at
maturity of the notes to settle the principal obligation with cash or with the
issue of Trust Units. The terms to settle principal with units is the same as
with the interest option described above.
A corporation controlled by one of our directors sublets office space from us
and we provide administrative services to that corporation on a cost recovery
basis.
CAPITAL ASSET ADDITIONS
YEAR ENDED DECEMBER 31
----------------------------------------------
($MILLIONS) 2004 2003 % Change
- ---------------------------------------------------------------------------------------------------------
Land and undeveloped lease rentals $ 0.8 $ 0.1 700%
Geological and geophysical 0.5 0.2 150%
Drilling and completion 23.0 10.1 128%
Well equipment, pipelines and facilities 14.0 15.1 (7%)
Capitalized G&A expenses 3.6 1.3 177%
Furniture, leaseholds and office equipment 0.8 0.4 100%
- ---------------------------------------------------------------------------------------------------------
Total development capital asset
expenditures $ 42.7 $ 27.2 57%
Acquisitions $ 706.0 $ 108.7 549%
- ---------------------------------------------------------------------------------------------------------
Total capital asset expenditures $ 748.7 $ 135.9 451%
=========================================================================================================
2004
East Central Southern North Southeast
Alberta Alberta Central Saskatchewan
Alberta
2004 ACTUAL CAPITAL BY CORE AREA (%) 49 1 6 44
2005
East Central Southern North Southeast
Alberta Alberta Central Saskatchewan
Alberta
2005 BUDGETED CAPITAL BY CORE AREA (%) 30 28 18 24
Development expenditures excluding acquisitions totaled $8.8 million for the
three month period ended December 31, 2004, resulting in full year development
capital expenditures of $42.7 million. This compares to $27.2 million for the
full year 2003. Throughout 2004, our capital expenditures were dedicated to
ongoing optimization and development of existing assets, primarily in our
existing core areas. We drilled a total of 30.5 net wells in 2004, with a
success rate of 100%.
16 EXHIBIT 99.3
------------
Excluding acquisitions, we expect that 2005 development capital expenditures
will total approximately $75 million, and will be focused on production and
reserve additions, and operating efficiency programs. In 2005, the development
capital will be directed to the new areas including North Central Alberta and
Southern Alberta, with an ongoing focus applied to East Central Alberta and
Southeast Saskatchewan. As the development program progresses, we may reallocate
funds between areas based on results achieved, with the goal of achieving
optimal returns on capital investment. We do not anticipate being able to
maintain production at year end 2004 rates through 2005 with our planned 2005
capital program. We anticipate average production for the year to be between
34,000 and 36,000 BOE/d.
DISTRIBUTIONS TO UNITHOLDERS AND TAXABILITY
Distributions to Unitholders are financed with cash flow from operations. Since
inception, we have communicated our intention to pursue a strategy that will
allow us to sustain $0.20 per Unit per month in distributions. During 2004, we
paid $0.20 per Trust Unit for each month ($59.6 million) to Unitholders. This is
the same per Unit level paid to Unitholders through 2003 ($29.1 million). The
higher level of absolute distributions paid reflects a greater number of Units
outstanding following the August equity issue, as well as the ongoing conversion
of both the 9% and 8% series of convertible debentures. However, our payout
ratio has declined over the past two years, resulting in a 46% payout ratio in
the fourth quarter of 2004, compared to 75% in the same period in 2003. Retained
cash flow will continue to be used to fund debt repayment, capital development
investments and possible future acquisition opportunities.
THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31
------------------------------------- ------------------------------------
($MILLIONS EXCEPT PER TRUST UNIT AMOUNTS) 2004 2003 % Change 2004 2003 % Change
- ------------------------------------------ ------------ ----------- ------------ ------------ ------------ ----------
Cash distributions declared $ 24.8 $ 10.2 143% $ 64.6 $ 30.7 110%
Per Trust Unit 0.60 0.60 0% 2.40 2.40 0%
Taxability of distributions (%) N/A n/a - 100% 41% 144%
Per Trust Unit $ 2.40 $ 2.40 0% $ 2.40 $ 0.98 144%
Payout ratio (%) 46% 75% -39% 50% 66% -25%
- ------------------------------------------ ------------ ----------- ------------ -- ------------ ------------ ----------
Of the total distribution amount paid in 2004, $12.6 million was reinvested by
Unitholders through the issue of 0.8 million Trust Units under the Distribution
Reinvestment Plan ("DRIP"). This reflects 21% participation under the DRIP.
During 2005, management believes the DRIP will remain at levels similar to 2004.
Should the percentage decrease, we will need to use a larger amount of cash
flows to pay monthly distributions.
Our distributions paid to Unitholders in 2004 totaled $0.20 per Trust Unit per
month for an annual total of $2.40 per Trust Unit. However, we earned more
taxable income in 2004 than the amounts distributed to Unitholders. As a result,
all distributions paid in the year are 100% taxable. No amount of the
distributions is a return of capital. Our trust indenture requires that any
taxable income we earned in Harvest Energy Trust as an independent taxable
entity that exceeds the amount paid in distributions automatically becomes
payable to Unitholders. As a result of the excess taxable income earned in 2004,
our Unitholders will receive an additional allocation of taxable income of
$0.252 per unit, which is also 100% taxable. This amount will be reported as a
corresponding increase in taxable income shown on those Unitholders' T3 slips.
In settlement of this additional taxable income payable, Unitholders of record
on March 31, 2005 will receive an additional payment of Trust Units equal to
$0.252 per Unit. Trust Units will be valued as at December 31, 2004 for this
purpose, in accordance with the trust indenture. Applying the closing price of
the Trust Units on December 31, 2004 of $22.95, each Unitholder of record on
March 31, 2005 will receive 0.01098 of a Trust Unit per Trust Unit held on that
date in settlement of this incremental amount of taxable income. This payment,
representing the excess income, will be made concurrently with the distribution
payment to Unitholders on April 15, 2005.
Payments to U.S. Unitholders are subject to 15% Canadian withholding tax, which
applies to the taxable portion of the distribution. After consulting with our
U.S. tax advisors, we are of the view that 2004 distributions are "qualified
dividends" under the Jobs and Growth Tax Relief Reconciliation Act of 2003.
These dividends are eligible for the reduced tax rate applicable to long-term
capital gains. However, the distributions may not be qualified dividends in
certain circumstances, depending on the holder's personal situation (i.e. if an
individual holder does not meet a holding period test). Where the distributions
do not qualify, they should be reported as ordinary dividends. U.S. and other
non-resident Unitholders are urged to consult independent legal advice on how
their distributions should be treated for tax purposes.
17 EXHIBIT 99.3
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SENSITIVITIES
The table below indicates the impact of changes in key variables on several of
our financial measures. The figures in this table are based on the Units
outstanding as at December 31, 2004 and our existing commodity price risk
management program, and are provided for directional information only.
- ---------------------------------------------------------------------------------------------------------------------
VARIABLE
----------------------------------------------------------------------------------
WTI HEAVY OIL CRUDE OIL CANADIAN BANK FOREIGN EXCHANGE
PRICE RATE
PRICE/BBL DIFFERENTIAL/BBL PRODUCTION PRIME RATE U.S./CDN.
- ---------------------------------------------------------------------------------------------------------------------
Assumption $40.00 US $15.00 US 35,000 bbl/d 4.25% 1.21
Change (plus or minus) $1.00 US $1.00 US 1,000 bbl/d 1.00% 0.01
ANNUALIZED IMPACT ON:
Cash flow from operations ($000's) $4,630 $7,456 $12,370 $631 $2,399
Per Trust Unit, basic $0.12 $0.18 $0.29 $0.02 $0.06
Per Trust Unit, diluted $0.11 $0.17 $0.29 $0.02 $0.05
Payout ratio 1.4% 2.2% 3.7% 0.2% 0.7%
- ---------------------------------------------------------------------------------------------------------------------
As noted above, our commodity price risk management program can reduce
sensitivities due to the oil price derivatives executed under our risk
management program. Those contracts in place as at December 31, 2004 are
documented in the table below. The prices shown for collars, indexed puts and
participating swaps are floor prices. The nature of those instruments allows us
to participate in positive price movements above these levels, while providing
fixed price realizations if the market price drops below the floor price.
2005 2006
---------------------------------------------------------------------
VOLUME (BBLS/D) PRICING ($/BBL) VOLUME (BBLS/D) PRICING ($/BBL)
- ------------------------------------------------------------------------------------------------------
WTI Crude Oil Swaps 1,028 $ 23.12 - -
WTI Crude Oil Collars 3,996 $ 28.16 - -
WTI Indexed Put Contracts 18,500 $ 35.95 3,750 $ 34.00
WTI Participating Swaps - - 8,750 $ 38.16
- ------------------------------------------------------------------------------------------------------
EXAMPLE OF PRICE REALIZATIONS WITH "INDEXED PUT" COMMODITY DERIVATIVE CONTRACT
(7,000 BBL/D)
WTI MARKET PRICE HARVEST REALIZED PRICE
$ 25.00 $ 35.00
$ 26.00 $ 35.00
$ 27.00 $ 35.00
$ 28.00 $ 35.00
$ 29.00 $ 35.00
$ 30.00 $ 35.00
$ 31.00 $ 35.00
$ 32.00 $ 35.00
$ 33.00 $ 35.00
$ 34.00 $ 35.00
$ 35.00 $ 35.00
$ 36.00 $ 35.66
$ 37.00 $ 36.32
$ 38.00 $ 36.98
$ 39.00 $ 37.64
$ 40.00 $ 38.30
$ 41.00 $ 38.96
$ 42.00 $ 39.62
$ 43.00 $ 40.28
$ 44.00 $ 40.94
$ 45.00 $ 41.60
$ 46.00 $ 42.60
18 EXHIBIT 99.3
------------
$ 47.00 $ 43.60
$ 48.00 $ 44.60
$ 49.00 $ 45.60
$ 50.00 $ 46.60
$ 51.00 $ 47.60
$ 52.00 $ 48.60
$ 53.00 $ 49.60
$ 54.00 $ 50.60
$ 55.00 $ 51.60
The graph above shows the Harvest realized price plotted against a changing WTI
price. The white line is our realized price and the black line is the WTI price.
The floor is set at $35, so if WTI is below $35, we realize $35. For spot prices
above $35, we receive spot price less 34% of the difference between spot price
and $35, until WTI reaches $45, at which time we will realize the WTI price less
$3.40 at that price point and higher.
CRITICAL ACCOUNTING POLICIES
OIL AND NATURAL GAS ACCOUNTING
In accounting for oil and natural gas activities, we can choose to account for
our oil and natural gas activities using either the full cost or the successful
efforts method of accounting.
We follow the Canadian Institute of Chartered Accountants guideline 16, "Oil and
Gas Accounting - Full Cost" for the full cost method of accounting for our oil
and natural gas activities. All costs of acquiring oil and natural gas
properties and related exploration and development costs, including overhead
charges directly related to these activities, are capitalized and accumulated in
one cost centre. Maintenance and repairs are charged against income, and
renewals and enhancements that extend the economic life of the capital assets
are capitalized. Any gains or losses on disposition of oil and natural gas
properties are not recognized unless that disposition would alter the rate of
depletion by 20% or more. The provision for depletion and depreciation of
petroleum and natural gas assets is calculated on the unit-of-production method,
based on proved reserves before royalties as estimated by independent petroleum
engineers. The basis used for the calculation of the provision is the
capitalized costs of petroleum and natural gas assets plus the estimated future
development costs of proved undeveloped reserves. Reserves are converted to
equivalent units on the basis of six thousand cubic feet of natural gas to one
barrel of oil. The reserve estimates used in these calculations can have a
significant impact on net income, and any downward revision in this estimate
could result in a higher depletion and depreciation expense. In addition, a
downward revision of this reserve estimate could require an additional charge to
income as a result of the computation of the prescribed ceiling test calculation
under this guideline. Under this method of accounting, an impairment test is
applied to the overall carrying value of the capital assets for a Canada-wide
cost centre with reserves valued at estimated future commodity prices at period
end.
Under the successful efforts method of accounting, all exploration costs, except
costs associated with drilling successful exploration wells, are expensed in the
period in which they are incurred and costs are generated on a property by
property basis. Impairment is also determined on a property by property basis.
The difference between these two approaches is not expected to produce
significantly different results for us as the drilling activity we undertake is
of a low risk nature and success rates are high; however, each policy is likely
to generate a different carrying value of capital assets and a different net
income.
CRITICAL ACCOUNTING ESTIMATES
There are a number of critical estimates underlying the accounting policies
applied when preparing the consolidated financial statements due to timing
differences between when certain activities take place and when these activities
are reported on. Changes in these estimates could have a material impact on our
reported results.
RESERVES
The process of estimating reserves is complex. It requires significant judgments
and decisions based on available geological, geophysical, engineering and
economic data. In the process of estimating the economically recoverable oil and
natural gas reserves and related future net cash flows, we incorporate many
factors and assumptions such as:
o Expected reservoir characteristics based on geological, geophysical and
engineering assessments;
o Future production rates based on historical performance and expected future
operating and investment activities;
o Future oil and gas prices and quality differentials; and
19 EXHIBIT 99.3
------------
o Future development costs.
Reserve estimates impact net income through depletion, the determination of
asset retirement obligations and the application of an impairment test.
Revisions or changes in the reserve estimates can have either a positive or a
negative impact on net income, capital assets and asset retirement obligations.
The estimates in reserves impact many of our accounting estimates including our
depletion calculation. A decrease of reserves by 10% would result in an increase
of approximately $11 million in our depletion expense.
ASSET RETIREMENT OBLIGATIONS
In the determination of our asset retirement obligations, management is required
to make a significant number of estimates with respect to activities that will
occur in many years to come. In arriving at the recorded amount of the asset
retirement obligation numerous assumptions are made with respect to ultimate
settlement amounts, inflation factors, credit adjusted discount rates, timing of
settlement and expected changes in legal, regulatory, environmental and
political environments. The asset retirement obligation also results in an
increase to the carrying cost of capital assets. The obligation accretes to a
higher amount with the passage of time as it is determined using discounted
present values. A change in any one of the assumptions could impact the
estimated future obligation and in return, net income. It is difficult to
determine the impact of a change in any one of our assumptions. As a result, a
reasonable sensitivity analysis cannot be performed.
IMPAIRMENT OF CAPITAL ASSETS
In determining if the capital assets are impaired there are numerous estimates
and judgments involved with respect to our cash flow estimates. The two most
significant assumptions in determining cash flows are future prices and
reserves.
The estimates of future prices require significant judgments about highly
uncertain future events. Historically, oil and gas prices have exhibited
significant volatility. The prices used in carrying out our impairment test are
based on prices derived from a consensus of future price forecasts among
industry analysts. Given the significant assumptions required and the
possibility that actual conditions will differ, we consider the assessment of
impairment to be a critical accounting estimate.
If forecast WTI crude oil prices were to fall to a range between high U.S.$20 to
low U.S.$30 levels, the initial assessment of impairment indicators would not
change; however, below that level, we would likely experience an impairment.
Although, oil and natural gas prices fluctuate a great deal in the short-term,
they are typically stable over a longer time horizon. This mitigates potential
for impairment.
Any impairment charges would reduce our net income.
It is difficult to determine and assess the impact of a decrease in our proved
reserves on our impairment tests. The relationship between the reserve estimate
and the estimated undiscounted cash flows is complex. As a result, we are unable
to provide a reasonable sensitivity analysis of the impact that a reserve
estimate decrease would have on our assessment of impairment.
CHANGES IN ACCOUNTING POLICY
ASSET RETIREMENT OBLIGATIONS
In December 2002, the CICA issued Handbook Section 3110, "Asset Retirement
Obligations". This standard requires recognition of a liability representing the
fair value of the future retirement obligations associated with capital assets.
This fair value is capitalized and amortized over the same period as the
underlying asset. The standard is effective for all fiscal years beginning on or
after January 1, 2004. See Notes 3 and 7 to our consolidated financial
statements.
HEDGING RELATIONSHIPS
In November 2002, the CICA published an amended Accounting Guideline 13,
"Hedging Relationships". The guideline establishes conditions where hedge
accounting may be applied. It is effective for years beginning on or after July
1, 2003. The guideline impacted our net income and net income per Trust Unit, as
certain financial instruments for oil and natural gas do not qualify for hedge
accounting. See Note 16 to our consolidated financial statements. Where hedge
accounting does not apply, any changes in the fair values of the financial
instruments relating to a period can either reduce or increase net income for
that period. We adopted this standard January 1, 2004, which has resulted in a
reduction in our pretax income of $11.3 million. At October 1, 2004, we ceased
hedge accounting for all of our derivative instruments.
20 EXHIBIT 99.3
------------
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 "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, foreign currency, and unrealized gains or 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.
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 do not expect this guideline
to have a material impact on our consolidated financial statements.
FINANCIAL INSTRUMENTS
The CICA Handbook Section 3860 "Financial Instruments - Disclosure and
Presentation" has been amended to provide guidance for classifying certain
financial instruments that embody obligations that may be settled by the
issuance of the issuer's equity shares as debt when the instrument that embodies
the obligations does not establish an ownership relationship. As a result of
this amendment, the convertible debentures will be reclassified from equity to
debt, with possibly a small portion representing the value of the conversion
feature remaining in equity. At this time, management has not fully assessed the
allocation, if any, between debt and equity. The mandatory effective date for
the amendment is for fiscal years beginning on or after November 1, 2004.
OPERATIONAL AND OTHER BUSINESS RISKS
Our financial and operating performance is subject to risks and uncertainties
which include, but are not limited to: operational risk, reserve risk, commodity
price risk, financial risk, environmental, health and safety risk, regulatory
risk, and other risk specifically discussed previously in this MD&A. We intend
to continue executing our business plan to create value for Unitholders by
paying stable monthly distributions and increasing the net asset value per Trust
Unit. All of our risk management activities are carried out under policies
approved by the Board of Directors of Harvest Operations Corp., and are intended
to mitigate the risks noted above as follows:
Operational risk associated with the production of oil and natural gas:
o Applying a proactive management approach to our properties;
o Selectively adding skilled and experienced employees and providing
encouragement and opportunities to maintain and improve technical competence;
and
o Remunerating employees with a combination of average industry salary and
benefits combined with a merit based bonus plan to reward success in
execution of our business plan.
21 EXHIBIT 99.3
------------
Reserve risk with respect to the quantity of recoverable reserves:
o Acquiring oil and natural gas properties that have high-quality reservoirs
combined with mature, predictable and reliable production and thus reduce
technical uncertainty;
o Subjecting all property acquisitions to rigorous operational, geological,
financial and environmental review; and
o Pursuing a capital expenditure program to reduce production decline rates,
improve operating efficiency and increase ultimate recovery of the
resource-in-place.
Commodity price risk, arising from fluctuations in oil and natural gas prices
due to market forces:
o Maintaining a risk-management policy and committee to continuously review
effectiveness of existing actions, identify new or developing issues and
devise and recommend to the Board of Directors of Harvest Operations Corp.
action to be taken;
o Maintaining a program to manage variability in commodity prices and
electricity costs utilizing swaps, collars and option contracts with a
portfolio of credit-worthy counterparties; and
o Maintaining a low cost structure to maximize product netbacks.
Financial risk, such as volatility in equity markets, foreign exchange rates,
interest rates, price differentials, credit risk and ability to meet debt
service obligations:
o Monitoring financial markets to ensure the cost of debt and equity capital is
kept as low as reasonably possible;
o Retaining up to 50% of the cash available for distribution to finance capital
expenditures and future property acquisitions;
o Monitoring our financial position and foreign exchange markets with the
intent of taking steps necessary to minimize the impact of fluctuations in
foreign currency exchange rates;
o Comparing actual financial performance against pre-determined expectations
and making changes where necessary; and
o Carrying adequate insurance to cover property and business interruption
losses.
Environmental, health and safety risk associated with well and production
facilities:
o Adhering to our safety program and keeping abreast of current industry
practices;
o Committing funds on an ongoing basis, toward the remediation of potential
environmental issues; and
o Accumulating sufficient cash resources to pay for future asset retirement
costs.
Regulatory risk arising from changing government policy risks, including
revisions to royalty legislation, income tax laws, and incentive programs
related to the oil and natural gas industry:
o Retaining an experienced, diverse and actively involved Board of Directors to
ensure good corporate governance; and
o Engaging technical specialists when necessary to advise and assist with the
implementation of policies and procedures to assist in dealing with the
changing regulatory environment.