EXHIBIT 1
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Harvest Energy Trust
Going Against the Grain
2004 Annual Report
CORPORATE PROFILE
Harvest Energy Trust is a Calgary-based energy royalty trust that was formed in
July of 2002, and trades on the Toronto Stock Exchange (TSX) under the symbol
HTE.UN.
Harvest is focused on acquiring high-quality, mature properties where the
production of crude oil, natural gas and natural gas liquids can be
significantly increased and extended by Harvest's "hands-on" operating strategy.
Harvest retains a significant portion of its cash flow to fund future growth in
the form of both internal capital projects and accretive acquisitions. This
strategy has allowed Harvest to grow to its present size in just over two years.
Under this progressive approach, the technically focused team at Harvest seeks
to maximize the value of every barrel by achieving higher ultimate production
and resource recovery, to further the ultimate goal of stable distributions to
Unitholders.
NOTICE OF MEETING
The Annual Meeting of the Unitholders of Harvest Energy Trust will be held on
May 4, 2005 at 3:00 pm in the Lecture Theatre Room at the Metropolitan Centre
located at 333 - 4th Avenue SW in Calgary, Alberta. All Unitholders and
interested parties are invited to attend.
NOTE: All figures in this annual report are in Canadian dollars, unless
otherwise indicated.
FORWARD-LOOKING STATEMENT DISCLAIMER
The following disclosure contains forward-looking information and estimates with
respect to Harvest. This information addresses future events and conditions, and
as such involves risks and uncertainties that could cause actual results to
differ materially from those contemplated by the information provided. These
risks and uncertainties include but are not limited to factors intrinsic in
domestic and international politics and economics, general industry conditions
including the impact of environmental laws and regulations, imprecision of
reserves estimates, fluctuations in commodity prices, interest rates or foreign
exchange rates and stock market volatility. The information and opinions
concerning the Trust's future outlook are based on information available at
March 2005.
GOING AGAINST THE GRAIN
Our approach to value creation and our willingness to "go against the grain"
makes Harvest a unique investment opportunity. We, at Harvest, make business
decisions that are based on sound principles of creating the greatest long-term
value for our Unitholders from our oil and natural gas operations, while always
attempting to prudently remove uncertainty. We have the vision to see
opportunities that others may not, and the courage to challenge conventional or
traditional ways of doing things, which may destroy Unitholder value.
Our achievements in the past three years demonstrate the power of Harvest's
strategy and the value of our focus, flexibility and commitment to creating
sustainable value for our Unitholders.
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2002 2003 2004
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Proved plus probable reserves per unit (reserves per unit) 1.28 1.82 2.27
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2002 2003 2004
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Proved plus probable reserve life index (years) 4.2 6.4 7.9
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2004 PERFORMANCE
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2002 2003 2004
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Average Daily Production (BOE/d) 4,307 11,040 23,019
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2002 2003 2004
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Proved plus probable reserves (MMBOE) 12.9 33.0 102.5
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2002* 2003 2004
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Payout Ratio (%) 20 66 50
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2002 2003 2004
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Field Netbacks ($/BOE)** 18.00 16.61 24.41
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2002 2003 2004
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Net Revenue ($/BOE) 26.94 25.55 32.89
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* Reflects cash flow for period ended December 31, but distributions only for
the month of December following the initial public offering.
** Before gains or losses on commodity derivatives.
HIGHLIGHTS
THREE MONTHS ENDED DECEMBER 31 TWELVE MONTHS ENDED DECEMBER 31
FINANCIAL ($000S EXCEPT WHERE NOTED) 2004 2003 % Change 2004 2003 % Change
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(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
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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%
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Total (BOE/d)(1) 37,024 14,858 149% 23,019 11,040 109%
=================================================================================================================================
OPERATING NETBACK(5) ($/BOE)
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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%)
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Operating netback(5) $ 19.26 $ 12.79 51% $ 17.94 $ 11.94 50%
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(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.
From the IPO in December, 2002 to December 31, 2004, Harvest has delivered a
total return to Unitholders of 317%. In 2004, Harvest's total return was 88%.
LETTER TO UNITHOLDERS
On behalf of the Harvest team, we are pleased to report on the Trust's activity
during 2004 and discuss our strategy for 2005 and beyond.
From inception, Harvest has chosen a unique and sometimes challenging route to
create maximum sustainable value for our Unitholders. This has included working
with perceived shorter reserve life assets when long reserve life was viewed as
more appropriate, having an oil focus when the apparent commodity of choice was
natural gas, and maintaining a lower payout ratio when the norm was to
distribute 100% or more of cash flow. Today, trusts are increasingly acquiring
shorter life assets, crude oil has performed well as a commodity, and most
trusts have lowered their payout ratio to 75% or less. We believe Harvest's
results to date validate our strategy and demonstrate our willingness to "go
against the grain" in pursuit of better returns for our Unitholders.
FOCUSED OIL AND NATURAL GAS OPERATIONS - HARVEST'S BUSINESS MODEL
Fundamentally, Harvest is an oil and natural gas production company with
expertise in managing mature assets. Since inception, our underlying philosophy
and business strategies have been focused on creating Unitholder value by
undertaking quality property acquisitions, low-risk development and efficient
operations. However, Harvest looks quite different today than when we went
public in December 2002. In the span of just over 24 months, Harvest's reserves,
reserves per unit, production and reserve life index have grown significantly.
Our product mix is more diversified due to additional light crude oil and
natural gas, and our netbacks have strengthened. The market capitalization of
Harvest has risen 1,100% since our initial public offering, and in 2004 we
further enhanced our capital structure by entering the U.S. debt market.
FUTURE SUSTAINABILITY
The foundation of Harvest's business model is a commitment to long-term
sustainability. By targeting a low payout ratio, Harvest has access to
undistributed cash flow to repay debt, fund our capital development program, or
take advantage of acquisition opportunities.
SUSTAINABILITY THROUGH PROPERTY ENHANCEMENT
Our business is based on the successful production and exploitation of mature
oil and natural gas properties. Through activities such as low risk development
drilling, ongoing optimization and property enhancement projects, we strive to
maximize production and reserves. Harvest's skilled and innovative technical
team seeks new ways to improve efficiency and reduce operating expenses. This
contributes to increased cash flow, and can also extend the life of our reserves
by making our wells economic for a longer period of time. Our sustainability is
further supported by retaining a higher proportion of our cash flow, which
enables us to fund these activities without necessarily issuing Trust Units and
diluting existing Unitholders.
SUSTAINABILITY THROUGH ACCRETIVE ACQUISITIONS
When pursuing acquisitions, we focus on properties that can offer the greatest
rate of return on our investment. This often includes producing properties with
large accumulations of oil or natural gas in place, and high quality reservoirs.
We do not turn away from assets that have a shorter reserve life or produce
heavier gravity crude oil, because these assets can often be acquired at more
favorable values, further contributing to higher returns. Given Harvest's
ability to effectively manage mature assets, our focus is strictly on value
potential and rate of return, rather than less relevant, specific asset
characteristics.
Harvest made two sizeable and strategically important acquisitions in 2004, both
of which were accretive to cash flow, net asset value, production and reserves
per unit. In June, Harvest acquired assets in North Central Alberta for $192.2
million, resulting in a production increase of 25% and the creation of a new
core area. Shortly thereafter, we announced our largest transaction to date: a
$511 million acquisition of assets in East Central and Southern Alberta. These
transactions support Harvest's future sustainability by expanding our asset base
with additional, high quality production and reserves, increasing our inventory
of drilling and property enhancement projects, expanding our existing East
Central core area, and creating a new core area in Southern Alberta. Development
work on all of our new properties was initiated immediately, and remains a focal
point for our 2005 capital program.
Going forward, Harvest will pursue opportunities to complete smaller
acquisitions within our existing core areas, and continue to evaluate non-core
asset dispositions by large conventional producers in Western Canada.
CAPITAL STRUCTURE
Successful trusts are able to acquire, develop and manage assets, while
accessing low-cost sources of capital to finance those activities. Harvest
accomplishes this, in part, by retaining a portion of our cash flow for
strengthening our balance sheet and reinvesting in our properties. If necessary,
retained cash flow can be supplemented with external capital such as equity, or
appropriate amounts of debt to finance acquisitions and development. In the fall
of 2004, Harvest entered the U.S. capital markets with the issuance of U.S.$250
million of long-term senior notes, bearing interest at 7 7/8%. We anticipate
this move
will provide Harvest with a sizeable new source of long-term, low-cost capital
that we can access to help fund our growth plans. We believe our capital
structure is appropriate given our low payout ratio and strong risk management
practices.
RISK MANAGEMENT
Harvest's risk management activities are designed to reduce the negative impact,
where practical, of external factors on our operational and financial
performance. Hedging is an important element of our strategy, designed to
provide `insurance' against extreme commodity price volatility. Harvest's
approach to hedging has evolved through the use of different types of
derivatives. For example, the derivative contracts in place through 2004 were
primarily swaps, which secured a higher floor price, but did not allow much
participation in strengthening crude oil price markets. The majority of these
hedges expired at the end of 2004. For 2005 and 2006, a significant portion of
Harvest's oil volumes are hedged using innovative derivative structures such as
indexed puts. These structures provide us with confidence in our cash flows
should oil prices decline below certain levels, but also provide us with the
opportunity to participate in upward oil price movements.
THE POWER OF PEOPLE
Harvest's people are an integral part of our organization. We have assembled an
experienced, skilled and committed team capable of evaluating, acquiring,
optimizing and operating mature properties. From our independent Board of
Directors to each individual employee, we are all dedicated to the ongoing
success of Harvest.
LOOKING AHEAD
We will continue to execute our strategy of maximizing the value of every
barrel, while delivering stable distributions to Unitholders. In 2005, our
capital development program will focus on low risk drilling, optimization and
cost reduction activities which have proven effective in the past. We will
continue building our inventory of property enhancement projects to provide for
further development of our assets in the future. We will also pursue accretive
acquisitions that meet our stringent criteria, and which expand our interests in
existing core areas, or establish new core areas.
In the context of the broader market, oil prices are expected to remain robust
in 2005 and 2006, relative to historical levels. Heavy oil differentials and
currency exchange rates appear to have stabilized at or near current levels.
Through 2005, Harvest's crude oil and exchange rate hedges, as well as our U.S.
dollar denominated senior notes, provide significant protection from oil price
and currency movements. We have also hedged a significant portion of our crude
oil volumes in 2006. As a result of these hedges and our low payout ratio,
Harvest is well positioned to weather significant changes to commodity prices or
other external uncertainties, while continuing to deliver reliable
distributions.
In mid-April 2005, Harvest will distribute its 28th consecutive cash
distribution of $0.20 per unit per month. We are committed to sustaining or
increasing our monthly distributions.
We wish to thank every Harvest employee for their dedication, enthusiasm and
tireless efforts. Each member of our valued team has contributed to Harvest's
success. We also want to express our appreciation to our Unitholders for their
continued support of Harvest's strategy and confidence in our vision. We look
forward to reporting on our continued growth in 2005.
On behalf of Management
JACOB ROORDA
PRESIDENT
March 24, 2005
OPERATIONS REVIEW
Harvest focuses on the operation of high quality, mature properties using a
simple and straight forward approach. Harvest's value creation strategy involves
acquiring under-managed, legacy properties with high working interests at
reasonable prices and then employing hands-on management and diligent
operational practices to extract maximum value.
Production optimization is a hallmark of Harvest's success and is achieved by
controlling operating and power costs, as well as processing and disposal
infrastructure, maintaining a dominant land position in our core areas,
utilizing our expertise in fluid handling and encouraging our employees to think
`outside the box'. Harvest's unique marketing arrangements help to effectively
enhance our cash flow.
Harvest has four core areas of operation: East Central Alberta, Southeast
Saskatchewan, North Central Alberta and Southern Alberta.
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EAST CENTRAL NORTH CENTRAL SOUTHERN TOTAL OF ALL
AB SE SK AB ALBERTA AREAS
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PRODUCTION (1)
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Crude oil 13,378 5,496 3,166 8,219 30,259
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Natural gas 3,098 271 702 23,626 27,697
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NGL 62 78 160 566 866
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Total BOE 13,956 5,619 3,443 12,723 35,741
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85%-90% 98% 50% 85% 85%
AVERAGE WI (%)
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OPERATORSHIP (%) 90% 99% 75% 100% 90%
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RESERVES (P+P)
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Crude oil (mmbbl) 34.9 17.5 9.7 23.9 86.0
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Natural gas (bcf) 7.2 1.4 7.2 67.3 83.1
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NGL (mmbbl) 0.2 0.3 0.4 1.7 2.6
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Total BOE (mmBOE) 36.3 18.0 11.3 36.8 102.5
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OPERATING COSTS ($/BOE)(1) $9.09 $10.08 $5.08 $5.21 $7.49
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AVERAGE ROYALTY (%)(1) 13.2% 20.3% 20.5% 17.6% 16.7%
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(1) Data as at March 2005. Columns may not add due to rounding.
EAST CENTRAL ALBERTA
Harvest's targeted entry into the East Central Alberta area was driven by
strategy and an obvious value creation opportunity. The area has provided
ongoing quality acquisition opportunities, as senior producers continue to turn
their attention to natural gas opportunities located elsewhere. Harvest's East
Central core area consists of 14 properties, which are currently producing
approximately 14,000 BOE/d including the most recent additions which took place
in September 2004. Situated along proven geological trends, these large,
original oil-in-place fields offer superior reservoir quality, modern facilities
and a history of reserve accretion. Harvest plans to continue with basic oil
field fluid handling and production optimization, efficiency improvements, and
operating cost reduction activities designed to expand cash flow and extend the
reserve life, leading to further value creation in this area. Projects that are
successful at one property can generally be applied to similar properties
elsewhere with positive results.
Harvest focuses on efficient water handling and power reduction activities in
East Central Alberta because a significant portion of the area's operating costs
are power-related. Drilling low-pressure water disposal wells, plus the
extensive use of power hedges, have significantly managed power costs in this
area. As a result, Harvest has been successful in generating strong cash flows,
high rates of return and quick paybacks.
SOUTHEAST SASKATCHEWAN
With the October 2003 acquisition of light crude oil assets in Southeast
Saskatchewan, Harvest has demonstrated success in applying its exploitation and
optimization expertise across different geographic areas, geological zones and
product types. Harvest now dominates the Tilston trend in Southeast
Saskatchewan, and has been able to apply operational techniques and concepts in
this area that are similar to those used in East Central Alberta. Harvest's
extensive proprietary 3-D seismic coverage also provides a strategic advantage
for maintaining control of drilling opportunities and growing the area's
production base.
Production in Southeast Saskatchewan has increased from approximately 5,000
BOE/d in October 2003 to approximately 5,600 BOE/d currently, primarily due to
Harvest's drilling and water handling efforts. Future development will include
step-out and horizontal infill drilling to further exploit new pools and
increase drainage and recovery factors. The high quality production, strategic
control through area domination, and a deep inventory of development
opportunities have contributed to Southeast Saskatchewan becoming a key asset
within Harvest's portfolio.
NORTH CENTRAL ALBERTA
In June of 2004, Harvest acquired light oil properties located in the Red Earth
region of North Central Alberta. These assets present a good value opportunity
for Harvest as they offer high netbacks, stable production profiles, low
operating expenses, a longer reserve life, and future development opportunities.
We also see opportunities for future acquisitions in this area.
Harvest will target expanded waterflood and depletion of the underexploited
Slave Point G pool and additional step-out or infill wells will target the
prolific Granite Wash sands. Optimization projects such as injector well
conversions, recompletions, and pump upgrades are budgeted to increase well
productivity. Current production in the North Central area is approximately
3,400 BOE/d of high quality, light gravity crude oil from the Slave Point and
Granite Wash formations.
SOUTHERN ALBERTA
Harvest's Southern Alberta core area was formed following the acquisition of
assets in September 2004. Properties in the area include Suffield, Crossfield,
Badger and Cavalier, and at year-end 2004 were collectively producing
approximately 12,700 BOE/d. Harvest realized further diversification of our
product mix with the addition of our first significant natural gas production at
Crossfield and Cavalier.
The area offers large accumulations of original resource- in-place reservoirs
situated along proven geological trends at Cavalier, Suffield and Crossfield.
Exploitation and development strategies successfully employed in Harvest's East
Central Alberta area and elsewhere can be applied in Southern Alberta. With
numerous development and optimization opportunities, and a large drilling
inventory, Southern Alberta will be a focal point for Harvest in 2005 and
beyond.
RESERVES DISCLOSURE
All of the evaluations and the data provided herein are in accordance with
National Instrument 51-101, except where noted. McDaniel & Associates evaluated
approximately 77% of the total reserves, primarily in Harvest's East Central and
North Central Alberta properties. Gilbert Laustsen Jung Associates evaluated
approximately 17% of Harvest's reserves, consisting of the new Southern Alberta
properties acquired in September. Paddock Lindstrom & Associates evaluated
approximately 6% of the total reserves, consisting of a portion of the North
Central Alberta properties acquired in June, 2004. McDaniel's pricing forecasts
were used in all reserve evaluations. The information and tables listed below
constitute a summary of the three separate reserve reports. Further reserves
information is available in Harvest's Annual Information Form filed on SEDAR and
available on Harvest's website. Reserves data presented below is net of
abandonment costs.
RESERVES SUMMARY - FORECAST PRICES AND COSTS AS AT DECEMBER 31, 2004
RESERVES
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LIGHT AND MEDIUM OIL HEAVY OIL NATURAL GAS
-------------------- --------- -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf)
PROVED
Developed Producing 26,385.8 23,679.3 29,355.3 26,635.9 56,887.4 50,464.8
Developed Non-Producing 356.6 331.9 0 0 5,649.7 5,426.4
Undeveloped 2,698.6 2,416.3 3,374.5 2,923.7 1,953.6 1,328.7
-------- -------- -------- -------- -------- --------
TOTAL PROVED 29,441.0 26,427.5 32,729.8 29,559.6 64,490.7 57,219.9
-------- -------- -------- -------- -------- --------
PROBABLE 8,397.7 7,679.9 15,446.9 13,849.4 18,660.2 16,474.6
-------- -------- -------- -------- -------- --------
TOTAL PROVED PLUS PROBABLE 37,838.7 34,107.4 48,176.7 43,409.0 83,150.9 73,694.5
======== ======== ======== ======== ======== ========
RESERVES
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NATURAL GAS LIQUIDS TOTAL OIL EQUIVALENT
------------------- --------------------
GROSS NET GROSS NET
RESERVES CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe)
- ----------------- ------ ------ ------ ------
PROVED
Developed Producing 1,979.5 1,755.4 67,201.8 60,481.4
Developed Non-Producing 82.2 72.0 1,380.4 1,308.3
Undeveloped 63.5 60.0 6,462.2 5,621.5
------- ------- -------- --------
TOTAL PROVED 2,125.2 1,887.4 75,044.5 67,411.1
------- ------- -------- --------
PROBABLE 512.8 463.0 27,467.4 24,738.1
------- ------- -------- --------
TOTAL PROVED PLUS PROBABLE 2,638.0 2,350.4 102,511.9 92,149.2
======= ======= ========= ========
(1) "Gross" reserves means the total working and royalty interest share of
Harvest's remaining recoverable reserves before deductions of royalties payable
to others.
(2) "Net" reserves means Harvest's gross reserves less all royalties payable to
others.
(3) Oil equivalent amounts have been calculated using a conversion rate of six
thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading,
particularly if used in isolation. This 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.
2004 RESERVE LIFE INDEX
Harvest calculates its reserve life index by dividing the total reserves by the
forecast 2005 production for that category as reported in the reserve engineer's
evaluation report.
Proved Producing: 5.7
Total Proved: 6.2
Total Proved plus Probable: 7.9
NET PRESENT VALUE OF RESERVES - FORECAST PRICES AND COSTS AS AT DECEMBER 31, 2004
NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year) (1)
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0% 5% 10% 15% 20%
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
- ----------------- ------ ------ ------ ------ ------
PROVED
Developed Producing 1,145,401.6 948,487.3 820,000.6 728,640.9 659,768.4
Developed Non-Producing 35,851.3 25,399.5 19,697.4 16,136.0 13,691.1
Undeveloped 103,879.8 77,550.3 60,364.4 48,400.8 39,649.2
----------- ----------- ----------- --------- ---------
TOTAL PROVED 1,285,132.7 1,051,437.1 900,062.4 793,177.7 713,108.7
----------- ----------- ----------- --------- ---------
PROBABLE 447,590.0 310,111.9 232,424.1 183,027.1 149,083.9
----------- ----------- ----------- --------- ---------
TOTAL PROVED PLUS PROBABLE 1,732,722.7 1,361,549.0 1,132,486.5 976,204.8 862,192.6
=========== =========== =========== ========= =========
NOTES TO RESERVES DATA TABLES:
(1) The Trust is entitled to deduct from its income all amounts which are paid
or payable by it to Unitholders in a given financial year. As a result of
amounts paid and payable to Unitholders in the course of the most recent
financial year, the Trust is not liable for any material amount of income tax on
income. The net present values of future net revenue after income taxes are,
therefore, the same as the net present values of future net revenue before
income taxes.
(2) Columns may not add due to rounding.
(3) The crude oil, natural gas liquids and natural gas reserve estimates
presented in the Reserve Report are based on the definitions and guidelines
contained in the COGE Handbook.
2004 RECONCILIATION OF GROSS RESERVES BY PRINCIPAL PRODUCT TYPE USING FORECAST PRICES AND COSTS AS AT DECEMBER 31, 2004
PROVED
TOTAL PLUS
TOTAL PROVED PROVED + PROBABLE PROVED PROBABLE
OIL HVY OIL GAS NGL OIL HVY OIL GAS NGL
MBBL MBBL MMCF MBBL MBBL MBBL MMCF MBBL MBOE MBOE
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31-Dec-03 19,252 7,511 1,988 122 23,869 8,564 2,699 154 27,216 33,037
Revisions 3,741 1,572 1,281 258 4,062 2,179 1,818 319 5,784 6,862
New Adds 1,405 162 52 -- 2,159 189 64 -- 1,576 2,358
Acquisitions 9,521 26,594 65,161 1,917 12,227 40,354 82,561 2,337 48,893 68,679
Dispositions -- -- -- -- -- -- -- -- -- --
Production (4,478) (3,109) (3,991) (172) (4,478) (3,109) (3,991) (172) (8,424) (8,424)
31-Dec-04 29,441 32,730 64,491 2,125 37,839 48,177 83,151 2,638 75,044 102,512
================================================================================================================
NOTE:
A 2004 reconciliation of net reserves, compliant with NI 51-101, is available in
Harvest's 2004 Annual Information Form filed on SEDAR.
SUMMARY OF MCDANIEL & ASSOCIATES CONSULTANTS LTD. PRICING AND INFLATION RATE ASSUMPTIONS AS OF JANUARY 1, 2005
FORECAST PRICES AND COSTS
OIL
--------------------------------------------------------
NATURAL
SASK GAS
ALBERTA CROMER NATURAL LIQUIDS
ALBERTA BOW RIVER MEDIUM GAS EDMONTON U.S./
WTI EDMONTON HEAVY MEDIUM CRUDE ALBERTA COND. AND CAN
CRUDE OIL LIGHT CRUDE OIL CRUDE OIL OIL AECO SPOT NATURAL INFLATION EXCHANGE
($US/ CRUDE OIL ($CDN/ ($CDN/ ($CDN/ PRICE GASOLINES RATES (1) RATE(2)
YEAR BBL) ($CDN/ BBL) BBL) BBL) BBL) ($CDN/ GJ) ($CDN/ BBL) (%/YEAR) ($US/$CDN)
---- ---- ----------- ---- ---- ---- ---------- ----------- -------- ----------
Forecast
2005 42.00 49.60 29.40 37.00 43.50 6.45 50.40 2.0 0.830
2006 39.50 46.60 29.90 37.10 40.90 6.20 47.40 2.0 0.830
2007 37.00 43.50 27.90 34.60 38.20 6.05 44.30 2.0 0.830
2008 35.00 41.10 26.30 32.70 36.00 5.80 41.90 2.0 0.830
2009 34.50 40.50 25.90 32.20 35.50 5.70 41.30 2.0 0.830
FINDING AND DEVELOPMENT (F&D) COSTS
TOTAL PROVED PROVED PLUS PROBABLE
------------ --------------------
2004 2003 2004 2003
---- ---- ---- ----
Development capital expenditures ($000s) 42,662 27,209 42,662 27,209
Net change from previous year's future development
capital (2,784) 5,372 (4,407) 21,601
- -----------------------------------------------------------------------------------------------------------
Total capital including net change in future development 39,878 32,581 38,255 48,810
capital ($000s)
Reserve additions (mBOE) 7,360 4,207 9,220 2,684
F&D COST ($/BOE) $5.42 $12.14 $4.15 $11.60
- -----------------------------------------------------------------------------------------------------------
FINDING, DEVELOPMENT AND ACQUISITION (FD&A) COSTS
2004 2003 2004 2003
---- ---- ---- ----
Including effect of acquisitions
Capital expenditures ($000s) 748,662 135,900 748,662 135,900
Net change from previous year's future development
capital 67,865 5,372 114,566 21,601
- -----------------------------------------------------------------------------------------------------------
Total capital including net change in future development 816,527 141,272 863,228 157,501
capital ($000s)
Reserve additions (MBOE) 56,252 19,458 77,900 23,702
FD&A COST ($/BOE) $14.51 $7.26 $11.08 $6.65
- -----------------------------------------------------------------------------------------------------------
RESERVE RECYCLE RATIO CALCULATION
TOTAL PROVED PROVED PLUS PROBABLE
------------ --------------------
2004 2003 2004 2003
---- ---- ---- ----
Average field netback ($/BOE) $24.17 $16.22 $24.17 $16.22
- -----------------------------------------------------------------------------------------------------------
F&D Cost ($/BOE) $5.42 $12.14 $4.15 $11.60
F&D Reserve recycle ratio 4.5 1.3 5.8 1.4
- -----------------------------------------------------------------------------------------------------------
FD&A cost ($/BOE) $14.51 $7.26 $11.08 $6.65
FD&A Reserve Recycle ratio 1.7 2.2 2.2 2.4
- -----------------------------------------------------------------------------------------------------------
CORPORATE GOVERNANCE
Harvest recognizes the importance of sound corporate governance. We are
committed to conducting all of our affairs based on a foundation of trust,
integrity and ethical behavior. As stewards of the Trust, the Board of Directors
and senior executive team are capable and empowered to ensure that the interests
of all stakeholders are appropriately balanced against the strategies and
over-arching principles of the Trust.
Strong corporate governance is much more than a set of rules to follow; it is
the foundation of our business and a key to enhancing the performance of the
Trust.
Harvest's corporate structure and governance principles have been designed to
ensure that Unitholders' interests are addressed while maintaining structural
simplicity, transparency, and aligned interests. The Board consists of
independent, non-executive directors, all of whom have extensive industry
experience. Four specific Board committees have been established to ensure
maximum efficiency and effectiveness: the Audit Committee, the Corporate
Governance Committee, the Compensation Committee, and the Reserves, Safety and
Environment Committee. Each committee includes directors who possess the
relevant skills and knowledge needed to execute the committee's mandate.
As the corporate and regulatory landscape continues to change, Harvest's
corporate governance practices will grow and evolve accordingly. We currently
comply with the existing corporate governance guidelines for Canadian issuers.
Nevertheless we are committed to evolve the responsibilities of the committees
to ensure their mandates will meet or exceed changes to corporate governance
guidelines which may occur in the future. In 2006, Harvest plans to be in
compliance with the relevant internal control and disclosure certification
requirements of the U.S. Sarbanes-Oxley Act. This process will benefit Harvest's
Unitholders as it formalizes our commitment to implement processes and controls
that promote sound business practices at all levels of the Trust.
SUSTAINABLE DEVELOPMENT
Harvest is committed to sustainable development and to meeting the highest
possible standards of care for the environment, the health and safety of our
employees and residents of communities in which we operate.
As operators of mature oil and natural gas properties, our commitment to excel
in the area of environment, health and safety (EH&S) is an important strategic
element of Harvest's business model. We employ best practices in all operational
areas to comply with relevant regulations and guidelines, and to ensure the
highest quality of work. Our team applies sound operational practices, and we
are always striving to improve our techniques and processes. For Harvest,
standards are not viewed as targets to be reached, but as levels to be exceeded.
As part of our Stewardship initiative, Harvest maintains internally-developed
management programs to deal with environmental, abandonment and reclamation
issues, which are funded on an ongoing basis as required. These programs are
directed by dedicated professionals who have the relevant regulatory and
compliance expertise, and can help us to better understand the abandonment and
site reclamation responsibilities for each of our properties. We identify
potential deficiencies in our operations via field tours and well file reviews,
and have implemented a Compliance Tracker Program to provide ongoing status
reports on the Trust's overall compliance with environmental, health, safety,
and regulatory requirements.
Harvest's positive safety record reflects our commitment to training and
building the knowledge base of our employees and our genuine concern for their
safety and well-being. In 2004, Harvest's management implemented an Award of
Excellence program to recognize field staff who excel in integrating the
concepts of environmental responsibility, regulatory compliance, and health and
safety into our everyday business.
Harvest is a member of the Canadian Association of Petroleum Producers (CAPP)
and is enrolled at a platinum level status under CAPP's Stewardship program.
This means we will conduct regular compliance audits of our safety program, and
will track and monitor our Green House Gas (GHG) emissions as part of our
Stewardship process.
Harvest realizes that our impact extends beyond the field or the boardroom, and
we strive to make a positive impact on communities in which we are active.
Consistent with the premise of sustainable development, we truly believe that we
can meet the needs of today without impeding future generations from meeting
their own needs.
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;
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.
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%
Net income 12,536 5,495 128% 18,231 15,516 17%
Per Trust Unit, basic $ 0.29 $ 0.30 (3%) $ 0.47 $ 1.16 (59%)
Per Trust Unit, diluted $ 0.28 $ 0.29 (3%) $ 0.45 $ 1.13 (60%)
Distributions, declared 24,823 10,209 143% 64,563 30,685 110%
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%
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, GAPP 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" in this 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 of 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%; 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 operating expenses per BOE 15 and 17%, and maintain operating
2004 OBJECTIVE 2004 PERFORMANCE 2005 OUTLOOK
- -----------------------------------------------------------------------------------------------------------------------------
BOE 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.
- -------------------------------------------------------------------------------------------------------------------------------
(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.
- --------------------------------------------------------------------------------------------------------------------------
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 14,85 149% 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 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) 8223 9632 11373 14858 14829 15291 24759 37024
- ----------------------------------------------------------------------------------------------------------------------------
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 ($/bbl) 53.64 35.56 51% 48.70 35.56 37%
Medium oil ($/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%
- -------------------------------------------------------------------------------------------------------------------------
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.
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%)
============================================================================================================
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.
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.
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 $0.20 per Unit per month and to repay a portion of outstanding
bank debt. Given our significant amount of oil price hedges in place, management
believes cash flows in 2005 will exceed cash distributions and budgeted capital
expenditures under most WTI price scenarios.
Should commodity prices stay strong, heavy oil differentials narrow and the
Canadian dollar stabilize, we should have sufficient cash flow to repay a
significant portion of our outstanding bank debt by the end of 2005. It is also
important to note that to the extent our Unitholders elect to receive
distributions in the form of Trust Units rather than cash under our Distribution
Reinvestment plan (DRIP), this further reduces net cash outlays. During 2004,
DRIP participation was approximately 21%.
- --------------------------------------------------------------------------------------------------
2003 2004
- --------------------------------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
- --------------------------------------------------------------------------------------------------
PAYOUT RATIO (%) 93 73 45 75 69 64 41 46
- --------------------------------------------------------------------------------------------------
The table below provides an analysis of our debt structure, including some key
debt ratios. We believe that the current capital structure is appropriate given
our low payout ratio and the significant hedges in place. We intend to use cash
flow after distributions and capital expenditures to repay bank debt.
YEAR ENDED DECEMBER 31
-------------------------------------
($ 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 $222 million undrawn. The amount available under the bank credit
facility may be redetermined by our lenders from time to time based on lenders'
estimates of future cash flows from our oil and natural gas properties. Thus,
our ability to draw on this facility may change. We may draw under this
facility, or complete additional financings in the form of senior notes,
convertible debentures or Trust Units to expand the capital program or to
finance additional acquisitions. We may also utilize bridge financing, similar
to that used in 2003 and 2004, if required.
Our bank debt will be repaid or refinanced in June 2005 with a similar facility.
As lenders calculate the amount of such facilities using conservative price
assumptions, management does not anticipate a significant change to the amount
available under the new facility. The long term to maturity of the senior notes
allows us significant flexibility in determining how that particular debt is
refinanced.
A breakdown of our outstanding Trust Units and potentially dilutive instruments
are as follows:
AS AT DECEMBER 31
----------------------------------------------
($ 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 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%.
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.
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
$ 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
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.
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.
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.
MANAGEMENT'S REPORT TO UNITHOLDERS
Management is responsible for the integrity and objectivity of the information
contained in this Annual Report and for the consistency between the financial
statements and other financial reporting data contained elsewhere in the report.
The accompanying consolidated financial statements of Harvest Energy Trust have
been prepared by management in accordance with accounting principles generally
accepted in Canada using estimates and careful judgment, particularly in those
circumstances where the transactions affecting a current period are dependent
upon future events. The accompanying consolidated financial statements have been
prepared using policies and procedures established by management and reflect
fairly the Trust's financial position, results of operations and cash flow
within reasonable limits of materiality and within the framework of the
accounting policies as outlined in the notes to the financial statements.
Management has established and maintains a system of internal controls to
provide reasonable assurance that Harvest Energy Trust's assets are safeguarded
from loss and unauthorized use, and that the financial information is reliable
and accurate.
External auditors have examined the consolidated financial statements. Their
examination provides an independent view as to management's discharge of its
responsibilities insofar as they relate to the fairness of reported operating
results and financial condition of Harvest Energy Trust.
The Audit Committee of Harvest's Board of Directors has reviewed in detail the
consolidated financial statements with management and the external auditors. The
financial statements have been approved by the Board of Directors on the
recommendation of the Audit Committee.
/s/ Jacob Roorda
- ----------------
Jacob Roorda
President
/s/ David Rain
- ----------------
David Rain
Vice President and Chief Financial Officer
March 24, 2005
AUDITORS' REPORT
TO THE UNITHOLDERS OF HARVEST ENERGY TRUST
We have audited the consolidated balance sheets of Harvest Energy Trust as at
December 31, 2004 and 2003 and the consolidated statements of income and
accumulated income and cash flows for the years then ended. These financial
statements are the responsibility of the Trust's management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. These standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free from material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Trust as at December 31, 2004
and 2003 and the results of its operations and its cash flows for the years then
ended in accordance with Canadian generally accepted accounting principles.
/s/ KPMG LLP
- -------------------
Chartered Accountants
Calgary, Canada
March 24, 2005
CONSOLIDATED BALANCE SHEETS
As at December 31
(THOUSANDS OF CANADIAN DOLLARS) (RESTATED, NOTE 3)
2004 2003
- --------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets
Accounts receivable $ 44,028 $ 19,168
Current portion of derivative contracts [NOTE 16] 8,861 -
Prepaid expenses and deposits 3,014 12,131
- --------------------------------------------------------------------------------------------------------------------
55,903 31,299
Deferred charges [NOTE 16] 24,507 1,989
Long term portion of derivative contracts [NOTE 16] 3,710 -
Capital assets [NOTES 4 AND 5] 918,397 210,543
Future income tax [NOTE 15] - 12,609
Goodwill [NOTE 4] 43,832 -
- --------------------------------------------------------------------------------------------------------------------
$ 1,046,349 $ 256,440
====================================================================================================================
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities [NOTE 6] $ 76,251 $ 18,083
Cash distribution payable 8,358 3,422
Current portion of derivative contracts [NOTE 16] 27,927 -
Bank debt [NOTE 8] 75,519 63,349
- --------------------------------------------------------------------------------------------------------------------
188,055 84,854
Deferred gains [NOTE 16] 2,177 -
Senior notes [NOTE 9] 300,500 -
Asset retirement obligation [NOTES 3 AND 7] 90,085 42,009
Future income tax [NOTE 15] 34,671 -
- --------------------------------------------------------------------------------------------------------------------
615,488 126,863
Unitholders' equity
Unitholders' capital [NOTE 11] 465,131 117,407
Exchangeable shares [NOTE 13] 6,728 -
Equity bridge notes [NOTES 10 AND 17] - 25,000
Convertible debentures [NOTE 14] 24,696 -
Accumulated income 31,416 19,478
Contributed surplus - 239
Accumulated distributions (97,110) (32,547)
- --------------------------------------------------------------------------------------------------------------------
430,861 129,577
- --------------------------------------------------------------------------------------------------------------------
$ 1,046,349 $ 256,440
====================================================================================================================
Commitments, contingencies and guarantees [Note 19]. See accompanying notes to
these consolidated financial statements.
Approved by the Board of Directors:
/s/ John A. Brussa
- ------------------------
John A. Brussa
Director
/s/ Verne G. Johnson
- ------------------------
Verne G. Johnson
Director
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME
For the Years Ended December 31
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT PER TRUST UNIT AMOUNTS) (RESTATED, NOTE 3)
2004 2003
- --------------------------------------------------------------------------------------------------------------------
REVENUE
Oil and natural gas sales $ 331,331 $ 119,351
Royalty expense, net (54,236) (16,412)
- --------------------------------------------------------------------------------------------------------------------
277,095 102,939
EXPENSES
Operating 73,442 36,045
General and administrative 8,621 4,101
Unit right compensation expense 11,359 239
Interest on short term debt 9,445 5,582
Interest on long term debt 5,488 -
Depletion, depreciation and accretion 102,776 35,727
Foreign exchange gain (7,111) (4,374)
Gains and losses on derivative contracts 63,701 18,924
- --------------------------------------------------------------------------------------------------------------------
267,721 96,244
- --------------------------------------------------------------------------------------------------------------------
Income before taxes 9,374 6,695
TAXES
Large corporations tax 1,505 157
Future income tax recovery [NOTE 15] (10,362) (8,978)
- --------------------------------------------------------------------------------------------------------------------
NET INCOME FOR THE YEAR $ 18,231 $ 15,516
====================================================================================================================
Interest on equity bridge notes [NOTES 10 AND 17] (1,070) (870)
Interest on convertible debentures [NOTE 14] (5,223) -
Accumulated income, beginning of year 19,478 5,136
Retroactive application of change in accounting policy [NOTE 3] - (304)
ACCUMULATED INCOME, END OF YEAR $ 31,416 $ 19,478
====================================================================================================================
Net income per trust unit, basic [NOTE 11] $ 0.47 $ 1.16
Net income per trust unit, diluted [NOTE 11] $ 0.45 $ 1.13
====================================================================================================================
See accompanying notes to these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT PER TRUST UNIT AMOUNTS) (RESTATED, NOTE 3)
2004 2003
- ---------------------------------------------------------------------------------------------------------------------
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net income for the year $ 18,231 $ 15,516
Items not requiring cash
Depletion, depreciation and accretion 102,776 35,727
Unrealized foreign exchange (gain) loss (5,537) 1,432
Amortization of deferred finance charges 4,086 2,556
Unrealized loss on derivative contracts [NOTE 16] 11,274 -
Future tax recovery (10,362) (8,978)
Non-cash unit right compensation expense 9,535 239
- ---------------------------------------------------------------------------------------------------------------------
130,003 46,492
Settlement of asset retirement obligations (929) (577)
Change in non-cash working capital (11,103) (12,290)
- ---------------------------------------------------------------------------------------------------------------------
117,971 33,625
- ---------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue of trust units, net of issue costs 164,743 61,691
Issue of bridge note payable - 25,000
Repayment of bridge notes - (25,000)
Issue of equity bridge notes [NOTES 10 AND 17] 30,000 33,500
Repayment of equity bridge notes [NOTES 10 AND 17] (55,000) (8,500)
Interest on equity bridge notes (1,070) (870)
Issuance of convertible debentures [NOTE 14] 160,000 -
Issue costs for convertible debentures (7,201) -
Interest on convertible debentures (5,223) -
Issue of senior notes 311,951 -
Repayment of bank debt, net (44,661) 15,263
Repayment of promissory note payable - (850)
Financing costs (13,770) (2,334)
Cash distributions (47,074) (18,488)
Change in non-cash working capital 5,097 2,889
- ---------------------------------------------------------------------------------------------------------------------
497,792 82,301
- ---------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to capital assets (42,662) (27,209)
Acquisition of Storm Energy Ltd. (75,783) -
Property acquisitions (513,865) (93,549)
Change in non-cash working capital 16,547 329
- ---------------------------------------------------------------------------------------------------------------------
(615,763) (120,429)
- ---------------------------------------------------------------------------------------------------------------------
Decrease in cash and short-term investments - (4,503)
Cash and short term investments, beginning of year - 4,503
- ---------------------------------------------------------------------------------------------------------------------
Cash and short term investments, end of year $ - $ -
- ---------------------------------------------------------------------------------------------------------------------
Cash interest payments $ 5,521 $ 2,866
Cash tax payments $ 2,298 $ 157
Cash distributions declared per trust unit $ 2.40 $ 2.40
=====================================================================================================================
See accompanying notes to these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004 and 2003
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT TRUST UNIT, AND PER
TRUST UNIT AMOUNTS)
1. STRUCTURE OF THE TRUST
Harvest Energy Trust (the "Trust") is an open-ended, unincorporated investment
trust formed under the laws of Alberta. Pursuant to its trust indenture and an
administration agreement, the Trust is managed by its wholly owned subsidiary,
Harvest Operations Corp. ("Harvest Operations"). The Trust acquires and holds
net profit interests in oil and natural gas properties in Alberta, Saskatchewan
and British Columbia held by Harvest Operations and other operating subsidiaries
of the Trust. All properties under the Trust are operated by Harvest Operations.
The beneficiaries of the Trust are the holders of Trust Units. The Trust makes
monthly distributions of its distributable cash to Unitholders of record on the
last business day of each calendar month.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements of Harvest Energy Trust have been
prepared by management in accordance with Canadian generally accepted accounting
principles ("Canadian GAAP"). These principles differ in certain respects from
accounting principles generally accepted in the United States of America ("U.S.
GAAP") and to the extent that they affect the Trust, these differences are
described in Note 20. Certain comparative figures have been reclassified to
conform to the current period's presentation.
(A) CONSOLIDATION
These consolidated financial statements include the accounts of the Trust, its
wholly-owned subsidiaries and its 60% interest in a partnership with a third
party. All inter-entity transactions and balances have been eliminated upon
consolidation. The Trust's proportionate interest in the partnership has been
included in the consolidated financial statements.
(B) USE OF ESTIMATES
The preparation of financial statements requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingencies, if any, as at the date of the financial statements
and the reported amounts of revenues and expenses during the period.
Specifically, amounts recorded for depletion, depreciation and accretion
expense, asset retirement obligations and amounts used in the impairment tests
for goodwill and capital assets are based on estimates of oil and natural gas
reserves and future costs required to develop those reserves. By their nature,
these estimates are subject to measurement uncertainty. In the opinion of
management, these consolidated financial statements have been prepared within
reasonable limits of materiality.
(C) REVENUE RECOGNITION
Revenues associated with the sale of crude oil, natural gas and natural gas
liquids are recognized when title passes to customers.
(D) JOINT VENTURE ACCOUNTING
The subsidiaries of the Trust conduct substantially all of their oil and natural
gas production activities through joint ventures and the consolidated financial
statements reflect only their proportionate interest in such activities.
(E) CAPITAL ASSETS
OIL AND NATURAL GAS ACTIVITIES
The Trust follows the full cost method of accounting for its oil and natural gas
activities. All costs of acquiring oil and natural gas properties and related
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. Renewals and enhancements that extend the
economic life of the capital assets are capitalized.
Gains and losses are not recognized on disposition of oil and natural gas
properties unless that disposition would alter the rate of depletion by 20% or
more.
Provision for depletion and depreciation of oil and natural gas assets is
calculated on the unit-of-production method, based on proved reserves net of
royalties as estimated by independent petroleum engineers. The basis used for
the calculation of the provision is the capitalized costs of oil 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 Trust places a limit on the aggregate carrying value of capital assets
associated with oil and natural gas activities, which may be amortized against
revenues of future periods. Impairment is recognized if the carrying amount of
the capital assets exceeds the sum of the undiscounted cash flows expected to
result from the Trust's proved reserves. Cash flows are calculated based on
third-party quoted forward prices, adjusted for the Trust's contract prices and
quality differentials.
Upon recognition of impairment, the Trust would then measure the amount of
impairment by comparing the carrying amounts of the capital assets to an amount
equal to the estimated net present value of future cash flows from Proved plus
Probable reserves. The Trust's risk-free interest rate is used to arrive at the
net present value of the future cash flows. Any excess carrying value above the
net present value of the Trust's future cash flows would be a permanent
impairment and reflected in net income for the relevant period.
The cost of unproved properties is excluded from the impairment test calculation
described above and subject to a separate impairment test.
OFFICE FURNITURE AND EQUIPMENT
Depreciation and amortization of office furniture and equipment is provided for
at rates ranging from 20% to 50% per annum.
(F) 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 the acquired business. The goodwill
balance is assessed for impairment annually at year-end, or more frequently if
events or changes in circumstances occur that more likely than not reduce the
fair value of the acquired business below its carrying amount. The test for
impairment is carried out by comparing the carrying amount of the reporting
entity to its fair value. If the fair value of the Trust's equity is less than
the book value, impairment is measured by allocating the fair value of the
consolidated Trust to its identifiable assets and liabilities at their fair
values. The excess of this allocation is the fair value of goodwill. Any excess
of the book value of goodwill over this implied fair value is the impairment
amount. Impairment is charged to income in the period in which it occurs.
Goodwill is stated at cost less impairment and is not amortized.
(G) ASSET RETIREMENT OBLIGATION
The Trust records the fair value of an asset retirement obligation as a
liability in the period in which it incurs a legal obligation associated with
the retirement of tangible long-lived assets that result from the acquisition,
construction, development, and normal use of the assets. The Trust uses a
credit-adjusted risk free discount rate to estimate this fair value. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset and depleted and depreciated using the unit of
production method over estimated net proved reserves. Subsequent to the initial
measurement of the asset retirement obligation, the obligation is adjusted at
the end of each period to reflect the passage of time and changes in the
estimated future cash flows underlying the obligation.
(H) INCOME TAXES
The Trust and its Trust subsidiaries are taxable entities under the Income Tax
Act (Canada) and are taxable only on income that is not distributed or
distributable to their Unitholders. As both the Trust and its Trust subsidiaries
distribute all of their taxable income to their respective Unitholders pursuant
to the requirements of the Income Tax Act (Canada), neither the Trust nor its
Trust subsidiaries make provisions for future income taxes.
Harvest Operations and the corporate subsidiaries of the Trust follow the
liability method of accounting for income taxes. Under this method, income tax
liabilities and assets are recognized for the estimated tax consequences
attributable to differences between the amounts reported in its financial
statements and its respective tax base, using enacted or substantively enacted
income tax rates. The effect of a change in income tax rates on future tax
liabilities and assets is recognized in income in the period in which the change
occurs.
(I) UNIT-BASED COMPENSATION
The Trust determines compensation expense for the Trust Unit incentive plan and
the Unit award incentive plan [Note 12] by estimating the intrinsic value of the
rights at each period end and recognizing the amount in income over the vesting
period. After the rights have vested, further changes in the intrinsic value are
recognized in income in the period of change.
The intrinsic value is the difference between market value of the Units and the
exercise price of the right. The intrinsic value is used to determine
compensation expense as participants in the plan have the option to either
purchase the Units at the exercise price or to receive a cash payment equal to
the excess of the market value over the exercise price. As the expense is
determined based on the period end price, large fluctuations, even recoveries,
in compensation expense may occur. As the
Unit rights are exercised, cash payments are reflected against the liability
previously recorded and any Unit issuances are reflected as increases to
Unitholders' capital.
Under the terms of the plan, the exercise price of rights granted may be reduced
in future periods based on the distributions made to Trust Unitholders. The
Trust previously used the fair value method of accounting for the Trust Unit
incentive plan.
(J) EXCHANGEABLE SHARES
Exchangeable shares are presented as equity of the Trust as their features make
them economically equivalent to Trust Units.
(K) DEFERRED FINANCING CHARGES
Deferred financing charges relate to costs incurred on the issuance of debt and
are amortized on a straight-line basis over the term of the debt, and are
included in interest expense.
(L) FINANCIAL INSTRUMENTS
Derivative financial instruments are utilized by the Trust in the management of
its commodity price, foreign currency and interest rate exposures. The Trust
uses a variety of derivative instruments to manage these exposures including,
swaps, options and collars. The Trust may elect to use hedge accounting when
there is a high degree of correlation between the price movements in the
derivative financial instruments and the items designated as being hedged. The
Trust documents all relationships between hedging instruments and hedged items
as well as its risk management objective and strategy for undertaking various
hedge transactions. Gains and losses are recognized on the derivative financial
instruments in the same period in which the gains and losses on the hedged item
are recognized. If the price movements in the derivative instrument and the
hedged item cease to be highly correlated, hedge accounting is terminated and
the fair value of the derivative financial instrument at such time is recognized
on the balance sheet as a deferred charge and recognized in income in the period
in which the underlying hedged transaction is recognized. Future changes in the
market value of the derivative financial instrument are then recognized in
income as they occur. At December 31, 2004, the Trust has not designated any of
its outstanding derivative instruments as hedges.
For derivative transactions where hedge accounting is not applied, the Trust
applies a fair value method of accounting by initially recording an asset or
liability, and recognizing changes in the fair value of the derivative
instrument in income as an unrealized gain or loss on derivative contracts. Any
realized gains or losses on derivative contracts that are not designated hedges
are recognized in income in the period they occur.
(M) FOREIGN CURRENCY TRANSLATION
Monetary assets and liabilities denominated in a foreign currency are translated
at the rate of exchange in effect at the balance sheet date. Revenues and
expenses are translated at the monthly average rate of exchange. Translation
gains and losses are included in income in the period in which they arise.
3. CHANGES IN ACCOUNTING POLICY
(A) FULL COST ACCOUNTING GUIDELINE
Effective January 1, 2004, the Trust adopted the Canadian Institute of Chartered
Accountants ("CICA") Handbook Accounting Guideline 16 "Oil and Gas Accounting -
Full Cost". The changes under the new guideline include modifications to the
ceiling test and depletion and depreciation calculations. There were no changes
to previously reported net income, capital assets or any other financial
statement amounts as a result of the implementation of this guideline.
(B) ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2004, the Trust adopted CICA Handbook Section 3110 "Asset
Retirement Obligations" in accounting for its asset retirement obligations. The
effect of this change in accounting policy has been recorded retroactively with
restatement of prior periods as follows:
---------------------------------------------------------------------------
BALANCE SHEET As at December 31,
2003
---------------------------------------------------------------------------
Asset retirement costs, included in capital assets $ 35,166
Asset retirement obligation 42,009
Site restoration provision (4,321)
Future income tax asset 1,024
Accumulated income (1,498)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
INCOME STATEMENT Year ended December
31, 2003
---------------------------------------------------------------------------
Accretion expense $ 1,845
Depletion and depreciation on asset retirement costs 4,520
Site restoration and reclamation (4,355)
Future tax recovery (816)
Net income change (1,194)
Basic net income change per trust unit (0.10)
Diluted net income change per trust unit (0.09)
---------------------------------------------------------------------------
(C) FINANCIAL INSTRUMENTS
Effective January 1, 2004, the Trust implemented CICA Accounting Guideline 13
"Hedging Relationships" ("AcG-13"). This guideline 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 tested to ensure they remain sufficiently effective. For transactions
that do not qualify as designated hedges, the Trust applies a fair value method
of accounting by initially recording an asset or liability, and recognizing
changes in the fair value of the derivative instrument in income.
Upon the implementation of this new accounting policy, the Trust recorded a
liability and a corresponding asset of $5.5 million related to the fair value of
the derivative financial instruments that did not qualify for hedge accounting.
This amount has been fully recognized in income for the year ended December 31,
2004.
4. CORPORATE ACQUISITIONS
On June 30, 2004, the Trust completed a Plan of Arrangement with Storm Energy
Ltd. ("Storm"). Under this plan, the Trust acquired certain oil and natural gas
producing properties for total consideration of approximately $192.2 million.
This amount consisted of the issuance of 2,720,837 Trust Units [Note 11] and the
issuance of 600,587 exchangeable shares each at $14.77 [Note 13], $75 million in
cash, the assumption of approximately $67.3 million in debt and working capital
deficiency and acquisition costs of $0.8 million.
This transaction has been accounted for using the purchase price method. The
following summarizes the estimated fair value of the assets acquired and
liabilities assumed at the date of acquisition.
-------------------------------------------------------------------------
ALLOCATION OF PURCHASE PRICE: AMOUNT
-------------------------------------------------------------------------
Working capital deficiency $ (10,488)
Bank debt (56,831)
Capital assets 213,455
Derivative contract 863
Goodwill 43,832
Asset retirement obligation (8,353)
Future income tax (57,642)
-------------------------------------------------------------------------
$ 124,836
-------------------------------------------------------------------------
CONSIDERATION FOR THE ACQUISITION:
Cash $ 75,000
Issuance of trust units 40,183
Issuance of exchangeable shares 8,870
Acquisition costs 783
-------------------------------------------------------------------------
$ 124,836
-------------------------------------------------------------------------
On June 1, 2003, the Trust acquired all of the common shares and the Net Profit
Interest of a private company. Total consideration paid by the Trust was $10.1
million, and consisted of the issuance of 625,000 Trust Units at a price of
$10.00 per Trust Unit, $3 million in cash and an $850,000 unsecured demand
promissory note bearing an interest rate of 10% per
annum effective June 27, 2003. The Trust assumed $2.5 million of working
capital, $2.8 million of bank debt and acquired $15.4 million in capital assets
as part of this acquisition.
5. CAPITAL ASSETS
----------------------------------------------------------------------------------------------------------
ACCUMULATED DEPLETION
DECEMBER 31, 2004 COST AND DEPRECIATION NET BOOK VALUE
----------------------------------------------------------------------------------------------------------
Oil and natural gas properties $ 845,396 $ (110,077) $ 735,319
Production facilities and equipment 209,984 (27,817) 182,167
Office furniture and equipment 1,337 (426) 911
----------------------------------------------------------------------------------------------------------
Total $ 1,056,717 $ (138,320) $ 918,397
==========================================================================================================
----------------------------------------------------------------------------------------------------------
ACCUMULATED DEPLETION
DECEMBER 31, 2003 COST AND DEPRECIATION NET BOOK VALUE
----------------------------------------------------------------------------------------------------------
Oil and natural gas properties $ 202,529 $ (31,262) $ 171,267
Production facilities and equipment 47,071 (8,346) 38,725
Office furniture and equipment 708 (157) 551
----------------------------------------------------------------------------------------------------------
Total $ 250,308 $ (39,765) $ 210,543
==========================================================================================================
On September 2, 2004, the Trust purchased oil and natural gas producing
properties from a senior producer for cash consideration of approximately $526
million before final working capital adjustments. Final adjustments reduced the
Trust's purchase price to $511.4 million. In conjunction with the acquisition of
these properties, the Trust issued approximately $175.2 million in subscription
receipts which were converted into 12,166,666 Trust Units upon completion of the
purchase [Note 11], and $100 million in 8% convertible unsecured subordinated
debentures [Note 14]. The balance of the acquisition cost was funded with a new
credit facility arrangement [Note 8].
On October 16, 2003, the Trust acquired the Carlyle Properties in southeastern
Saskatchewan for total consideration of approximately $79.5 million before costs
and purchase price adjustments. The acquisition was partially financed by the
issue of Trust Units on October 16, 2003, with the balance being funded by the
bank facility.
General and administrative costs of $3.6 million (2003 - $1.3 million) have been
capitalized during the year ended December 31, 2004.
All costs are subject to depletion and depreciation at December 31, 2004
including future development costs of $83.3 million (2003 - $15.2 million).
$28.6 million (2003 - nil) of undeveloped properties were excluded from the
asset base subject to depletion at December 31, 2004.
In accordance with Canadian GAAP, the Trust performed an impairment test as at
December 31, 2004 and 2003. The crude oil and natural gas future prices used in
the impairment test were obtained from third parties and were adjusted for
commodity price differentials specific to the Trust. Based on these assumptions,
the undiscounted future net revenue from the Trust's proved reserves exceed the
carrying value of the Trust's oil and natural gas assets as at December 31,
2004, and therefore no impairment was recorded.
BENCHMARK PRICES:
------------------------- ------------------ ------------------ ----------------------- ------------------
WTI OIL FOREIGN EDMONTON LIGHT CRUDE AECO GAS
YEAR (US$/BBL) EXCHANGE RATE OIL (CDN$BBL) (CDN$/GJ)
------------------------- ------------------ ------------------ ----------------------- ------------------
2005 42.00 0.83 49.60 6.45
------------------------- ------------------ ------------------ ----------------------- ------------------
2006 39.50 0.83 46.60 6.20
------------------------- ------------------ ------------------ ----------------------- ------------------
2007 37.00 0.83 43.50 6.05
------------------------- ------------------ ------------------ ----------------------- ------------------
2008 35.00 0.83 41.10 5.80
------------------------- ------------------ ------------------ ----------------------- ------------------
2009 34.50 0.83 40.50 5.70
------------------------- ------------------ ------------------ ----------------------- ------------------
Thereafter (escalation) 2.0% 0% 2.0% 2.0%
------------------------- ------------------ ------------------ ----------------------- ------------------
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
----------------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2004 2003
----------------------------------------------------------------------------------------------
Trade accounts payable $ 13,697 $ 9,524
Accrued interest 5,993 897
Trust unit incentive plan [NOTE 12] 9,774 -
Premium on derivative contracts 4,500 -
Accrued closing adjustments on asset acquisition 13,546 -
Other accrued liabilities 27,139 7,629
Large corporation taxes payable 1,602 33
----------------------------------------------------------------------------------------------
$ 76,251 $ 18,083
----------------------------------------------------------------------------------------------
7. ASSET RETIREMENT OBLIGATION
The Trust's asset retirement obligation results from its net ownership interest
in oil and natural gas assets including well sites, gathering systems and
processing facilities and the estimated costs and timing to reclaim and abandon
them. The Trust estimates the total undiscounted amount of cash flows required
to settle its asset retirement obligation to be approximately $334.8 million
which will be incurred between 2004 and 2023. The majority of the costs will be
incurred between 2015 and 2021. A credit-adjusted risk-free rate of 10% was used
to calculate the fair value of the asset retirement obligation.
A reconciliation of the asset retirement obligation is provided below:
--------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31 2004
2003
--------------------------------------------------------------------------------------------
Balance, beginning of year $ 42,009 $ 15,566
Liabilities incurred 53,488 25,175
Revision of estimates (8,704) -
Liabilities settled (929) (577)
Accretion expense 4,221 1,845
--------------------------------------------------------------------------------------------
Balance, end of year $ 90,085 $ 42,009
--------------------------------------------------------------------------------------------
8. BANK DEBT
As at December 31, 2004, Harvest Operations has a senior borrowing base credit
facility with a syndicate of lenders. This facility consists of a $310 million
production loan, a $15 million operating loan, and a U.S. $21.3 million
mark-to-market credit to be used for financial instrument hedging. The term of
the facility is to June 29, 2005. Availability under the facility is subject to
a borrowing base calculation performed by the lenders at least on a semi-annual
basis. The facility permits drawings in Canadian or U.S. dollars, and includes
banker's acceptances, LIBOR loans and letters of credit. Outstanding balances
bear interest at rates ranging from 0% to 2.25% above the applicable Canadian or
U.S. prime rate depending upon the type of borrowing and the debt to annualized
cash flow ratio. The debt is secured by a $750 million debenture with a fixed
and floating charge over all of the assets of Harvest Operations, and a
guarantee by the Trust and its subsidiaries.
A bridge facility of $70 million was provided by the Trust's lenders to assist
in the closing of the significant property acquisition in September [Note 5].
This facility was due to mature on June 1, 2005, and outstanding balances under
this facility accrued interest at progressive rates of 3% to 8% above the
applicable Canadian prime rate. The bridge facility was repaid in full with the
net proceeds of the senior notes issuance [Note 9].
9. SENIOR NOTES
On October 14, 2004, Harvest Operations closed an agreement to sell, on a
private placement basis in the United States, U.S.$250 million of senior notes
due October 15, 2011. The senior notes are unsecured and bear interest at an
annual rate of 7 7/8% and were sold at a price of 99.3392% of their principal
amount. A discount of $2.1 million on the senior notes is recorded in deferred
charges and amortized into interest expense over the term of the notes. Interest
is payable semi-annually on April 15 and October 15. The senior notes are
unconditionally guaranteed by the Trust and all of its wholly-owned
subsidiaries. The Trust used the net proceeds of the offering to repay in full
Harvest's bank bridge facility and partially repay outstanding balances under
Harvest's senior credit facility. The fair value of the senior notes at December
31, 2004 was U.S.$250.6 million (Cdn$301.2 million).
10. EQUITY BRIDGE NOTES
A director of Harvest Operations and a corporation controlled by that director
had advanced $25 million pursuant to the equity bridge notes as at December 31,
2003. On January 2, 2004 Harvest Operations paid $665,068 in accrued interest on
these notes. On January 26 and 29, 2004, Harvest Operations 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 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 the Trust and were subordinate to
the interest of the senior secured lenders pursuant to Harvest Operations'
credit facility.
The Trust had the option to settle the quarterly interest payments under the
equity bridge notes with cash or the issue of Trust Units. If the Trust elected
to issue Trust Units, the number of Trust Units to be issued to settle a
quarterly interest payment would have been the equivalent of the quarterly
payment amount divided by 90% of the most recent ten-day weighted average
trading price. The Trust 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.
11. UNITHOLDERS' CAPITAL
(A) AUTHORIZED
The authorized capital consists of an unlimited number of Trust Units.
(B) ISSUED
---------------------------------------------------------------------------------------
NUMBER OF UNITS
(000S) AMOUNT
---------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2002 9,312 $ 36,728
Exercise of warrants 150 150
Special warrant exercise 1,500 15,000
Acquisitions 825 8,350
Trust unit issue 4,313 48,645
Distribution reinvestment plan issuance 1,009 10,638
Trust unit issue costs - (2,104)
---------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2003 17,109 $ 117,407
Storm Plan of Arrangement [NOTE 4] 2,721 40,183
Conversion of subscription receipts [NOTE 5] 12,167 175,200
Convertible debenture conversions-9% series 3,521 49,300
Convertible debenture conversions-8% series 5,221 84,841
Exchangeable share retraction 152 2,142
Distribution reinvestment plan issuance 752 12,553
Unit appreciation rights exercise 145 721
Trust unit issue costs - (17,216)
---------------------------------------------------------------------------------------
AS AT DECEMBER 31, 2004 41,788 $ 465,131
---------------------------------------------------------------------------------------
(C) PER TRUST UNIT INFORMATION
The following table summarizes the net income and Trust Units used in
calculating income per Trust Unit:
- ---------------------------------------------------------------------------------------------
2004 2003
- ---------------------------------------------------------------------------------------------
NET INCOME ADJUSTMENTS
- ---------------------------------------------------------------------------------------------
Net income $ 18,231 $ 15,516
Interest on equity bridge notes (1,070) (870)
Interest on convertible debentures (5,223) -
- ---------------------------------------------------------------------------------------------
Net income available to Trust unitholders $ 11,938 $ 14,646
- ---------------------------------------------------------------------------------------------
WEIGHTED AVERAGE TRUST UNITS ADJUSTMENTS
- ---------------------------------------------------------------------------------------------
Weighted average trust units outstanding 25,033,567 12,590,937
- ---------------------------------------------------------------------------------------------
Weighted average exchangeable shares outstanding(1) 290,090 -
- ---------------------------------------------------------------------------------------------
Weighted average trust units outstanding, basic 25,323,657 12,590,937
- ---------------------------------------------------------------------------------------------
Effect of trust unit appreciation rights 1,140,738 411,868
- ---------------------------------------------------------------------------------------------
Weighted average trust units outstanding, diluted(2) 26,464,395 13,002,805
- ---------------------------------------------------------------------------------------------
(1) Reflects the weighted average of exchangeable shares outstanding based on
the conversion ratio at December 31, 2004.
(2) Weighted average Trust Units outstanding diluted for 2004 does not include
the impact of the conversion of the debentures as the impact would be
anti-dilutive. Total Units excluded amount to 6,004,145.
12. TRUST UNIT INCENTIVE PLANS
The Trust Unit incentive plan was established in 2002. In December 2004, the
plan was modified such that the ability to settle a Unit right with cash is now
solely at the option of the holder and not subject to the discretion of the
Board of Directors. The Trust is authorized to grant non-transferable rights to
purchase Trust Units to directors, officers, consultants, employees and other
service providers to an aggregate of 1,487,250 Trust Units, of which 1,371,475
were granted as of December 31, 2004. The initial exercise price of rights
granted under the plan is equal to the market price of the Trust Units at the
time of grant and the maximum term of each right is five years. The rights vest
equally over four years commencing on the first anniversary of the grant date.
The exercise price of the rights may be reduced by an amount up to the amount of
cash distributions made on the Trust Units subsequent to the date of grant of
the respective right, provided that the Trust's net operating cash flow (on an
annualized basis) exceeds 10% of the Trust's recorded cost of capital assets
less all debt, working capital deficiency (surplus) or debt equivalent
instruments, accumulated depletion, depreciation and amortization charges,
asset retirement obligations, and any future income tax liability associated
with such capital assets. Any portion of a distribution that does not reduce the
exercise price on vested rights is paid to the holder in cash on a semi-annual
basis.
As a result of the modification of the Trust Unit incentive plan, the Trust is
required to recognize an obligation for all of the Units reserved under the
plan. This obligation represents the difference between the market value of the
Trust Units and the exercise price of the Unit rights outstanding under the
plan. As such, an obligation of $9.8 million has been recorded in accounts
payable and accrued liabilities for the graded vested portion of the 1,117,725
Trust Units outstanding under the plan at December 31, 2004. A one time charge
of $8.2 million has been included in Unit right compensation expense to reflect
the additional expense resulting from the change in accounting from the fair
value method previously used to the intrinsic method. The amount previously
expensed has been removed from contributed surplus and reflected in accounts
payable and accrued liabilities.
The following summarizes the Trust Units reserved for issuance under the Trust
Unit incentive plan:
2004 2003
------------------------------------------------------------------------------------------------------------
UNIT WEIGHTED UNIT WEIGHTED
APPRECIATION AVERAGE APPRECIATION AVERAGE
RIGHTS EXERCISE PRICE RIGHTS EXERCISE PRICE(A)
------------------------------------------------------------------------------------------------------------
Outstanding beginning of year 1,065,150 $ 9.04 787,500 $ 8.00
Granted 445,600 16.47 277,650 11.94
Exercised (253,750) 8.30 - -
Cancelled (139,275) 10.91 - -
------------------------------------------------------------------------------------------------------------
Outstanding before exercise price 1,117,725 11.92 1,065,150 9.04
reductions
Exercise price reductions - (1.83) - (1.11)
------------------------------------------------------------------------------------------------------------
Outstanding, end of year 1,117,725 $ 10.09 1,065,150 $ 7.93
============================================================================================================
Exercisable before exercise price $ 8.89 $ 8.00
reductions 206,688 196,875
Exercise price reductions - (2.64) - (1.30)
------------------------------------------------------------------------------------------------------------
Exercisable, end of year 206,688 $ 6.25 196,875 $ 6.70
============================================================================================================
(a) adjusted to retroactively reflect modifications to the plan made in 2004.
The following table summarizes information about Unit appreciation rights
outstanding at December 31, 2004.
------------------------------------------------------------------------------------------------------------------
OUTSTANDING EXERCISABLE
------------------------------------------------------------------------------------------------------------------
EXERCISE
EXERCISE PRICE EXERCISE PRICE OUTSTANDING AT PRICE NET OF REMAINING EXERCISABLE EXERCISE PRICE
BEFORE PRICE NET OF PRICE DECEMBER 31, PRICE CONTRACTUAL AT DECEMBER, NET OF PRICE
REDUCTIONS REDUCTIONS 2004 REDUCTIONS(A) LIFE (A) 31, 2004 REDUCTIONS (A)
$8.00 - 10.21 $5.18 - $7.86 509,625 $ 5.27 2.9 163,375 $ 5.23
$10.30 - $13.35 $7.98 - $11.97 214,700 10.31 3.7 43,313 10.11
$13.75 - $18.90 $12.37 -$18.50 308,400 14.92 4.5 - n/a
$19.90 - $23.70 $19.50 - $23.30 85,000 20.92 4.8 - n/a
------------------------------------------------------------------------------------------------------------------
$8.00 - $23.70 $5.18 - $23.30 1,117,725 $ 10.09 3.7 206,688 $ 6.25
==================================================================================================================
(a) Based on weighted average Unit appreciation rights outstanding.
When the Trust adopted the fair value method of accounting for its Trust Unit
incentive plan on January 1, 2003, it was required to calculate the pro forma
impact of having adopted that method from the date all rights were initially
granted.
For purposes of those calculations the fair value of each Trust Unit right has
been estimated on the grant date using the following:
---------------------------------------------------------------------------
December 31, 2003
---------------------------------------------------------------------------
Expected volatility 23.3%
---------------------------------------------------------------------------
Risk free interest rate 4.1%
---------------------------------------------------------------------------
Expected life of the trust unit rights 4 years
---------------------------------------------------------------------------
Estimated annual distributions per unit $2.40
---------------------------------------------------------------------------
As at December 31, 2003 for the purposes of pro forma disclosures, the expense
related to all of the Trust Unit rights issued prior to December 31, 2002 is
reflected in proforma net income as shown below:
----------------------------------------------------------------------------
(Restated Note 3)
----------------------------------------------------------------------------
2003
----------------------------------------------------------------------------
Net income As reported $15,516
----------------------------------------------------------------------------
Pro forma $14,228
----------------------------------------------------------------------------
Income (loss) per unit - basic As reported $1.16
----------------------------------------------------------------------------
Pro forma $1.06
----------------------------------------------------------------------------
Income (loss) per unit - diluted As reported $1.13
----------------------------------------------------------------------------
Pro forma $1.03
----------------------------------------------------------------------------
During the years ended December 31, the Trust has recognized non-cash
compensation expense of $9.5 million in 2004 and $239,000 in 2003 related to
Trust Unit rights and included it in general and administrative expense in the
consolidated statements of income.
UNIT AWARD INCENTIVE PLAN
In the year ended December 31, 2004, the Trust has implemented a Unit Award
Incentive Plan ("Unit Award Plan"). The Unit Award Plan authorizes the Trust to
grant awards of Trust Units to directors, officers, employees and consultants of
the Trust and its affiliates. Subject to the Board of Directors' discretion,
awards vest annually over a four year period and, upon vesting, entitle the
holder to receive the number of Trust Units subject to the award or the
equivalent cash amount. The number of Units to be issued is adjusted at each
distribution date for an amount approximately equal to the foregone
distributions. The fair value associated with the Trust Units granted under the
Unit Award Plan is expensed in the statement of income over the vesting period.
The Trust recorded compensation expense of $56,000 in 2004 related to this plan.
The Trust may issue up to a maximum of 150,000 Trust Units under the Unit Award
Plan. In 2004, 15,000 Trust Units were issued under this plan, of which 5,000
were subsequently cancelled.
13. EXCHANGEABLE SHARES
(A) AUTHORIZED
Harvest Operations is authorized to issue an unlimited number of exchangeable
shares without nominal or par value.
(B) ISSUED
--------------------------------------------------------------------------
EXCHANGEABLE SHARES, SERIES 1
--------------------------------------------------------------------------
NUMBER AMOUNT
--------------------------------------------------------------------------
Storm Plan of Arrangement 600,587 $ 8,870
--------------------------------------------------------------------------
Shareholder retractions (145,040) (2,142)
--------------------------------------------------------------------------
As at December 31, 2004 455,547 $ 6,728
--------------------------------------------------------------------------
On June 30, 2004, 600,587 exchangeable shares, series 1 were issued at $14.77
each as partial consideration under the Plan of Arrangement with Storm [Note 4].
The exchangeable shares, series 1 can be converted at the option of the holder
at any time into Trust Units. The number of Trust Units issued to the holder
upon conversion is based upon the applicable exchange ratio at that time. The
exchange ratio is calculated monthly and adjusts to account for distributions
paid to Unitholders during the period that the exchangeable shares are
outstanding. The exchangeable shares are not eligible to receive distributions.
The exchangeable shares that have not been converted by the holder may be
redeemed in part or in their entirety by Harvest Operations at any date until
June 30, 2009, at which time all remaining exchangeable shares in this series
will be redeemed for Trust Units. The exchangeable shares had an exchange ratio
of 1:1.06466 as at December 31, 2004.
14. CONVERTIBLE DEBENTURES
On January 29, 2004, the Trust issued $60 million of 9% convertible unsecured
subordinated debentures due May 31, 2009. Interest on the debentures is payable
semi-annually in arrears in equal installments on May 31 and November 30 in each
year, commencing May 31, 2004. The debentures are convertible into fully paid
and non-assessable Trust Units at the option of the holder at any time prior to
the close of business on the earlier of May 31, 2009 and the business day
immediately preceding the date specified by the Trust for redemption of the
Debentures, at a conversion price of $14.00 per Trust Unit plus a cash payment
for accrued interest and in lieu of any fractional Trust Units resulting on the
conversion. The debentures may be
redeemed by the Trust at its option in whole or in part subsequent to May 31,
2007, at a price equal to $1,050 per debenture between June 1, 2007 and May 31,
2008 and at $1,025 per debenture between June 1, 2008 and May 31, 2009. Any
redemption will include accrued and unpaid interest at such time. Under both
redemption options, the Trust may elect to pay both the principal and accrued
interest in the form of Trust Units at a price equal to 95% of the weighted
average trading price for the preceding 20 consecutive trading days, 5 days
prior to settlement date.
On August 10, 2004, the Trust issued of $100 million of 8% convertible unsecured
subordinated debentures due September 30, 2009. Interest on the debentures is
payable semi-annually in arrears in equal installments on March 31 and September
30 in each year, commencing March 31, 2005. The debentures are convertible into
fully paid and non-assessable Trust Units at the option of the holder at any
time prior to the close of business on the earlier of September 30, 2009 and the
business day immediately preceding the date specified by the Trust for
redemption of the debentures, at a conversion price of $16.25 per Trust Unit
plus a cash payment for accrued interest and in lieu of any fractional Trust
Units resulting on the conversion. The debentures may be redeemed by the Trust
at its option in whole or in part subsequent to September 30, 2007, at a price
equal to $1,050 per debenture between October 1, 2007 and September 30, 2008 and
at $1,025 per debenture between October 1, 2008 and September 30, 2009. Any
redemption will include accrued and unpaid interest at such time. Under both
redemption options, the Trust may elect to pay both the principal and accrued
interest in the form of Trust Units at a price equal to 95% of the weighted
average trading price for the preceding 20 consecutive trading days, 5 days
prior to settlement date. This series of convertible debentures ranks pari-passu
with the outstanding debentures issued on January 29, 2004.
The following table summarizes the issuance and subsequent conversions of the
convertible debentures:
- ----------------------------------------------------------------------------------------------------------
9% SERIES 8% SERIES TOTAL
- ----------------------------------------------------------------------------------------------------------
NUMBER OF AMOUNT NUMBER OF AMOUNT AMOUNT
DEBENTURES DEBENTURES
- ----------------------------------------------------------------------------------------------------------
January 29, 2004 issuance 60,000 $60,000 - - $60,000
- ----------------------------------------------------------------------------------------------------------
August 10, 2004 issuance - - 100,000 $100,000 100,000
- ----------------------------------------------------------------------------------------------------------
Converted for trust units (49,300) (49,300) (84,841) (84,841) (134,141)
- ----------------------------------------------------------------------------------------------------------
Convertible debenture issue costs (2,667) (4,534) (7,201)
- ----------------------------------------------------------------------------------------------------------
Convertible debenture issue costs
- ----------------------------------------------------------------------------------------------------------
related to the converted debentures 2,184 3,854 6,038
- ----------------------------------------------------------------------------------------------------------
As at December 31, 2004 10,700 $10,217 15,159 $14,479 $24,696
- ----------------------------------------------------------------------------------------------------------
Fair value at December 31, 2004 $17,441 $21,223 $38,664
- ----------------------------------------------------------------------------------------------------------
15. INCOME TAXES
Future income taxes reflect the net tax effects of temporary differences between
the carrying amounts of assets and liabilities of Harvest Operations and the
Trust's other corporate subsidiaries and their corresponding income tax bases.
The legislated reductions in the Federal and Provincial income tax rates were
implemented as expected in 2004. Federal rates are expected to decline further
until 2007, resulting in an effective tax rate of approximately 34% for the
Trust, which is the rate applied to the temporary differences in the future
income tax calculation.
The provision for future income taxes varies from the amount that would be
computed by applying the combined Canadian Federal and Provincial income tax
rates to the reported income before taxes as follows:
- --------------------------------------------------------------------------------------------
2004 2003
- --------------------------------------------------------------------------------------------
Income before taxes $ 9,374 $ 6,695
- --------------------------------------------------------------------------------------------
Multiplied by tax rate 38.9% 40.6%
- --------------------------------------------------------------------------------------------
Computed income tax expense at statutory rates 3,646 2,718
- --------------------------------------------------------------------------------------------
Amount included in Trust income (17,433) (13,293)
- --------------------------------------------------------------------------------------------
(13,787) (10,575)
- --------------------------------------------------------------------------------------------
Increase (decrease) resulting from the following:
- --------------------------------------------------------------------------------------------
Non-deductible crown charges 1,278 (61)
- --------------------------------------------------------------------------------------------
Resource allowance (1,731) 2,062
- --------------------------------------------------------------------------------------------
Non-tax portion of capital gain 2,633 (1,282)
- --------------------------------------------------------------------------------------------
Unit appreciation rights expense 560 99
- --------------------------------------------------------------------------------------------
Rate change 549 794
- --------------------------------------------------------------------------------------------
Other 136 (15)
- --------------------------------------------------------------------------------------------
Future income tax recovery $ (10,362) $ (8,978)
- --------------------------------------------------------------------------------------------
The components of the future income tax liability (asset) are as follows:
- --------------------------------------------------------------------------------------------------
2004 2003
- --------------------------------------------------------------------------------------------------
Net book value of oil and natural gas assets in excess of tax pools $ 46,333 $ (1,085)
Asset retirement obligation (9,691) (9,468)
Net unrealized gains on derivative contracts and foreign exchange 2,293 -
Tax loss carry forwards (1,172) (1,649)
Deferral of taxable income in partnership 2,339 -
Working capital and other items (5,431) (407)
- --------------------------------------------------------------------------------------------------
Future income tax liability (asset) $ 34,671 $ (12,609)
- --------------------------------------------------------------------------------------------------
The non-capital losses described above expire in the years 2009 and 2010.
16. FINANCIAL INSTRUMENTS
The Trust is exposed to market risks resulting from fluctuations in commodity
prices, foreign exchange rates and interest rates in the normal course of
operations.
(A) FAIR VALUES
Financial instruments of the Trust consist mainly of accounts receivable,
deposits, accounts payable and accrued liabilities, cash distributions payable,
bank debt, convertible debentures and senior notes. Other than as disclosed in
the related notes to the convertible debentures and the senior notes, there were
no significant differences between the carrying values of these financial
instruments reported on the balance sheet and their estimated fair values due to
their short term to maturity
(B) INTEREST RATE RISK
The Trust is exposed to interest rate risk on its bank debt. All of the Trust's
other debt has fixed interest rates.
(C) CREDIT RISK
Substantially all accounts receivable are due from customers in the oil and
natural gas industry and are subject to normal industry credit risks.
Concentration of credit risk is mitigated by having a broad customer base, which
includes a significant number of companies engaged in joint operations with the
Trust. The Trust periodically assesses the financial strength of its partners
and customers, including parties involved in marketing or other commodity
arrangements. The carrying value of accounts receivable reflects management's
assessment of the associated credit risks.
(D) FOREIGN EXCHANGE RATE RISK
The Trust is exposed to the risk of changes in the Canadian/U.S. dollar exchange
rate on sales of commodities that are denominated in U.S. dollars or directly
influenced by U.S. dollar benchmark prices. In addition, the Trust's senior
notes are denominated in U.S. dollars (U.S.$250 million). These notes act as an
economic hedge to help offset the impact of exchange rate movements on commodity
sales during the year. As at December 31, 2004 the full balance of the notes is
still outstanding and is not repayable until October 15, 2011. Interest is
payable semi-annually on the notes in U.S. dollars.
(E) COMMODITY RISK MANAGEMENT
The Trust uses fixed price oil sales contracts and derivative financial
instruments to manage its commodity price exposure. Under the terms of some of
the derivative instruments, Harvest Operations is required to provide security
from time to time based on the underlying market value of those contracts. The
Trust is also exposed to counterparty risk for these derivative contracts. This
risk is managed by diversifying the Trust's derivative portfolio among a number
of counterparties and by dealing with large investment grade institutions. The
following is a summary of the oil sales price derivative contracts as at
December 31, 2004, that have fixed future sales prices:
- ----------------------------------------------------------------------------------------------------------
OIL PRICE SWAP CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
- ----------------------------------------------------------------------------------------------------------
Daily Quantity Term Price per Barrel Mark to Market
Gain (Loss)
- ----------------------------------------------------------------------------------------------------------
500 Bbls/d January through December 2005 U.S. $24.00 $ (4,107)
1,100 Bbls/d January through March 2005 U.S. $22.38 (2,535)
1,030 Bbls/d April through June 2005 U.S. $22.18 (2,358)
50% PARTICIPATING SWAP CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
- ----------------------------------------------------------------------------------------------------------------
8,750 Bbls/d Jan - Dec 2006 U.S. $38.16(b) $ 3,710
OIL PRICE COLLAR CONTRACTS BASED ON WEST TEXAS INTERMEDIATE
- -------------------------- ------------------------------ ------------------------------- ------------------ ---
2,500 Bbls/d January through June 2005 U.S. $28.40 - 32.25 ($21.80) $ (6,032) (a)
1,500 Bbls/d July through December 2005 U.S. $28.17 - 32.10 ($22.33) (3,296) (a)
2,000 Bbls/d January through December 2005 U.S. $28.00 - 42.00 (529)
(a) Harvest has sold put options at the average price denoted in parenthesis,
for the same volumes as the associated commodity contracts. The counterparty may
exercise these options if the respective index falls below the specified price
on a monthly settlement basis.
(b) This price is a floor. The Trust realizes this price plus 50% of the
difference between spot price and this price.
INDEXED PUT OPTION BASED ON WEST TEXAS INTERMEDIATE
- --------------------- ----------------------- --------------------- ----------------- ----------------------
MARK TO MARKET GAIN
DAILY QUANTITY TERM TYPE PRICE PER BBL (LOSS)
- --------------------- ----------------------- --------------------- ----------------- ----------------------
4,000 bbls/d Jan - Dec 2005 Long Put U.S. $30.00 $ 937
1,972 bbls/d Jan - Dec 2005 Short Call U.S. $30.00 (11,261)
1,972 bbl/d Jan - Dec 2005 Long Call U.S. $40.00 4,642
7,000 bbl/d Jan - Dec 2005 Long Put U.S. $35.00 $ 4,050
2,380 bbl/d Jan - Dec 2005 Short Call U.S. $35.00 (9,239)
2,380 bbl/d Jan - Dec 2005 Long Call U.S. $45.00 3,090
7,500 bbl/d Jan - Dec 2005 Long Put U.S. $40.00 $ 9,142
3,675 bbl/d Jan - Dec 2005 Short Call U.S. $40.00 (8,651)
3,675 bbl/d Jan - Dec 2005 Long Call U.S. $50.00 2,678
7,500 bbl/d Jan - June 2006 Long Put U.S. $34.00 $ 2,989
3,750 bbl/d Jan - June 2006 Short Call U.S. $34.00 (7,252)
3,750 bbl/d Jan - June 2006 Long Call U.S. $44.00 3,170
- --------------------- ----------------------- --------------------- ----------------- ----------------------
(1) Each group of a long put, short call and a long call reflect an "indexed put
option". These series of puts and calls serve to fix a floor price while
retaining upward price exposure on a portion of price movements above the floor
price.
The following is a summary of electricity price physical and financial swap
contracts entered into by Harvest Operations to fix the cost of future
electricity usage as well as a put option related to the U.S./Canadian dollar
exchange rate as at December 31, 2004:
- -------------------------------------------------------------------------------------------------------------
SWAP CONTRACTS BASED ON ELECTRICITY PRICES
- -------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE QUANTITY TERM AVERAGE PRICE MARK TO MARKET
PER MEGAWATT GAIN (LOSS)
- -------------------------------------------------------------------------------------------------------------
24.8 MWH January through December 2005 Cdn $47.43 $ 1,272
29.9 MWH January through December 2006 Cdn $47.51 (196)
SWAP CONTRACTS BASED ON ELECTRICITY HEAT RATE
- -------------------------- -------------------------------------------- ----------------- -------------------
QUANTITY TERM HEAT RATE MARK TO MARKET
(LOSS)
- -------------------------- -------------------------------------------- ----------------- -------------------
5 MW January through December 2005 8.40 GJ/MWh $ (80)
- -------------------------- -------------------------------------------- ----------------- -------------------
FOREIGN CURRENCY CONTRACTS
- -------------------------------------------------------------------------------------------------------------
MONTHLY CONTRACT AMOUNT TERM CONTRACT RATE MARK TO MARKET
GAIN
- -------------------------- ------------------------------ ------------------------------- -------------------
U.S. $8.33 million January through December 2005 1.20 Cdn / U.S. $ 4,500(1)
(1) Represents the premium paid on this contract.
At December 31, 2004, the net unrealized loss position reflected on the balance
sheet for all the financial derivative contracts outstanding at that date was
approximately $15.4 million. Harvest Operations has provided deposits to some
counterparties for a portion of its financial derivative contracts, based on the
fair value of those contracts at the end of the trading day.
For the year ended December 31, 2004, the total unrealized loss recognized in
the statement of income was $11.3 million. The realized losses on all derivative
contracts are included in the period in which they are incurred. Both of these
amounts are reflected in Gains and Losses on Derivative Contracts on the
statement of income.
At October 1, 2004, the Trust discontinued hedge accounting for all of its
derivative financial instruments. For those contracts where hedge accounting had
previously been applied, a deferred charge or gain was recorded equal to the
fair value of the contracts at the time hedge accounting was discontinued with a
corresponding amount recorded in the derivative contracts balance. The deferred
charge or gain is 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 in the statement of income. At December 31, 2004,
$10.8 million and $2.2 million has been recorded as a deferred charge and a
deferred gain, respectively on the balance sheet.
- ------------------------------------------------------------------------------------------
DECEMBER 31
- ------------------------------------------------------------------------------------------
DEFERRED CHARGES - ASSET 2004 2003
- ------------------------------------------------------------------------------------------
Balance, beginning of year $ 1,989 $ 2,210
- ------------------------------------------------------------------------------------------
Deferred charge related to derivative contracts
recorded upon adoption of AcG-13 5,490 -
- ------------------------------------------------------------------------------------------
Deferred charge related to derivative contracts
- ------------------------------------------------------------------------------------------
recorded upon discontinuing hedge accounting 20,215 -
- ------------------------------------------------------------------------------------------
Discount on senior notes [NOTE 9] 2,075
- ------------------------------------------------------------------------------------------
Financing costs incurred 13,770 2,335
- ------------------------------------------------------------------------------------------
Amortization of deferred charge related to derivative
contracts(1) (14,946) -
- ------------------------------------------------------------------------------------------
Amortization of deferred financing costs(2) (4,086) (2,556)
- ------------------------------------------------------------------------------------------
Balance, end of year $ 24,507 $ 1,989
- ------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------
DECEMBER 31
- ------------------------------------------------------------------------------------------
DEFERRED GAINS - LIABILITY 2004 2003
- ------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------
Balance, beginning of year $ - $ -
- ------------------------------------------------------------------------------------------
Deferred gains related to derivative contracts
recorded upon discontinuing hedge accounting 2,527 -
- ------------------------------------------------------------------------------------------
Amortization of deferred gains related to derivative
contracts(1) (350) -
- ------------------------------------------------------------------------------------------
Balance, end of year $ 2,177 $ -
- ------------------------------------------------------------------------------------------
(1) Recorded within gains and losses on derivative contracts (2) Recorded within
interest expense
17. RELATED PARTY TRANSACTIONS
Refer to Note 10 regarding equity bridge notes received from a director of
Harvest Operations and a corporation controlled by that director.
A corporation controlled by a director of Harvest Operations sublets office
space and is provided administrative services by Harvest Operations on a cost
recovery basis.
18. CHANGE IN NON-CASH WORKING CAPITAL
- ---------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31
- ---------------------------------------------------------------------------------------------
2004 2003
- ---------------------------------------------------------------------------------------------
Changes in non-cash working capital items:
- ---------------------------------------------------------------------------------------------
Accounts receivable $ (24,860) $ (5,590)
- ---------------------------------------------------------------------------------------------
Prepaid expenses and deposits 9,117 (11,596)
- ---------------------------------------------------------------------------------------------
Current portion of derivative contracts assets (8,861) -
- ---------------------------------------------------------------------------------------------
Accounts payable and accrued liabilities 58,168 12,154
- ---------------------------------------------------------------------------------------------
Cash distributions payable 4,936 1,559
- ---------------------------------------------------------------------------------------------
Current portion of derivative contracts liability 27,927 -
- ---------------------------------------------------------------------------------------------
$ 66,427 $ (3,473)
- ---------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------
Changes relating to operating activities $ (11,103) $(12,290)
- ---------------------------------------------------------------------------------------------
Changes relating to financing activities 5,097 2,889
- ---------------------------------------------------------------------------------------------
Changes relating to investing activities 16,547 329
- ---------------------------------------------------------------------------------------------
Add: Non cash changes 55,886 5,599
- ---------------------------------------------------------------------------------------------
$ 66,427 $ (3,473)
- ---------------------------------------------------------------------------------------------
19. COMMITMENTS, CONTINGENCIES AND GUARANTEES
From time to time, the Trust is involved in litigation or has claims brought
against it in the normal course of business operations. Management of the Trust
is not currently aware of any claims or actions that would materially affect the
Trust's reported financial position or results from operations.
In the normal course of operations, management may also enter into certain types
of contracts that require the Trust to indemnify parties against possible third
party claims, particularly when these contracts relate to purchase and sale
agreements. The terms of such contracts vary and generally a maximum is not
explicitly stated; as such the overall maximum amount of the obligations cannot
be reasonably estimated. Management does not believe payments, if any, related
to such contracts would have a material affect on the Trust's reported financial
position or results from operations.
The Trust has letters of credit outstanding in the amount of approximately $5
million related to electricity infrastructure usage. These letters are provided
by Harvest Operations' lenders pursuant to the credit agreement [Note 8]. These
letters expire throughout 2004 and 2005, and are expected to be renewed as
required.
Following is a summary of the Trust's contractual obligations and commitments as
at December 31, 2004:
PAYMENTS DUE BY PERIOD
- -------------------------------------------------------------------------------------------------------
($000'S) 2005 2006 - 2007 2008 - 2009 THEREAFTER TOTAL
- -------------------------------------------------------------------------------------------------------
Debt repayments (1) 75,519 - - 300,500 376,019
- -------------------------------------------------------------------------------------------------------
Capital commitments 700 - - - 700
- -------------------------------------------------------------------------------------------------------
Operating leases 400 2,869 2,869 956 7,094
- -------------------------------------------------------------------------------------------------------
Total contractual obligations 76,619 2,869 2,869 301,456 383,813
- -------------------------------------------------------------------------------------------------------
(1) Includes long-term and short-term debt. Assumes that the outstanding
convertible debentures either exchange at the holders' option for Units or are
redeemed for Units at the Trust's option.
20. RECONCILIATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
These consolidated financial statements have been prepared in accordance with
Canadian GAAP which, in most respects, conforms to generally accepted accounting
principles in U.S. GAAP. Any differences in accounting principles as they have
been applied to the accompanying consolidated financial statements are not
material except as described below. All items required for financial disclosure
under U.S. GAAP are not noted.
The application of U.S. GAAP would have the following effects on net income as
reported:
- --------------------------------------------------------------------------------------------------
YEAR ENDED
DECEMBER 31,
- --------------------------------------------------------------------------------------------------
2004 2003
- --------------------------------------------------------------------------------------------------
Net income as reported $ 18,231 $ 15,516
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Adjustments
- --------------------------------------------------------------------------------------------------
Unrealized loss on derivative financial instruments (f) 3,886 (9,345)
- --------------------------------------------------------------------------------------------------
Future income tax effect on unrealized loss on derivative
financial instruments (f) (g) (5,251) 3,952
- --------------------------------------------------------------------------------------------------
Future tax impact of deferred charges (f) (g) 2,885 --
- --------------------------------------------------------------------------------------------------
Interest on convertible debentures (d) (5,223) --
- --------------------------------------------------------------------------------------------------
Interest on equity bridge notes (d) (1,070) (870)
- --------------------------------------------------------------------------------------------------
Amortization of deferred financing charges (d) (546) --
- --------------------------------------------------------------------------------------------------
Non-cash general and administrative expenses (c) 1,455 (1,288)
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Net income under US GAAP before cumulative effect
of change in accounting policy 14,367 7,965
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Cumulative effect of change in accounting policy (b) -- (304)
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Net income under US GAAP after cumulative effect of change
in accounting policy 14,367 7,661
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Increase in redemption value of trust units under US GAAP (e) (298,893) (48,362)
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Net loss available to unitholders under US GAAP (e) $ (284,526) $(40,701)
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
BASIC
- --------------------------------------------------------------------------------------------------
Net income under US GAAP before cumulative effect of
change in accounting policy $ 0.57 $ 0.63
- --------------------------------------------------------------------------------------------------
Cumulative effect of change in accounting policy (b) -- (0.02)
- --------------------------------------------------------------------------------------------------
Net income after the cumulative effect of change in accounting
policy (before changes in redemption value of trust units 0.57 0.61
- --------------------------------------------------------------------------------------------------
Net loss available to unitholders per trust unit under
- --------------------------------------------------------------------------------------------------
US GAAP $ (11.24) $ (3.23)
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
DILUTED
- --------------------------------------------------------------------------------------------------
Net income under US GAAP before cumulative effect of change
in accounting policy $ 0.54 $ 0.61
- --------------------------------------------------------------------------------------------------
Cumulative effect of change in accounting policy (0.02)
- --------------------------------------------------------------------------------------------------
Net income after the cumulative effect of change in
accounting policy (before changes in redemption value of trust units $ 0.54 $ 0.59
- --------------------------------------------------------------------------------------------------
Net loss available to unitholders per trust unit under
- --------------------------------------------------------------------------------------------------
U.S GAAP $ (11.24) $ (3.23)
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
The application of U.S. GAAP would have the following effect on the consolidated
balance sheets as reported:
- ----------------------------------------------------------------------------------------------------
DECEMBER 31, 2004 December 31, 2003
- ----------------------------------------------------------------------------------------------------
GAAP CANADIAN US Canadian US
GAAP GAAP GAAP GAAP
- ----------------------------------------------------------------------------------------------------
Assets
- ----------------------------------------------------------------------------------------------------
Current portion of derivative contracts (f) $ 8,861 $ 8,861 $ -- $ --
- -------------------------------------------------- --------- --------- --------- ---------
Capital assets (a) 918,397 918,397 210,543 210,543
- -------------------------------------------------- --------- --------- --------- ---------
Long term portion of derivative contracts (f) 3,710 3,710 -- --
- -------------------------------------------------- --------- --------- --------- ---------
Deferred charges (f) (d) 24,507 12,768 1,989 1,989
- -------------------------------------------------- --------- --------- --------- ---------
Future taxes (g) -- -- 12,609 17,860
- -------------------------------------------------- --------- --------- --------- ---------
- -------------------------------------------------- --------- --------- --------- ---------
Liabilities
- -------------------------------------------------- --------- --------- --------- ---------
Derivative contracts (f) 27,927 27,927 -- 12,468
- -------------------------------------------------- --------- --------- --------- ---------
Deferred gains (f) 2,177 -- -- --
- -------------------------------------------------- --------- --------- --------- ---------
Senior notes (i) 300,500 298,488
- -------------------------------------------------- --------- --------- --------- ---------
Convertible debentures - liability (d) -- 25,859 -- --
- -------------------------------------------------- --------- --------- --------- ---------
Equity bridge notes - liability (d) -- -- -- 25,000
- -------------------------------------------------- --------- --------- --------- ---------
Asset retirement obligation (b) 90,085 90,085 42,009 42,009
- -------------------------------------------------- --------- --------- --------- ---------
Future taxes (f)(g) 34,671 31,786 -- --
- -------------------------------------------------- --------- --------- --------- ---------
- -------------------------------------------------- --------- --------- --------- ---------
867,452 -- 213,692
Temporary equity (e)
- -------------------------------------------------- --------- --------- --------- ---------
- -------------------------------------------------- --------- --------- --------- ---------
Unitholders' Equity
- -------------------------------------------------- --------- --------- --------- ---------
Unitholders' capital (e) $ 465,131 $ -- $ 117,407 $ --
- -------------------------------------------------- --------- --------- --------- ---------
Equity bridge notes (d) -- -- 25,000 --
- -------------------------------------------------- --------- --------- --------- ---------
Convertible debentures (d) 24,696 -- -- --
- -------------------------------------------------- --------- --------- --------- ---------
Exchangeable shares (e) 6,728 -- -- --
- -------------------------------------------------- --------- --------- --------- ---------
Contributed surplus (c) -- -- 239 1,694
- -------------------------------------------------- --------- --------- --------- ---------
Accumulated income 31,416 (370,005) 19,478 (85,479)
- -------------------------------------------------- --------- --------- --------- ---------
(a) Under Canadian GAAP, the Trust performs an impairment test that limits the
capitalized costs of its oil and natural gas assets to the discounted estimated
future net revenue from proved and risked probable oil and natural gas reserves
plus the cost of unproved properties less impairment, using forward prices. The
discount rate used is equal to the Trust's risk free interest rate. Under U.S.
GAAP, entities using the full cost method of accounting for oil and natural gas
activities perform an impairment test on each cost centre using discounted
future net revenue from proved oil and natural gas reserves discounted at 10%.
The prices used under the U.S. GAAP ceiling tests are those in effect at year
end. There was no impairment under U.S. GAAP at December 31, 2004 or 2003.
(b) Effective January 1, 2004, the Trust retroactively adopted the CICA Handbook
standard for accounting for asset retirement obligations. This section is
equivalent to Statement of Financial Accounting Standards ("SFAS") No. 143 for
fiscal periods beginning on or after January 1, 2003. The transitional
provisions between Canadian GAAP and U.S. GAAP differ however, as Canadian GAAP
requires a restatement of comparative amounts whereas U.S. GAAP does not allow
restatement.
(c) During the year, the Trust modified the Trust Unit incentive plan to include
a feature that allows participants to receive cash for the value of their Units
at their sole option. As such, under Canadian GAAP the Trust now determines
compensation expense based on the excess of the market price over the adjusted
exercise price of all of the rights outstanding at the end of each reporting
period and the expense is deferred and recognized in income over the vesting
period of the rights, with a corresponding amount recorded to liabilities. After
the rights have vested, compensation expense is recognized in income in the
period in which a change in the market price of the Trust Units or the exercise
price of the rights occurs. For the year ended December 31, 2003, under Canadian
GAAP, the Trust used the fair value method to account for these rights.
For U.S. GAAP purposes, the Trust Unit incentive plan is a variable compensation
plan as the exercise price of the rights is subject to downward revisions from
time to time. Accordingly, compensation expense is determined using the same
method as under Canadian GAAP for 2004. An adjustment is made to reflect
compensation expense recorded under U.S. GAAP
relating to rights issued in 2002 previously not expensed under Canadian GAAP.
For the year ended December 31, 2003, an adjustment is also made for the
difference between compensation expense using the fair value method and the
intrinsic method used.
(d) Under Canadian GAAP, the equity bridge notes and convertible debentures are
classified as Unitholders' equity and the interest accrued and paid on the
equity bridge notes and convertible debentures has been recorded as a reduction
of accumulated income. Issue costs are netted against equity and interest
expense is recorded as a financing activity in the statement of cash flows.
Under U.S. GAAP, the equity bridge notes and convertible debentures are
classified as long-term debt. Accordingly, an adjustment has been made to net
income to reflect interest expense on both instruments under U.S. GAAP. Under
U.S. GAAP the interest expense would be reported as a reduction to operating
cash flows in the statement of cash flows.
Issue costs related to the convertible debentures have been classified as
deferred charges for U.S. GAAP and amortized into income.
(e) Under the Trust Indenture, Trust Units are redeemable at any time on demand
by the Unitholder for cash. Under U.S. GAAP, the amount included on the
consolidated balance sheet for Unitholders' Equity would be reduced by an amount
equal to the redemption value of the Trust Units as at the balance sheet date.
The same accounting treatment would be applicable to the exchangeable shares.
The redemption value of the Trust Units and the exchangeable shares is
determined with respect to the trading value of the Trust Units as at each
balance sheet date, and the amount of the redemption value is classified as
temporary equity. Increases, if any, in the redemption value during a period
results in a charge to permanent equity and is reflected as a reduction in
earnings available to Unitholders for the year.
(f) Under U.S. GAAP, SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities" requires that all derivative instruments be recorded on the
consolidated balance sheet as either an asset or liability measured at fair
value, and requires that changes in fair value be recognized currently in income
unless specific hedge accounting criteria are met. U.S. GAAP requires that a
company formally document, designate, and assess the effectiveness of derivative
instruments before they can receive this accounting treatment. The Trust had not
formally documented and designated all hedging relationships as at December 31,
2004 or December 31, 2003, and as such was not eligible for hedge accounting
treatment.
Upon adoption of AcG-13, the Trust has implemented fair value accounting
effective January 1, 2004 under Canadian GAAP and had designated a portion of
its derivative contracts as hedges. A difference does arise due to the adoption
of fair value accounting under Canadian GAAP. Upon discontinuing hedge
accounting a deferred charge or gain is recorded representing the fair value of
the contract at that time. This difference is amortized over the term of the
contract. During the year, the Trust discontinued hedge accounting for all
derivative contracts under Canadian GAAP. Under U.S. GAAP there were no
contracts designated as hedges. To the extent deferred charges and gains are
recorded and amortized when hedge accounting was discontinued, there is a
difference between Canadian and U.S. GAAP.
(g) The Canadian GAAP liability method of accounting for income taxes is similar
to the U.S. GAAP SFAS 109, "Accounting for Income Taxes", which requires the
recognition of tax assets and liabilities for the expected future tax
consequences of events that have been recognized in the Trust's consolidated
financial statements. Pursuant to U.S. GAAP, enacted tax rates are used to
calculate future income tax, whereas Canadian GAAP uses substantively enacted
rates. There are no differences for the year ended December 31, 2004 or the year
ended December 31, 2003 relating to tax rate differences.
Upon adoption of fair value accounting for derivative contracts under Canadian
GAAP, deferred charges and gains were set up when hedge accounting was
discontinued. As there is no tax base relating to these amounts a temporary
difference was created. This difference does not exist under U.S. GAAP as there
are no deferred charges or gains under U.S. GAAP. In addition, to the extent
there were historical differences with respect to Canadian and U.S. GAAP due to
derivative contract assets and liabilities, these amounts are now required to be
eliminated as the balances of those accounts under Canadian and U.S. GAAP are
now the same.
At December 31, 2003, the difference relates to the recording of a derivative
contract liability under U.S. GAAP and not under Canadian GAAP.
(h) Unless otherwise noted, the consolidated statements of cash flows prepared
in accordance with Canadian GAAP conform in all material respects with U.S.
GAAP, with the exception that Canadian GAAP allows for the presentation of a
subtotal of cash flows from operating activities before changes in non-cash
working capital items in the consolidated statement of cash flows. This
sub-total cannot be presented under U.S. GAAP.
(i) Under Canadian GAAP, the discount on the senior notes has been recorded in
deferred charges. Under U.S. GAAP, this amount is required to be applied against
the senior notes balance.
The following are standards and interpretations that have been issued by the
Financial Accounting Standards Board ("FASB") and the Trust has assessed the
impact to be as follows:
In December 2004, FASB issued statement 123R "Share Based Payments" that
addresses the accounting for share-based payment transactions in which an
enterprise receives employee services in exchange for (a) equity
instruments of the enterprise or (b) liabilities that are based on the fair
value of the enterprise's equity instruments or that may be settled by the
issuance of such equity instruments. The proposal eliminates the ability to
account for share-based compensation transactions using APB 25, "Accounting
for Stock Issued to Employees", and generally requires instead, that such
transactions be accounted for using a fair-value-based method. The
effective date would be for the first interim or annual period beginning on
or after June 15, 2005, for awards granted on or after the effective date.
Management has not yet assessed the impact of this standard on its
consolidated financial statements.
In December 2004, FASB issued statement number 153 "Exchanges of
Nonmonetary Assets - an amendment of APB Opinion No. 29". This Statement
amends Opinion 29 to eliminate the exception for nonmonetary exchanges of
similar productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of
the entity are expected to change significantly as a result of the
exchange. Management does not expect this statement to have a material
impact on its consolidated financial statements.
Additional disclosures required under U.S. GAAP:
- --------------------------------------------------------------------------------------------
(THOUSANDS OF CANADIAN DOLLARS)
- --------------------------------------------------------------------------------------------
DECEMBER 31, 2004 December 31, 2003
- --------------------------------------------------------------------------------------------
Components of accounts receivable
- --------------------------------------------------------------------------------------------
Trade $ 14,743 $ 16,334
- --------------------------------------------------------------------------------------------
Accruals 29,285 2,834
- --------------------------------------------------------------------------------------------
$ 44,028 $ 19,168
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Components of prepaid expenses
- --------------------------------------------------------------------------------------------
Prepaid expenses $ 1,730 $ 232
- --------------------------------------------------------------------------------------------
Funds on deposit 1,284 11,899
- --------------------------------------------------------------------------------------------
$ 3,014 $ 12,131
- --------------------------------------------------------------------------------------------
CORPORATE INFORMATION
DIRECTORS
JOHN A. BRUSSA(1)(3)(4)
M. BRUCE CHERNOFF, CHAIRMAN(2)(3)
VERNE G. JOHNSON(1)(2)(4)
HECTOR J. MCFADYEN(1)(3)(4)
HANK B. SWARTOUT(2)
(1) Member of the Audit Committee.
(2) Member of the Reserves, Safety and Environment Committee.
(3) Member of the
Compensation Committee.
(4) Member of the Corporate Governance Committee.
OFFICERS
JACOB ROORDA, P.ENG.
PRESIDENT
J.A. (AL) RALSTON
VICE PRESIDENT, OPERATIONS
JAMES A CAMPBELL, P. GEOL.
VICE PRESIDENT, GEOSCIENCES
DAVID J. RAIN, C.A.
VICE PRESIDENT, CHIEF FINANCIAL
OFFICER AND CORPORATE SECRETARY
KEY PERSONNEL
J. HOWARD BYE
FIELD SUPERINTENDENT, NORTH
RENATA COLIC, C.A.
MANAGER, FINANCIAL REPORTING
RANDY DOETZEL
MANAGER, PRODUCTION
DARCY ERICKSON, P. ENG.
MANAGER, DRILLING & COMPLETIONS
DANIELLE GALLANT, C.A.
MANAGER, CORPORATE FINANCE
CINDY GRAY
INVESTOR RELATIONS & COMMUNICATIONS
JOHN KEIRLE
MANAGER, LAND
MATTHEW MAZURYK, P. ENG.
MANAGER, ENGINEERING
ALLAN POST
OPERATIONAL CONTROLLER
STEVE SAUNDERS, C.A.
DIRECTOR, TAXATION
ROBERT SAYNA
FIELD SUPERINTENDENT, SOUTH
CORPORATE ADDRESS
2100, 330-5th Avenue S.W.
Calgary, Alberta T2P 0L4
Telephone: (403) 265-1178
Fax: (403) 265-3490
WEBSITE
WWW.HARVESTENERGY.CA
EXCHANGE LISTING
Toronto Stock Exchange: HTE.UN
REGISTRAR AND TRANSFER AGENT
Valiant Trust Company
310, 606 - 4th St. SW
Calgary, AB T2P 1T1
Telephone: (403) 233-2801
AUDITOR
KPMG LLP
Calgary, Alberta
INVESTOR RELATIONS
Cindy Gray, Investor Relations & Communications
General inquiries: information@harvestenergy.ca
Toll-free number: 1-866-666-1178
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2100, 330-5th Avenue S.W.
Calgary, Alberta T2P 0L4
(403) 265-1178
information@harvestenergy.ca
www.harvestenergy.ca