##### 



EXHIBIT 99.4 MANAGEMENTS DISCUSSION AND ANALYSIS The following is Managements Discussion and Analysis (MD&A) of Paramount
Energy Trusts operating and financial results for the year ended December
31, 2003, as well as information and estimates concerning the Trusts future
outlook based on currently available information. This discussion should be
read in conjunction with the Trusts audited consolidated financial
statements for the years ended December 31, 2003 and 2002, together with
accompanying notes. Financial and Operating
Highlights(1) Three Months Ended December 31
    
    Year Ended December 31($Cdn thousands, except as noted)
    
    2003
    
    2002
    
    2003
    
    2002
    
    2001FinancialRevenue before royalties
    
    
    41,022
    
    
    
    40,576
    
    
    
    201,239
    
    
    
    123,739
    
    
    
    228,283Per Unit(2)
    
    
    0.92
    
    
    
    1.02
    
    
    
    4.72
    
    
    
    3.12
    
    
    
    5.76Cash flow(3)
    
    
    25,138
    
    
    
    18,756
    
    
    
    126,360
    
    
    
    59,699
    
    
    
    101,416Per Unit(2)
    
    
    0.56
    
    
    
    0.47
    
    
    
    2.97
    
    
    
    1.51
    
    
    
    2.56Net earnings (loss)(4)
    
    
    (2,812
    )
    
    
    7,497
    
    
    
    52,434
    
    
    
    7,406
    
    
    
    60,713Per Unit(2)
    
    
    (0.06
    )
    
    
    0.19
    
    
    
    1.23
    
    
    
    0.19
    
    
    
    1.53Cash distributions
    
    
    26,783
    
    
    
    n/a
    
    
    
    123,202
    
    
    
    n/a
    
    
    
    n/aPer Unit(5)
    
    
    0.60
    
    
    
    n/a
    
    
    
    2.884
    
    
    
    n/a
    
    
    
    n/aTotal assets
    
    
    260,984
    
    
    
    277,348
    
    
    
    260,984
    
    
    
    277,348
    
    
    
    299,853Net debt outstanding
    
    
    54,189
    
    
    
    n/a
    
    
    
    54,189
    
    
    
    n/a
    
    
    
    n/aCapital expendituresExploration, development and other
    
    
    1,043
    
    
    
    3,893
    
    
    
    9,084
    
    
    
    14,296
    
    
    
    41,863Acquisitions
    
    
    13,771
    
    
    
    
    
    
    
    32,252
    
    
    
    
    
    
    
    Trust Units Outstanding(thousands)End of period(7)
    
    
    44,638
    
    
    
    39,638
    
    
    
    44,638
    
    
    
    39,638
    
    
    
    39,638Weighted average(7)
    
    
    44,638
    
    
    
    39,638
    
    
    
    42,597
    
    
    
    39,638
    
    
    
    39,638Diluted
    
    
    45,322
    
    
    
    39,638
    
    
    
    43,238
    
    
    
    39,638
    
    
    
    39,638March 19, 2004
    
    
    44,765
    
    
    
    n/a
    
    
    
    44,765
    
    
    
    n/a
    
    
    
    n/aOperatingProductionTotal natural gas (Bcf)
    
    
    7.5
    
    
    
    8.4
    
    
    
    31.2
    
    
    
    34.6
    
    
    
    37.5Daily average natural gas (Mcf/d)
    
    
    81,199
    
    
    
    91,031
    
    
    
    85,574
    
    
    
    94,842
    
    
    
    102,704Average priceNatural gas ($/Mcf)
    
    
    5.49
    
    
    
    4.89
    
    
    
    6.44
    
    
    
    3.57
    
    
    
    6.09ReservesProved plus probable(6)Natural gas (Bcf)
    
    
    148.8
    
    
    
    183.9
    
    
    
    148.8
    
    
    
    183.9
    
    
    
    205.3LandUndeveloped land holdings (thousands of net acres)
    
    
    322
    
    
    
    364
    
    
    
    322
    
    
    
    364
    
    
    
    n/aDrillingWells drilled (gross)Gas
    
    
    
    
    
    
    
    
    
    
    16
    
    
    
    16
    
    
    
    38Service
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    Dry
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    3Total
    
    
    
    
    
    
    
    
    
    
    17
    
    
    
    20
    
    
    
    41Success rate (%)
    
    
    
    
    
    
    
    
    
    
    100
    
    
    
    90
    
    
    
    93
 14




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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS  (1)
    
    All amounts in this report include the operations and results of the
Northeast Alberta properties of Paramount Resources Ltd. (PRL) which were
acquired by Paramount Energy Trust (PET) during the three months ended March
31, 2003. The consolidated financial statements have been prepared on a
continuity of interests basis which recognizes PET as the successor entity
to PRLs Northeast Alberta core area of operations as PET acquired
substantially all of PRLs natural gas assets in that region.(2)
    
    Based on weighted average Trust Units outstanding for the period.(3)
    
    Management uses cash flow (before changes in non-cash working
capital) to analyze operating performance and leverage. Cash flow 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. Cash flow as presented is not
intended to represent operating cash flow or operating profits for the
period nor should it be viewed as an alternative to cash flow from
operating activities, net earnings or other measures of financial
performance calculated in accordance with Canadian GAAP. All references
to cash flow throughout this report are based on cash flow before
changes in non-cash working capital.(4)
    
    Net earnings for 2002 and 2001 have been restated to reflect the
retroactive application of a change in accounting policy relating to
asset retirement obligations.(5)
    
    Based on Trust Units outstanding at each cash distribution date.(6)
    
    As evaluated by McDaniel & Associates Consultants Ltd. in accordance
with National Instrument Nl 51-101. 2002 and 2001 figures are proved
plus 1⁄2 probable for comparability under Nl 51- 101. See Reserves.(7)
    
    The Trust Units indicated for periods prior to March 31, 2003 are pro
forma. Actual Units were issued by PET in the first and second quarters
of 2003. On February 3, 2003, 9.9 million Units were issued to PRL,
which in turn issued these Units to shareholders as a dividend in-kind.
On March 11, 2003 pursuant to a Rights Offering, 29.7 million Units were
issued . Forward Looking Information This MD&A contains forward-looking information with respect to Paramount
Energy Trust. The use of any of the words anticipate, continue, estimate, expect,
may, will, project, should, believe, outlook and similar
expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other
factors that may cause actual results or events to differ materially from those
anticipated in our forward-looking statements. We believe the expectations
reflected in these forward-looking statements are reasonable. However, we
cannot assure the reader that these expectations will prove to be correct. The
reader should not unduly rely on forward-looking statements included in this
report. These statements speak only as of the date of the MD&A, being March 26,
2004. In particular, this MD&A contains forward-looking statements pertaining to the
following:  
    
    the quantity and recoverability of our reserves;
    
    the timing and amount of future production;
    
    prices for natural gas produced;
    
    operating and other costs;
    
    business strategies and plans of Management;
    
    supply and demand for natural gas;
    
    expectations regarding our ability to raise capital and to add to our
reserves through acquisitions as well as exploration and development;
    
    the focus of capital expenditures on development activity rather than
exploration;
    
    the sale, farming in, farming out or development of certain exploration
properties using third party resources;
    
    the use of development activity and acquisitions to replace and add to
reserves;
    
    the impact of changes in natural gas prices on cash flow after hedging;
    
    drilling plans;
    
    the existence, operations and strategy of the commodity price risk
management program;
    
    the approximate and maximum amount of forward sales and hedging to be
employed;
    
    the Trusts acquisition strategy, and the criteria to be considered and
the benefits to be derived;
    
    the impact of Canadian federal and provincial governmental regulation
on the Trust relative to other issuers of similar size;
    
    our treatment under governmental regulatory regimes;
    
    the goal to sustain or grow production and reserves through prudent
management and acquisitions;   15




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##### 



Paramount Energy Trust  
    
    the emergence of accretive growth opportunities; and
    
    the Trusts ability to benefit from the combination of growth
opportunities and the means to grow through the capital markets. Our actual results could differ materially from those anticipated in our
forward-looking statements as a result of the risk factors set forth below and
elsewhere in this MD&A which include but are not limited to:  
    
    volatility in market prices for natural gas;
    
    risks inherent in our operations;
    
    uncertainties associated with estimating reserves;
    
    competition for, among other things: capital, acquisitions of reserves,
undeveloped lands and skilled personnel;
    
    incorrect assessments of the value of acquisitions;
    
    geological, technical, drilling and process problems;
    
    general economic conditions in Canada, the United States and globally;
    
    industry conditions including fluctuations in the price of natural gas;
    
    royalties payable in respect of PETs production;
    
    governmental regulation of the oil and gas industry, including
environmental regulation;
    
    fluctuation in foreign exchange or interest rates;
    
    unanticipated operating events that can reduce production or cause
production to be shut-in or delayed;
    
    stock market volatility and market valuations; and
    
    the need to obtain required approvals from regulatory
authorities. The above list of risk factors should not be construed as exhaustive. Evaluation of Disclosure Controls and Procedures The Chief Operating Officer, Susan Riddell Rose, and Chief Financial Officer,
Cameron Sebastian, evaluated the effectiveness of PETs disclosure controls and
procedures as of December 31, 2003 (the Evaluation Date), and concluded that
PETs disclosure controls and procedures were effective to ensure that
information PET is required to disclose in its filings with the Securities and
Exchange Commission under the Securities Exchange Act of 1934 (the Exchange
Act) is recorded, processed, summarized and reported, within the time periods
specified in the Commissions rules and forms, and to ensure that information
required to be disclosed by PET in the reports that it files under the Exchange
Act is accumulated and communicated to PETs Management, including its
principal operating officer and principal financial officer, as appropriate to
allow timely decisions regarding required disclosure. Changes to Internal Controls and Procedures for Financial Reporting There were no significant changes to PETs internal controls or in other
factors that could significantly affect these controls subsequent to the
Evaluation Date. Mechanics of Creation of the Trust The Trust was formed through a series of transactions as described below: On February 3, 2003:  (1)
    
    PET acquired the Legend property from PRL for an $81 million
promissory note;(2)
    
    PET issued approximately 9.9 million Trust Units to PRL, and(3)
    
    PRL declared a dividend to be paid to its shareholders on February
12, 2003 of these Trust Units, at one Unit per 6.071646 shares, valued
at $5.15 per Trust Unit, or approximately $0.85 per PRL Common Share. On February 17, 2003:  (4)
    
    PET issued three Rights per Trust Unit to acquire additional Trust
Units at $5.05 per Unit. On March 11, 2003:  (5)
    
    With proceeds of the Rights Offering of approximately $150 million,
which was successfully closed with full subscription on March 10, 2003,
plus bank debt, PET purchased from PRL the majority of PRLs remaining
Northeast Alberta natural gas assets for $220 million. The effective
date of the property transactions was July 1, 2002 which, after
adjustment for net cash flow and interest, resulted in the Trust
assuming $70 million in bank debt. Business Plan and Strategy PET is a natural gas focused Canadian energy royalty trust actively managed to
generate monthly cash distributions for Unitholders. The Trusts operations are
focused in Canada with its core assets presently concentrated in Northeast
Alberta. PET is Canadas only 100 percent natural gas royalty Trust. PET seeks to be highly profitable generating premium after-tax returns at an
acceptable risk for all stakeholders. Maximizing total return to Unitholders in
the form of cash distributions and change in Unit price is a paramount
objective. Strategies for achieving this objective include attentive management
of all costs and capital expenditures, prudent use of financial leverage,
optimization of our existing asset base, land stewardship and the pursuit of
accretive acquisitions. At the same 16




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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS time, Management also attempts to mitigate commodity price volatility through
an active hedging and price management program. PET has a strategy to focus its vision of accretive growth on existing core
areas and pursue field optimization and cost control within those core areas to
maximize asset value. The Trust strives to control its operations whenever
possible, and to maintain high working interests. PET operates over 90 percent
of its properties and owns facilities that gather and process much of its
production allowing the Trust to use existing infrastructure and synergies
within core areas. PET believes this high level of operatorship can translate
to controlling costs, timing of capital outlays and projects as well as
providing competitive advantages for future opportunities. PET holds a fundamental belief in the cyclical nature of the oil and gas
industry.The interaction of supply and demand will force corrections in
commodity price anomalies. Consequently the Trusts business plan is adjustable
depending on where we are in a particular cycle. This thought process impacts
marketing strategies, financing decisions, acquisition evaluations and capital
allocations. PETs Business
Approach  Take Advantage of the Cycle (PICTURE) Corporate Governance PET is committed to maintaining high standards of corporate governance. While
their intent is similar, each regulatory body has a different set of rules
pertaining to corporate governance including the Toronto Stock Exchange, the
Canadian provincial securities commissions and the U.S. Securities and Exchange
Commission whose responsibilities include implementing rules under the United
States Sarbanes-Oxley Act of 2002. PET fully conforms to the rules of the
governing bodies under which it operates and, in many cases, we already comply
with proposals and recommendations that have not yet come into force. Full
disclosure of this compliance is provided within PETs information circulars
and on the Trusts website. Gas over Bitumen Issue The Alberta Energy and Utilities Board (AEUB or the Board) issued General
Bulletin (GB) 2003-28 (the Bulletin) on July 22, 2003. The AEUB continues to
consider that gas production in pressure communication with potentially
recoverable bitumen places future bitumen recovery at an unacceptable risk. On
January 26, 2004, the AEUB Staff Submission Group (SSG) released its
recommendations for the shut-in of producing wells with total average daily
production of 135 MMcf/d as of August 31, 2003 or approximately one percent of
the natural gas production of the Province of Alberta. Pursuant to Interim
Shut-in Order 03-001, approximately 95 MMcf/d was shut-in by industry on
September 1, 2003. A shut-in date has not been announced for the remaining 40
MMcf/d recommended for shut-in by the SSG. A total of 24.1 MMcf/d of production
net to PET was recommended for shut-in by the SSG which includes 7.6 MMcf/d of
the gas shut-in on September 1, 2003 and an additional 16.5 MMcf/d of PETs
production which was previously exempted from Interim Shut-in Order 03-001. PET submitted substantial technical evidence to the AEUB on February 23, 2004
with respect to the many wells for which the Trust objects to the shut-in
recommendations of the AEUBs SSG. While the task of providing adequate
technical evidence to support continued gas production prior to the AEUB
deadline was impossible, some evidence was provided for all of PETs affected
assets. AEUB Interim Hearings with respect to this matter began on March 10,
2004. The AEUB decision with respect to the Interim Hearing has not yet been
released. On February 27, 2004 the Alberta Court of Appeal granted a stay of
the AEUB hearing process to the extent that it applies to wells for which the
productive status was previously determined under AEUB Decision 2003-23
following the Chard/Leismer Hearing. This has excluded 0.7 MMcf/d of PET
production from the current proceedings. The Alberta Court of Appeal declined
to grant a stay of the March Interim Hearing; however, PET and others have
been granted Leave to Appeal the entire GB 2003-28 process subject to the AEUB
not providing a fair and reasonable process. A date for the hearing of that
appeal has not been set. Until the AEUB determines the final productive status of the wells, PET cannot
accurately estimate the amount of production that will be shut-in, if any, and
for what duration. The amount and timing of compensation for having to shut-in
such production is also not determinable at this time. In order to establish a
base level of certainty, PETs current estimates of future cash flow and
distributions assume the shut-in of gas volumes as recommended by the SSG and
that any compensation for such shut-in, other than the temporary financial
assistance program of $0.60 per Mcf presently in place, is delayed
indefinitely. The implications of 17




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##### 



Paramount Energy Trust AEUB GB 2003-28 on PETs gas production have been fully described in previous
press releases and other documents which can be viewed on PETs website at
www.paramountenergy.com. Production Volumes Production volumes averaged 85.6 MMcf/d in 2003 compared to 94.8 MMcf/d in
2002, a decrease of 10 percent. Natural production declines as well as the 7.9
MMcf/d of natural gas sales shut-in pursuant to AEUB Interim Shut-in Order
03-001 on September 1, 2003 were offset by a successful capital program as well
as the acquisition of the Ells property in March, Epact Exploration Ltd. in
November and other minor acquisitions which consolidated some of the Trusts
interests in its properties. The Trust estimates that the year-over-year
production volume decrease would have been less than seven percent without the
shut-in of gas on September 1, 2003 pursuant to the AEUB Shut-in Order. PET
intends to continue to attempt to mitigate the effects of natural production
declines in the future through exploitation of its existing asset base as well
as pursuing accretive acquisitions. Production 2003
    
    2002
    
    2001Natural gas (MMcf/d)
    
    
    85.6
    
    
    
    94.8
    
    
    
    102.7
 Production in the fourth quarter of 2003 averaged 81.2 MMcf/d compared to 88.5
MMcf/d in the third quarter. This decrease reflects the AEUB shut-in as of
September 1 and the fact that the Epact acquisition did not close until
November. Commodity Prices U.S. natural gas prices are typically referenced off NYMEX at the Henry Hub in
Louisiana while western Canada natural gas prices are referenced to the AECO
Hub in Alberta. AECO Hub prices were $6.70 per Mcf and $4.07 per Mcf for 2003
and 2002 respectively, an increase of 65 percent. In 2003, approximately 38 percent of natural gas production was sold to
aggregators, 18 percent was sold at fixed prices, 39 percent was sold into the
Alberta Spot Market and five percent to the long-term index market with price
indexed to the AECO Monthly Index. The Alberta Gas Reference Price is the monthly weighted average of an
intra-Alberta consumers price and an ex-Alberta border price, reduced by
allowances for transporting and marketing gas. The Alberta Gas Reference Price
is used to calculate Alberta Gas Crown Royalties. The Alberta Gas Reference
Price increased 58 percent from $3.88 per Mcf in 2002 to $6.13 per Mcf in 2003. PETs average wellhead gas price, prior to hedging transactions, increased by
71 percent to $6.11 per Mcf in 2003 from $3.57 per Mcf in 2002. PETs average
gas price after hedging transactions was $6.44 per Mcf and $3.57 per Mcf in
2003 and 2002 respectively. Natural Gas Production (MMcf/d) (BAR CHART) 2003 Natural Gas Markets (%) (PIE CHART) Natural Gas Price ($/Mcf) (LINE GRAPH) 18




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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS Prices and Marketing 2003
    
    2002
    
    2001Reference pricesAECO gas ($/Mcf)
    
    $
    6.70
    
    
    $
    4.07
    
    
    $
    6.30Alberta Gas Reference Price ($/Mcf)
    
    $
    6.13
    
    
    $
    3.88
    
    
    $
    5.41Average PET pricesNatural gas, before hedging ($/Mcf)
    
    $
    6.11
    
    
    $
    3.57
    
    
    $
    6.09% AECO, before hedging
    
    
    91
    %
    
    
    88
    %
    
    
    97
    %% Alberta Gas Reference Price, before
hedging
    
    
    100
    %
    
    
    92
    %
    
    
    113
    %Natural gas, after hedging ($/Mcf)
    
    $
    6.44
    
    
    $
    3.57
    
    
    $
    6.09% AECO, after hedging
    
    
    96
    %
    
    
    88
    %
    
    
    97
    %% Alberta Gas Reference Price, after hedging
    
    
    105
    %
    
    
    92
    %
    
    
    113
    %
 PETs average wellhead gas price prior to hedging transactions in the
fourth quarter was $5.06, a decrease of nine percent from $5.58 in third
quarter. PETs average gas price after hedging transactions in the fourth
quarter was $5.49 per Mcf compared to $5.76 in the third quarter. Revenue Natural gas revenue in 2003 was $201.2 million, representing a 63 percent
increase from $123.7 million in 2002. Revenue growth was achieved via higher
natural gas prices coupled with prudent hedging. Revenue ($ thousands)
    
    2003
    
    2002
    
    2001Natural gas revenue, before
hedging
    
    
    190,921
    
    
    
    123,739
    
    
    
    228,283Hedging receipts
    
    
    10,318
    
    
    
    
    
    
    
    Total revenue
    
    
    201,239
    
    
    
    123,739
    
    
    
    228,283
 As a result of lower production and gas prices, revenue in the fourth quarter
decreased to $41.0 million from $46.8 million in the third quarter. Hedging and Risk Management The Trusts hedging activities are conducted in consultation with the Board of
Directors of the Administrator of the Trust with the objective of using a
proactive and opportunistic approach to hedging in order to maximize
distributable income while managing price risk, rather than a routine
portfolio approach. A number of market analysis tools are used in an attempt
to identify perceived anomalies or trends in natural gas markets. In addition
hedging may be used to ensure the economics related to significant
acquisitions. Generally the Trust limits its hedging activity for any given
period to 50 percent of forecast production for that period. In 2003, the Trusts hedging activities resulted in a net receipt of $10.3
million or $0.33 per Mcf. Activity in 2002 did not include any hedging as the
2002 results represent an allocation of the Northeast Alberta operations of
PRL. PET currently has the following natural gas hedges in place: Natural Gas Hedging(1) Gigajoules/day(GJ/d)
    
    Price ($/GJ)
    
    Term45,000 GJ/d
    
    $
    6.30
    
    
    January 2004  March 200435,000 GJ/d
    
    $
    5.56
    
    
    April 2004  October 20047,500 GJ/d
    
    $
    5.00 to 7.10
    
    
    April 2004  December 200415,000 GJ/d
    
    $
    6.42
    
    
    November 2004  March 2005
  (1)
    
    Volumes at AECO Royalties Alberta Gas Crown Royalties are a cash royalty calculated on the Crowns share
of production using the Alberta Gas Reference Price. Credits are applied to
account for the Crowns share of allowable capital costs, operating costs and
processing fees. Royalty expense increased 75 percent to $38.2 million in 2003 from $21.9
million in the previous year. This percentage increase exceeded the 63 percent
increase in revenue as royalties in Alberta are calculated on a sliding scale
which increases the overall royalty rate as natural gas prices increase as
they did in 2003. Royalties ($ thousands except where noted)
    
    2003
    
    2002
    
    2001Natural gas royalties
    
    
    38,209
    
    
    
    21,886
    
    
    
    45,761Per Unit ($/Mcf)
    
    
    1.22
    
    
    
    0.63
    
    
    
    1.22Percentage of sales (%)
    
    
    19.0
    
    
    
    17.7
    
    
    
    20.0
 Royalty expense in the fourth quarter decreased to $7.3 million from $7.8
million in the third quarter due to the decrease in revenue and deferred
royalties of $0.60/Mcf of foregone production resulting from Interim Shut-in
Order 03-001 on September 1, 2003. This equated to a royalty deferral of $0.5
million in the fourth quarter of 2003. 19




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##### 



Paramount Energy Trust Operating Costs Operating costs decreased by eight percent to $27.7 million ($0.89 per Mcf) in
2003 from $30.3 million ($0.87 per Mcf) in 2002. On a unit of production basis
operating costs were relatively unchanged. In Northeast Alberta approximately
80 percent of production costs are fixed and 20 percent are variable with
production volumes. The decrease in total costs resulted from the decline in
average production levels in 2003, low operating costs for the Ells property
acquired in March 2003 as well as the increased focus by PET on cost control
in its field operations. Unit costs were held constant despite an overall
industry trend towards increasing operating costs resulting from competitive
conditions and a shortage of oilfield services. Operating Costs ($ thousands except where noted)
    
    2003
    
    2002
    
    2001Operating costs
    
    
    27,727
    
    
    
    30,265
    
    
    
    32,870Per Mcf ($)
    
    
    0.89
    
    
    
    0.87
    
    
    
    0.88
 Operating Costs ($/Mcf) (BAR CHART) Operating costs in the fourth quarter were unchanged at $6.7 million compared
to the third quarter. Unit operating costs increased to $0.98 per Mcf in the
fourth quarter from $0.82 in the third quarter due to lower production and the
commencement of winter activity. Operating Netbacks PETs 2003 operating netback of $4.33 per Mcf represented a 109 percent
increase from $2.07 in 2002 and reflected an 80 percent increase in realized
natural gas prices, partly offset by a 94 percent increase in royalties per Mcf
and a two percent increase in operating costs on a unit of production basis. Netback $/Mcf
    
    2003
    
    2002
    
    2001Gas price
    
    
    6.44
    
    
    
    3.57
    
    
    
    6.09Royalties
    
    
    (1.22
    )
    
    
    (0.63
    )
    
    
    (1.22
    )Operating costs
    
    
    (0.89
    )
    
    
    (0.87
    )
    
    
    (0.88
    )Netback
    
    
    4.33
    
    
    
    2.07
    
    
    
    3.99
 Lower gas prices and higher unit operating costs resulted in the netback
decreasing to $3.66 in the fourth quarter from $3.97 in the third quarter of
2003. General and Administrative Expense General and administrative expenses, net of overhead recoveries on operated
properties, increased to $4.7 million ($0.15 per Mcf) in 2003 from $4.0 million
($0.12 per Mcf) in 2002. While routine expenditures were held constant, the
2003 total included $0.7 million in legal and consulting expenditures directly
related to the AEUB gas over bitumen issue. General and administrative expenses net of gas over bitumen costs were $4.0
million ($0.13 per Mcf). General and Administrative Expense 2003
    
    
    
    
    
    2002
    
    
    
    
    
    2001$ 000s
    
    $/Mcf
    
    $ 000s
    
    $ /Mcf
    
    $ 000s
    
    $ /McfGeneral &
administrative
    
    
    3,980
    
    
    
    0.13
    
    
    
    3,987
    
    
    
    0.12
    
    
    
    4,498
    
    
    
    0.12Gas over bitumen
costs
    
    
    696
    
    
    
    0.02
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total general &
administrative
    
    
    4,676
    
    
    
    0.15
    
    
    
    3,987
    
    
    
    0.12
    
    
    
    4,498
    
    
    
    0.12
 General and administrative expenses were $1.4 million in the fourth quarter
compared to $1.1 million in the third quarter. Operating Netback ($/Mcf) (BAR CHART) 20




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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS 2003 Revenue Distribution (%) (PIE CHART) Interest Expense PET commenced bank borrowing in March 2003 with the acquisition of assets from
PRL. Interest on bank borrowings was generally paid at Bankers Acceptance
rates plus a stamping fee of 150 basis points. Interest Expense ($ thousands except where noted)
    
    2003
    
    2002
    
    2001Interest expense
    
    
    2,440
    
    
    
    50
    
    
    
    Per Mcf ($)
    
    
    0.08
    
    
    
    
    
    
    
    
 Interest expense in the fourth quarter of 2003 was $0.3 million compared to
$0.6 million in the third quarter. Depletion, Depreciation and Accretion The 2003 depletion, depreciation and accretion (D D & A) rate increased to
$2.01 per Mcf from $1.49 per Mcf in 2002, primarily due to the decrease in the
Trusts proved reserves at December 31, 2003 as well as the Epact acquisition.
The D D & A rate includes depletion of $2.3 million ($2.3 million in 2002) on
the capitalized cost associated with the asset retirement obligation as well as
accretion expense on the asset retirement obligation of $1.2 million in 2003
($1.2 million in 2002). The retroactive application of the new accounting
policy for asset retirement obligations required restatement of prior periods. Depletion, Depreciation and Accretion ($ thousands except where noted)
    
    2003
    
    2002
    
    2001Depletion expense
    
    
    61,436
    
    
    
    50,383
    
    
    
    38,119Accretion of asset retirement
obligation
    
    
    1,239
    
    
    
    1,163
    
    
    
    1,095Total
    
    
    62,675
    
    
    
    51,546
    
    
    
    39,214Per Mcf ($)
    
    
    2.01
    
    
    
    1.49
    
    
    
    1.05
 Depletion expense was $17.6 million in
the fourth quarter compared to $16.7
million in the third quarter. Income Taxes For income tax purposes PET is able to and intends to claim deduction for all
amounts paid or payable to the Unitholder then allocate remaining taxable
income, if any, to the Unitholders. Accordingly, no current or future income
taxes have been recorded in 2003. In 2002 an amount of current tax expense was
recorded which represented an allocation of the current taxes of PRL to its
Northeast Alberta operations. Capital Expenditures Exclusive of the series of transactions including the acquisitions of
properties from PRL which created the Trust, PET expended $8.3 million on
exploration and development activities in its core areas. In addition the Ells
property was acquired for $18.4 million in March and Epact Exploration Ltd.
was acquired in November for $13.3 million as well as other minor
acquisitions. Capital Expenditures ($ thousands except where noted)
    
    2003
    
    2002
    
    % ChangeExploration & development expenditures
    
    
    8,327
    
    
    
    11,468
    
    
    
    (27
    )Acquisitions
    
    
    32,252
    
    
    
    
    
    
    
    Properties acquired from PRL
    
    
    269,162
    
    
    
    
    
    
    
    Other
    
    
    757
    
    
    
    2,828
    
    
    
    (73
    )Total
    
    
    310,498
    
    
    
    14,296
    
    
    
    
 The Board of Directors of the Administrator of PET has approved a capital
budget for exploration and development expenditures of up to $20 million for
2004. Net Capital Expenditures ($MM) (BAR CHART) 21




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##### 



Paramount Energy Trust Cost Recovery Test PET performs cost recovery tests annually or as economic events dictate. An
impairment loss is recognized when the carrying amount of a property or
project is greater than the sum of the expected future cash flows
(undiscounted and without interest charges) from that property or project. The
amount of the impairment loss is calculated as the difference between the
carrying amount and the present value of estimated future cash flows. Although the sum of the expected future cash flows for the total of all of
PETs assets greatly exceeds the carrying amount, cost recovery tests carried
out at a property level did identify some impairment at December 31, 2003.
Application of this test at December 31, 2003 resulted in a reduction of the
carrying value of PETs property, plant and equipment of $9.8 million. This
amount arose in connection with an increase in capital assets related to the
asset retirement obligation, revisions to PETs reserves and adjustments to
estimates of future cash flows related to the gas over bitumen issue. No
future compensation with respect to the gas over bitumen issue for any shut-in
production beyond the current interim financial assistance of $0.60 per Mcf on
current or future foregone production was included in this determination. To
the extent that circumstances including volumes of gas shut-in or finalization
of compensation arrangements change, further adjustments to the carrying
amount of PETs property, plant and equipment may be required. Such
adjustments relate to prescribed determinations under the successful efforts
method of accounting and should not be taken to represent indications of the
fair market value of PETs assets or the possible impairment of such value. Capitalization and Financial Resources PET commenced bank borrowing in March 2003. At December 31, 2003, PET had bank
debt outstanding of $55.6 million and a working capital surplus of $1.4
million. Subsequent to December 31, 2003 the Trusts available credit
facilities were increased from $75 million to $100 million. PET has a revolving credit facility with a syndicate of Canadian Chartered
Banks. The facility consists of a demand loan of $90 million and a working
capital facility of $10 million. In addition to amounts outstanding under the
facility, PET has outstanding letters of credit in the amount of $1.7 million.
Collateral for the credit facility is provided by a floating-charge debenture
covering all existing and after acquired property of the Trust as well as
unconditional full liability guarantees from all subsidiaries in respect of
amounts borrowed under the facility. Advances under the facility are made in the form of Bankers Acceptances (BA),
prime rate loans or letters of credit. In the case of BA advances,
interest is a function of the BA rate plus a stamping fee based on the Trusts
current ratio of debt to cash flow. In the case of prime rate loans, interest
is charged at the lenders prime rate. December 31, 2003 net debt to total market capitalization was 9.4 percent and
net debt to 2003 cash flow was 0.4 years. Market capitalization ($ thousands except per Trust Unit and percent amounts)
    
    2003Bank and other debt
    
    
    55,564Working capital
    
    
    (1,375
    )Net debt
    
    
    54,189Trust Units outstanding (000s)
    
    
    44,638Market price at end of period
    
    
    11.68Market value of Trust Units
    
    
    521,376Total market
capitalization(1)
    
    
    575,565Net debt as a percent of total capitalization
    
    
    9.4
    %Cash flow
    
    
    126,360Net debt to cash flow ratio (times)
    
    
    0.4
 (1) Total market capitalization 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 market
capitalization is not intended to represent the total funds from equity and
debt received by the Trust. In February, 2004 PET closed the acquisition of producing natural gas
properties in the Marten Hills area of Northeast Alberta for $30.3 million.
The acquisition was financed from existing credit facilities. Total Market Capitalization (%) (PIE CHART) 22




---



##### 



MANAGEMENTS DISCUSSION AND ANALYSIS Unitholders Equity PETs total capitalization was $575.6 million at December 31, 2003 with the
market value of the Trust Units representing 91 percent of total
capitalization. During 2003, the market price of the Trust Units ranged from
$8.25 to $15.45 with an average daily trading volume of 236,000 Units. On December 31, 2003 there were 44.6 million Trust Units outstanding. All
Trust Units were issued during 2003 as follows:  
    
    On February 3, 2003 9.9 million Trust Units were issued to PRL. All these
Units were distributed by way of a dividend in-kind to the shareholders of
PRL.
    
    On March 11, 2003 PET issued 29.7 million Trust Units to Unitholders
pursuant to a Rights Offering.
    
    On May 30, 2003 PET closed an equity financing issuing 5 million Trust
Units at $12.65 per Unit for net proceeds of $60.1 million. Cash Distributions PET declared cash distributions of $123.2 million ($2.884 per Unit) in 2003
representing 97 percent of 2003 cash flow. Taxation of 2003 Cash Distributions Cash distributions are comprised of a return of capital portion (tax deferred)
and a return on capital portion (taxable). For cash distributions received or
receivable by a Canadian resident, outside of a registered pension or
retirement plan in the 2003 taxation year, the split between the two is 52
percent taxable and 48 percent tax deferred. PET, in consultation with its tax advisors, is of the view that the 2003
distributions pa id to non-corporate Unitholders who are U.S. residents are
Qualified Dividends for U.S. tax purposes. With respect to distributions
paid in 2003, 47.8 percent would be reported as qualified dividends and 52.2
percent would be reported as non-taxable return of capital for U.S. Persons.
PET performed an Earnings and Profits calculation for U.S. tax purposes in
order to make this determination. Holders or potential holders of Paramount
Energy Trust Units should consult their own legal and tax advisors as to their
particular tax consequences of holding Paramount Energy Trust Units. 2003 Distributions by Month($  per Trust Unit) Tax DeferredAmountTaxable
    
    (Return ofPayment Date
    
    Amount
    
    Capital)
    
    TotalApril 15, 2003
    
    $
    0.432
    
    
    $
    0.398
    
    
    $
    0.830May 15, 2003
    
    
    0.144
    
    
    
    0.133
    
    
    
    0.277June 16, 2003
    
    
    0.144
    
    
    
    0.133
    
    
    
    0.277July 15, 2003
    
    
    0.130
    
    
    
    0.120
    
    
    
    0.250August 15, 2003
    
    
    0.130
    
    
    
    0.120
    
    
    
    0.250September 15, 2003
    
    
    0.104
    
    
    
    0.096
    
    
    
    0.200October 15, 2003
    
    
    0.104
    
    
    
    0.096
    
    
    
    0.200November 17, 2003
    
    
    0.104
    
    
    
    0.096
    
    
    
    0.200December 15, 2003
    
    
    0.104
    
    
    
    0.096
    
    
    
    0.200January 15, 2004
    
    
    0.104
    
    
    
    0.096
    
    
    
    0.200Total
    
    $
    1.500
    
    
    $
    1.384
    
    
    $
    2.884
    (1)Percent
    
    
    52.0
    %
    
    
    48.0
    %
    
    
    100.0
    %
  (1)
    
    Total is based upon cash distributions paid and payable during 2003 2004 Cash Distributions After a payout of $0.20 per Trust Unit for January 2004, monthly cash
distributions were set at $0.16 per Trust Unit for February 2004. It is
expected that this newly-established level of monthly distribution will be
sustainable for the foreseeable future assuming the current forward market for
natural gas prices, the shut-in of additional volumes of gas due to the gas
over bitumen issue as recommended by the AEUB SSG and that compensation for
such shut-in, other than the temporary financial assistance program presently
in place, is delayed beyond the date of shut-in. Distributions are subject to
review monthly based on PETs production and commodity price fluctuations.
Revisions, if any, to the forecast monthly distributions will be determined as
required in the context of prevailing and anticipated conditions at that time. 23




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##### 



Paramount Energy Trust Cash Flow Sensitivity for the Year 2004 Below is a table that shows sensitivities of PETs 2004 cash flow to
operational changes and changes in the business environment: Impact on Annual Cash Flow Change
    
    $ /Trust Unit
    
    %Business EnvironmentPrice per Mcf of natural gas
($Cdn - AECO)
    
    $0.50/GJ
    
    
    0.216
    
    
    
    10$U.S./$Cdn exchange rate
    
    $
    0.01
    
    
    
    0.037
    
    
    
    2Interest rate on debt
    
    
    1
    %
    
    
    0.021
    
    
    
    1OperationalGas production volume
    
    1 MMcf/d
    
    
    0.026
    
    
    
    1Operating costs per Mcf
    
    $0.10/Mcf
    
    
    0.060
    
    
    
    3Cash G&A expenses per Mcf
    
    $
    0.05
    
    
    
    0.030
    
    
    
    1
 These sensitivities assume operating costs of $0.95 per Mcf, general and
administrative expenses of $0.15 per Mcf, a U.S./Canadian exchange rate of
$0.75 and an interest rate on debt of 4.5 percent. Given the uncertainty surrounding the gas over bitumen issue and the range of
possible production volumes which may or may not be shut-in in the future, the
following table presents estimated 2004 monthly average cash flow per Unit at
various assumed average annual gas prices and production levels, and assuming
no compensation for any gas over bitumen shut-in production beyond the current
interim financial assistance of $0.60 per Mcf on current or future foregone
production. Incorporating the current forward market for natural gas, average
calendar 2004 AECO gas prices are currently estimated at approximately
$6.25/GJ. 2004 Estimated Monthly Cash Flow per Unit Average 2004 AECO Gas
Price ($/GJ)$
    5.00
    
    
    $
    5.50
    
    
    $
    6.00
    
    
    $
    6.50
    
    
    $
    7.00
  Production
    
    Average 2004 Cash Flow(MMcf/d)
    
    $/Unit/Month85
    
    
    0.171
    
    
    
    0.186
    
    
    
    0.204
    
    
    
    0.222
    
    
    
    0.24180
    
    
    0.162
    
    
    
    0.176
    
    
    
    0.193
    
    
    
    0.209
    
    
    
    0.22675
    
    
    0.154
    
    
    
    0.166
    
    
    
    0.181
    
    
    
    0.197
    
    
    
    0.21270
    
    
    0.146
    
    
    
    0.157
    
    
    
    0.170
    
    
    
    0.184
    
    
    
    0.198
 Summary of Quarterly Results The following table presents PETs results by quarter for the last two fiscal
years. Summary of Quarterly Results ($ millions, except for per Unit amounts) 2003
    
    2002Q4
    
    Q3
    
    Q2
    
    Q1
    
    Q4
    
    Q3
    
    Q2
    
    Q1Natural gas revenue
    
    
    41.0
    
    
    
    46.8
    
    
    
    51.3
    
    
    
    62.1
    
    
    
    40.6
    
    
    
    28.0
    
    
    
    33.4
    
    
    
    21.8Net earnings (loss)
    
    
    (2.8
    )
    
    
    12.3
    
    
    
    17.0
    
    
    
    26.0
    
    
    
    7.5
    
    
    
    1.0
    
    
    
    3.9
    
    
    
    (5.0
    )Per Unit Basic
    
    
    (0.06
    )
    
    
    0.28
    
    
    
    0.41
    
    
    
    0.66
    
    
    
    0.19
    
    
    
    0.02
    
    
    
    0.10
    
    
    
    (0.13
    )Per Unit Diluted
    
    
    (0.06
    )
    
    
    0.28
    
    
    
    0.41
    
    
    
    0.64
    
    
    
    0.19
    
    
    
    0.02
    
    
    
    0.10
    
    
    
    (0.13
    )
 Critical Accounting Estimates Successful Efforts Accounting PET follows the successful efforts method of accounting. Under this method, PET
capitalizes only those costs that result directly in the discovery of petroleum
and natural gas reserves. Exploration expenses including geological and
geophysical costs, lease rentals and exploratory dry hole costs are charged to
earnings as incurred. Leasehold acquisition costs including costs of drilling
and equipping successful wells are capitalized. The net cost of unproductive
wells, abandoned wells and surrendered leases are charged to earnings in the
year of abandonment or surrender. Gains or losses are recognized on the
disposition of properties and equipment. Cost Recovery Test The net amount at which petroleum and natural gas costs on a property or
project are carried is subject to a cost recovery test annually or as economic
events dictate. An impairment loss is recognized when the carrying amount of
the asset is greater than the sum of the expected future cash flows
(undiscounted and without interest charges). The amount of the impairment loss
is calculated as the difference between the carrying amount and the discounted
present value of estimated future cash flows. The carrying values of capital
assets including the costs of acquiring proved and probable reserves are
subject to uncertainty associated with the quantity of oil and gas reserves,
future production rates, commodity prices and other factors. 24




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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS Financial Reporting and Regulatory Update There have been several changes in the financial reporting and securities
regulatory environment in 2003 that have impacted the Trust and all public
entities. Canadian securities regulators and the Canadian Institute of
Chartered Accountants (CICA) are undertaking these measures to increase
investor confidence through increased transparency, consistency and
comparability of financial statements and financial information. As well, the
changes have been brought about by a goal of aligning Canadian standards more
closely with those in the United States. The following new and amended standards were implemented by the Trust in 2003
and their impact is reflected in the 2003 financial statements.  Asset Retirement Obligations The CICA issued Section 3110 which harmonizes
Canadian GAAP with SFAS No. 143 Accounting for Asset Retirement Obligations.
The new Canadian standard is effective for fiscal years beginning on or after
January 1, 2004. However, earlier adoption is encouraged. PET implemented this
standard in 2003 in accordance with the early adoption provisions of the
standard. As a result of implementation, the liability for future abandonment
costs (the Asset Retirement Obligation or ARO) increased to $21.7 million
and the carrying amount of property, plant and equipment increased by $7.4
million. Net earnings for 2003 of $53.3 million decreased by $0.9 million
compared to net earnings which would have been reported under the old
standard. The transitional provisions of this section require that the
standard be applied retroactively with restatement of comparative periods. As
a result of the retroactive application, 2002 comparative numbers have been
restated to reflect the impact of the standard on the 2002 financial
statements. Net earnings for 2002 of $9.0 million decreased by $1.6 million,
the ARO increased to $20.0 million, the carrying amount of property, plant and
equipment increased by $9.3 million and opening 2002 accumulated earnings
decreased by $2.0 million. Opening 2003 accumulated earnings decreased by $3.6
million for the cumulative impact of retroactive restatement of all prior
years.Disclosure of Guarantees In February 2003, the CICA issued Accounting
Guideline 14 Disclosure of Guarantees which requires that all guarantees be
disclosed in the notes to the financial statements along with a description
of the nature and term of the guarantee and an estimate of the fair value of
the guarantee. The new guideline is effective for fiscal years beginning on
or after January 1, 2003. Implementation of the new guideline did not impact
PETs financial results for 2003. The following new and amended standards are expected to impact the Trust in
2004 as follows:  Stock Based Compensation and Other Stock Based Payments
In September 2003, the CICA issued an amendment to section 3870 Stock based
compensation and other stock based payments. The amended section is
effective for fiscal years beginning on or after January 1, 2004.Hedging Relationships In December 2001, the CICA issued Accounting
Guideline 13 Hedging Relationships that deals with the identification,
designation, documentation and measurement of effectiveness of hedging
relationships for the purposes of applying hedge accounting. Accounting
Guideline 13 is intended to harmonize Canadian GAAP with SFAS No. 133
Accounting for Derivatives Instruments and Hedging Activities. The
guideline is effective for fiscal years beginning on or after July 1, 2003.Continuous Disclosure Obligations Effective March 31, 2004, the Trust and
all reporting issuers in Canada will be subject to new disclosure
requirements as per National Instrument 51-102 Continuous Disclosure
Obligations. This new instrument is effective for fiscal years beginning on
or after January 1, 2004. The instrument proposes shorter reporting periods
for filing of annual and interim financial statements, MD&A and the Annual
Information Form (AIF). The instrument also proposes enhanced disclosure in
the annual and interim financial statements, MD&A and AIF. Under this new
instrument, it will no longer be mandatory for the Trust to mail annual and
interim financial statements and MD&A to Unitholders, but rather these
documents will be provided on an as requested basis. It is PETs intention
to make these documents available on the Trusts website on a continuous
basis. Impact on Net Earnings of Change in Accounting Policies The implementation of a new accounting policy relating to asset retirement
obligations has resulted in restatement of previously reported annual and
quarterly net earnings. The restatement was required per the transitional
provisions of the accounting standard. The following table illustrates the impact of the new accounting policy on
annual net income for the years and quarters which have been presented for
comparative purposes: 25




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##### 



Paramount Energy Trust 2003($ thousands)
    
    Q4
    
    Q3
    
    Q2
    
    Q1
    
    TotalNet earnings (loss) before changes in accounting
policies(1)
    
    
    (2,574
    )
    
    
    11,993
    
    
    
    17,502
    
    
    
    26,416
    
    
    
    53,337Increase (decrease) in net earnings: asset
retirement obligation(2)
    
    
    (238
    )
    
    
    323
    
    
    
    (518
    )
    
    
    (470
    )
    
    
    (903
    )Net earnings (loss) after change in accounting policies
    
    
    (2,812
    )
    
    
    12,316
    
    
    
    16,984
    
    
    
    25,946
    
    
    
    52,434
 2002($ thousands)
    
    Q4
    
    Q3
    
    Q2
    
    Q1
    
    TotalNet earnings (loss) before changes in accounting
policies(1)
    
    
    7,117
    
    
    
    1,737
    
    
    
    4,614
    
    
    
    (4,427
    )
    
    
    9,041Increase (decrease) in net earnings: asset
retirement obligation(2)
    
    
    380
    
    
    
    (723
    )
    
    
    (671
    )
    
    
    (621
    )
    
    
    (1,635
    )Net earnings (loss) after change in accounting policies
    
    
    7,497
    
    
    
    1,014
    
    
    
    3,943
    
    
    
    (5,048
    )
    
    
    7,406
  (1)
    
    This represents net earnings as reported before retroactive restatement
for changes in accounting policies.  (2)
    
    The new accounting policy for asset retirement obligations was
implemented in the fourth quarter of 2003. This new standard requires
retroactive application with restatement of all periods presented for
comparative purposes. Quantitative and Qualitative Disclosures About Market Risk PETs operations are affected by a number of underlying risks, both internal
and external to the Trust. These risks are similar to those affecting others
in both the conventional oil and gas royalty trust sector and the conventional
oil and gas producers sector. The Trusts financial position, results of
operations and cash available for distribution to Unitholders are directly
impacted by these factors. Cyclical and Seasonal Impact of Industry The Trusts operational results and financial condition will be dependent on
the prices received for natural gas production. Natural gas prices have
fluctuated widely during recent years and are determined by supply and demand
factors including weather and general economic conditions as well as conditions
in other oil and natural gas producing regions. Any decline in natural gas
prices could have an adverse effect on the Trusts financial condition. Renegotiation or Termination of Contracts As at the date hereof, the Trust does not anticipate that any aspect of its
business will be materially affected in the current fiscal year by the
renegotiation or termination of contracts or subcontracts. Competitive Conditions The Trust is a member of the petroleum and natural gas industry which is
highly competitive at all levels. The Trust competes with other companies and
other energy Trusts for all of its business inputs including exploitation
and development prospects, access to commodity markets, property and corporate
acquisitions, personnel and available capital. The Trust endeavours to be
competitive by maintaining a strong financial condition by attracting and
retaining technically competent and accountable staff, by refining and
enhancing business processes on an ongoing basis and by utilizing current
technologies to enhance exploitation, development and operational activities. Environmental Considerations The Trust is proactive in its approach to environmental concerns. Procedures
are in place to ensure that due care is taken in the day-to-day management of
its properties. All government regulations and procedures are followed in
adherence to the law. The Trust conducts well abandonment and site restoration
in a timely manner to ensure minimal damage to the environment and lower
overall costs to the Trust. Government Regulation Risk PET operates in a highly regulated industry and it is possible that changes in
such regulations or adverse regulatory decisions could affect the Trusts
production which could reduce distributions to Unitholders. Additional details
with respect to the gas over bitumen regulatory issue are described elsewhere
in this MD&A. 26




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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS Commodity Price, Foreign Exchange and Interest Rate Risk The two most important factors
affecting the level of cash
distributions available to Unitholders
are the level of production achieved by
PET, and the prices received for its
production. These prices are influenced
in varying degrees by factors outside
the Trusts control. Some of these
factors include:  
    
    economic conditions that
influence the demand for natural
gas and the level of interest
rates set by the Governments of
Canada and the U.S.;
    
    weather conditions that influence the demand for natural gas;
    
    transportation availability and costs; and
    
    price differentials among
markets based on transportation
costs to major markets. To mitigate these risks, PET has active
hedging and marketing programs in place
based on an established set of criteria
that has been approved by the Board of
Directors of the Administrator of the
Trust. The results of the hedging
program are reviewed against these
criteria and the results actively
monitored by the Board. Beyond our hedging strategy, PET also
mitigates risk by having a diversified
gas marketing portfolio, by transacting
with a number of counterparties and
limiting exposure to each counterparty. The contracts that PET has with
aggregators vary in length. They
represent a blend of domestic markets
with fixed and floating prices designed
to provide price diversification to our
revenue stream. 27