Document:

<PAGE>

                                                                  EXHIBIT 4.2

MANAGEMENT'S DISCUSSION AND ANALYSIS  ("MD & A")

PARAMOUNT IS PLEASED TO REPORT ITS FINANCIAL AND OPERATING RESULTS FOR THE YEAR
ENDED DECEMBER 31, 2002.

THE FOLLOWING DISCUSSION OF FINANCIAL POSITION AND RESULTS OF OPERATIONS SHOULD
BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
THERETO. IT OFFERS MANAGEMENT'S ANALYSIS OF PARAMOUNT'S HISTORICAL FINANCIAL AND
OPERATING RESULTS AND PROVIDES ESTIMATES OF PARAMOUNT'S FUTURE FINANCIAL AND
OPERATING PERFORMANCE BASED ON INFORMATION CURRENTLY AVAILABLE. ACTUAL RESULTS
WILL VARY FROM ESTIMATES AND THE VARIANCES MAY BE SIGNIFICANT.

Paramount Resources Ltd. ("Paramount" or the "Company") is an exploration,
development and production company with established operations in Alberta,
British Columbia, Saskatchewan, the Northwest Territories, Montana, North Dakota
and California. The Company has patiently executed its corporate growth
strategy, focusing on natural gas as a commodity, and high impact exploration as
the cornerstone to future success. Management's vision continues to be based on
the long-term fundamentals for oil and natural gas in North America. During
2002, Paramount continued to focus its efforts on building a strong asset base
through exploration and development, and the acquisition of Summit Resources
Limited ("Summit").

SIGNIFICANT EVENTS

     o    ACQUISITION OF SUMMIT RESOURCES LIMITED

          On June 28, 2002, Paramount closed the acquisition of Summit Resources
          Limited for cash consideration of $251.4 million and assumed net debt
          of $81.0 million. The acquisition diversified the Company's production
          base and consolidated certain working interests in Central Alberta
          which the Company believes are highly prospective.

     o    CREATION OF AN INDEPENDENT ENERGY TRUST

          In conjunction with Paramount's acquisition of Summit, the Company
          announced its intention to create an independent Energy Trust (the
          "Trust"), providing shareholders an investment which would complement
          Paramount's traditional exploration and development strategy.

          During the first quarter 2003, all necessary regulatory clearances
          with respect to the Canadian prospectus and a US Registration
          Statement were received. Paramount subsequently transferred a portion
          of its Northeast Alberta assets to the Trust and issued a $51 million
          dividend in kind of Trust Units received from the Trust to its
          shareholders. On March 11, 2003, the Trust closed a rights offering,
          the proceeds of which partially capitalized the Trust and allowed it
          to purchase from Paramount additional assets in Northeast Alberta.

     o    SETTLEMENT OF BITUMEN/NATURAL GAS CO-PRODUCTION ISSUE

          On June 27, 2002, Paramount received compensation of $47.1 million in
          settlement for the Surmont shut-in order of May 1, 2000.

<PAGE>

                                       2

     o    SALE OF REMAINING INVESTMENT IN PEYTO EXPLORATION AND DEVELOPMENT
          CORP.

          Paramount monetized its remaining investment in Peyto Exploration and
          Development Corp. to realize cash proceeds of $45.0 million in 2002
          for a net gain of $40.1 million.

HIGHLIGHTS

     o    Cash flow totaled $259.9 million or $4.37 per share.

     o    Natural gas sales averaged 241 MMcf/d; crude oil and natural gas
          liquids production averaged 5,663 Bbl/d.

ACCOUNTING POLICY

Paramount follows the "successful efforts" method of accounting for its
petroleum and natural gas operations. This method, unlike the alternative "full
cost" accounting method, usually generates a more conservative value for net
earnings as exploration expenditures, including exploratory dry hole costs,
geological and geophysical costs, lease rentals on undeveloped properties as
well as the cost of surrendered leases and abandoned wells are expensed rather
than capitalized in the year incurred. However, to make reported cash flow
results comparable to industry practice, Paramount reclassifies geological and
geophysical costs as well as surrendered leases and abandonment costs from
operating to investing activities.

REVENUE

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
PRODUCTION REVENUE (thousands of dollars)               2002             2001           2000
-------------------------------------------------------------------------------------------------
<S>                                             <C>              <C>             <C>
Natural gas                                     $    311,438     $    481,436    $   375,746
Crude oil and natural gas liquids                     72,750           28,442         21,676
Commodity hedging  gain (loss)                        46,813           15,808         (5,952)
Gain on sale of short-term investments                40,830            2,982             -
Other                                                  2,111             (295)            -
-------------------------------------------------------------------------------------------------
Gross revenue                                   $    473,942     $    528,373    $   391,470
-------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------
</TABLE>

Paramount's financial success is contingent upon the growth of reserves and
production volumes and the economic environment that creates a demand for
natural gas and crude oil. Such growth is a function of the amount of cash flow
that can be generated and reinvested into a successful capital expenditure
program. To protect cash flow against commodity price volatility, the Company
will, from time to time, manage cash flow by utilizing commodity price hedges.
The hedging program is generally for periods of less than one year and
restricted to a maximum of 50 percent of Paramount's current production volumes.

<PAGE>

                                       3

Petroleum and natural gas revenue totaled $431.0 million in 2002, as compared to
$525.7 million in 2001 (2000 - $391.5 million). The decrease in revenue results
from lower commodity prices received during the year. Weaker natural gas demand
resulted in a decrease of 33% in Paramount's average natural gas sales price to
$4.08/Mcf as compared to $6.12/Mcf in 2001 (2000 - $4.59/Mcf). Included in
petroleum and natural gas sales are $46.8 million of commodity hedging gains
attributed primarily to natural gas hedges. On a per unit basis the 2002 price
includes approximately $0.55/Mcf profit from natural gas commodity hedges that
were in place during the year. Natural gas sales volumes averaged 241 MMcf/d in
2002 as compared to 225 MMcf/d in 2001 (2000 - 220 MMcf/d). The increase in
natural gas sales volumes is attributed to the acquisition of Summit effective
June 28, 2002, which added approximately 50 MMcf/d of natural gas production.

Oil and natural gas liquids prices averaged $34.64/Bbl, as compared to
$35.48/Bbl in 2001 (2000 - $37.80/Bbl). Oil and natural gas liquids production
increased 162 percent to average 5,663 Bbl/d in 2002 as compared to 2,165 Bbl/d
in 2001 (2000 - 1,571 Bbl/d). This increase is attributable to the acquisition
of Summit which at the time of acquisition produced approximately 5,000 Bbl/d of
oil and natural gas liquids.

Paramount's 2002 production profile continues to be significantly weighted to
natural gas but the Company has increased its oil and natural gas liquids
production with the Summit acquisition. In 2002 natural gas revenue contributed
83 percent of Paramount's total petroleum and natural gas revenue compared to 95
percent in 2001.

Fourth quarter petroleum and natural gas revenue totaled $135.5 million as
compared to $87.7 million for the comparable quarter in 2001. The increase in
sales resulted from an increase in production volumes associated with the
acquisition of Summit, as well as an increase in natural gas prices, which
averaged $4.60/Mcf during the quarter as compared to $4.17/Mcf for the
comparable quarter in 2001. Natural gas sales averaged 263 MMcf/d for the fourth
quarter of 2002 compared to 218 MMcf/d for the comparable quarter in 2001. Oil
and natural gas liquids sales averaged 8,552 Bbl/d in the fourth quarter of 2002
as compared to 2,002 Bbl/d for the comparable quarter in 2001.

<PAGE>

                                       4

At December 31, 2002, Paramount had the following natural gas commodity price
hedges in place representing approximately 40 percent of Paramount's average
2002 production:

VOLUME
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------
AECO                         PRICE                         TERM
-----------------------------------------------------------------------------
<S>                         <C>                 <C>
10,000 GJ/d                   $5.46             November 2002 - October 2003
20,000 GJ/d                   $5.06             November 2002 - October 2003
20,000 GJ/d                   $5.25             November 2002 - October 2003

NYMEX
-----------------------------------------------------------------------------
20 MMcf/d                   US$3.83             November 2002 - October 2003
20 MMcf/d                   US$3.90             November 2002 - October 2003
10 MMcf/d                   US$4.10             November 2002 - October 2003

WTI
-----------------------------------------------------------------------------
1,000 Bbl/d                US$24.07                    May 2002 - April 2004
1,000 Bbl/d                US$24.33             January 2003 - December 2003
-----------------------------------------------------------------------------
</TABLE>

The unrealized loss on these financial hedges at December 31, 2002 totaled $28.7
million.

The Company also has in place foreign exchange hedges, which have fixed the
exchange rate on US $40.9 million for CDN $58.6 million over the next three
years at CDN $1.4322. For the year ended December 31, 2002, gross revenue
included losses from foreign currency hedging activity of $3.4 million (2001 -
$1.7 million).

During 2002, approximately 43 percent of Paramount's natural gas sales were
under long-term contracts to gas aggregators and direct-sales purchasers as
compared to 42 percent and 46 percent for 2001 and 2000, respectively.

<PAGE>

                                       5

<TABLE>
<CAPTION>
NATURAL GAS SALES PER MARKET GROUP                                            2002         2001         2000
------------------------------------ ------------------------------------ ------------ ------------ -------------
LONG-TERM CONTRACTS                                                        BCF      %   Bcf      %   Bcf       %
------------------------------------ ------------------------------------ ------------ ------------ -------------
<S>                                                                       <C>    <C>   <C>    <C>    <C>   <C>
Mirant                               Midwestern US, Pacific Northwest     14.7    16.6  17.4   21.2  19.6    24.3
                                     US, California and Quebec
Progas                               Northeastern US                       9.6    10.9   8.1    9.9   7.2     8.9
Canstates/Temco                      Northeastern US                       1.5     1.7   1.9    2.2   3.2     4.0
TransCanada                          Eastern Canada                        0.4     0.5   2.7    3.3   1.2     1.5
------------------------------------ ------------------------------------ ------------ ------------ -------------
Subtotal - aggregators                                                    26.2    29.7  30.1   36.6  31.2    38.7
------------------------------------ ------------------------------------ ------------ ------------ -------------
Direct sales
Nexen                                Midwestern US                         2.9     3.3     -      -     -       -
Selkirk                              Northeastern US                       6.0     6.8   4.5    5.5   6.0     7.4
West Windsor                         Eastern Canada                        0.6     0.7     -      -     -       -
BC Gas                               British Columbia                      0.6     0.7     -      -     -       -
Duke                                 AECO                                  1.4     1.6     -      -     -       -

------------------------------------ ------------------------------------ ------------ ------------ -------------
Subtotal - direct sales                                                   11.5    13.1   4.5    5.5   6.0     7.4
------------------------------------ ------------------------------------ ------------ ------------ -------------
Subtotal - Long-term Contacts                                             37.7    42.8  34.6   42.1  37.2    46.1
------------------------------------ ------------------------------------ ------------ ------------ -------------
Short-term markets
Spot                                 Chicago                               3.2     3.6     -      -     -       -
Spot                                 Eastern Canada                        2.7     3.1     -      -     -       -
Spot                                 California                           13.8    15.7  14.6   17.8  14.6    18.1
Spot                                 Alberta/Waddington                   30.7    34.8  32.9   40.1  28.7    35.8
------------------------------------ ------------------------------------ ------------ ------------ -------------
Total(1)                                                                  88.1   100.0  82.1  100.0  80.5   100.0
------------------------------------ ------------------------------------ ------------ ------------ -------------
</TABLE>

(1)  Natural gas sales for 2000 reflect a 366-day year

For 2003, revenues will be impacted by drilling success and production volumes
as well as external factors such as the market for natural gas, the exchange
rate of the Canadian dollar relative to the US dollar and the West Texas
Intermediate ("W.T.I") price for crude oil. Additionally, the disposition of
producing natural gas assets in Northeast Alberta to the Trust will reduce
production volumes and corresponding reserves. Natural gas production in this
area averaged approximately 97 MMcf/d during 2002, exiting the year at 90
MMcf/d. A minor asset disposition package is also currently being marketed, with
bids expected to close early in 2003.

The Company anticipates a continued positive trend in commodity prices for 2003
relative to the prices received in 2002.

GAIN ON SALE OF SHORT-TERM INVESTMENTS

During the year Paramount disposed of 8.7 million shares of Peyto Exploration
and Development Corp. at an average price of $5.17 per share for net proceeds of
$45.0 million resulting in a gain of $40.1 million. In 2002, Paramount also
disposed of 1.25 million shares of Triquest Energy Corp. at an average price of
$2.98 per share for net proceeds of $3.7 million resulting in a gain of $0.7
million. Paramount routinely utilizes a portion of its working capital to make
short-term investments in private and publicly traded oil and gas companies.
Accordingly, related gains and losses are included in cash flow from operations.

<PAGE>

                                       6

BITUMEN/NATURAL GAS CO-PRODUCTION

On February 28, 2002, Paramount entered into a Memorandum of Agreement with the
Province of Alberta and Conoco Canada Resources Ltd. ("Conoco"), effective May
1, 2000. The Memorandum of Agreement provided, inter alia, for compensation of
$85 million to be paid to the Surmont Gas Producers by the Alberta Crown in the
form of reduced royalties as well as the granting to the Province of Alberta by
the Surmont Gas Producers of an 11 percent gross overriding royalty encompassing
certain wells, lands and leases affected by the shut-in order of May 1, 2000.
Compensation of $47.1 million was received in June 2002. This amount has been
recorded in the Consolidated Statement of Earnings, net of the net book value of
wells, lands and leases in the affected area of $9.1 million.

ROYALTIES

Royalties are paid by Paramount to the owners of mineral rights with whom the
Company holds leases. Paramount has mineral leases with the Crown (Provincial
and Federal Governments), freeholders and other operators with whom the Company
has joint interests.

<TABLE>
<CAPTION>
------------------------------------------- ---------------- ----------------- ----------------
ROYALTIES (thousands of dollars)                      2002             2001              2000
------------------------------------------- ---------------- ----------------- ----------------
<S>                                         <C>              <C>               <C>
Crown royalties                                   $ 71,535         $ 94,253          $ 76,470
Other royalties                                      3,658            5,953             4,587
------------------------------------------- ---------------- ----------------- ----------------
                                                    75,193          100,206            81,057
Alberta Royalty Tax Credit                            (749)            (500)             (516)
------------------------------------------- ---------------- ----------------- ----------------
Total royalties                                   $ 74,444         $ 99,706          $ 80,541
------------------------------------------- ---------------- ----------------- ----------------
------------------------------------------- ---------------- ----------------- ----------------
Average corporate royalty rate                        17.2%           18.9%             20.6%
------------------------------------------- ---------------- ----------------- ----------------
------------------------------------------- ---------------- ----------------- ----------------
</TABLE>

Alberta gas Crown royalties are a cash royalty calculated on the Crown's share
of production using the Alberta Reference Price. The Alberta Reference Price is
the monthly weighted average price for gas consumed in Alberta and gas exported
from Alberta reduced for allowances for transportation and marketing. A
subsequent cost-of-service credit is applied to account for the Crown's share of
allowable capital and processing fees to arrive at the net royalty.

For 2002, royalties net of the Alberta Royalty Tax Credit ("ARTC") decreased to
$74.4 million from $99.7 million in 2001 (2000 - $80.5 million) due to lower
natural gas commodity prices. As a percentage of production revenue, Paramount's
corporate royalty rate decreased to 17.2 percent as compared to 18.9 percent in
2001 (2000 - 20.6 percent). Fourth-quarter royalties reflected the increase in
production volumes and commodity prices compared to the prior year's quarter,
and increased to $28.2 million as compared to $12.4 million during the fourth
quarter 2001.

<PAGE>

                                       7

For 2003, Paramount's average corporate royalty rate is expected to increase,
giving effect to a corporate average natural gas price which will be less than
the Alberta Reference Price on which royalties are calculated. This results from
expected losses on the Company's hedging program which are netted from revenues
in deriving at petroleum and natural gas sales. As in 2002, there will continue
to be minimal royalties paid to the Federal Government for production from
projects in the Northwest Territories. Royalties for these projects are subject
to payout accounts.

OPERATING EXPENSES

<TABLE>
<CAPTION>
------------------------------------------------ ---------------- ----------------- ----------------
OPERATING EXPENSES (thousands of dollars)                   2002              2001             2000
------------------------------------------------ ---------------- ----------------- ----------------
<S>                                              <C>               <C>              <C>
Operating expenses                                       $86,067           $61,045          $47,974
------------------------------------------------ ---------------- ----------------- ----------------
------------------------------------------------ ---------------- ----------------- ----------------
Net operating expenses per Mcfeq                           $0.79             $0.68            $0.56
------------------------------------------------ ---------------- ----------------- ----------------
------------------------------------------------ ---------------- ----------------- ----------------
</TABLE>

Paramount's 2002 operating expenses increased 41 percent to $86.1 million from
$61.0 million in 2001 (2000 - $48.0 million). On a unit-of-production basis,
average operating costs increased to $0.79/Mcfeq from $0.68/Mcfeq in 2001 (2000
- $0.56/Mcfeq). Fourth-quarter operating costs increased to $23.5 million as
compared to $17.5 million a year earlier, primarily due to the increased well
base in the current quarter associated with the Summit acquisition.

Paramount constructs and operates plant facilities and gathering systems as a
corporate strategy in order to control the flow of gas to market. These
facilities incur fixed costs, which are in addition to the costs incurred at the
well level, thereby increasing total operating expenses and the relative
magnitude of the per unit costs. As production declines in the Company's
traditional shallow gas areas, per-unit operating costs have increased. In new
core areas facilities are constructed in anticipation of maximizing throughput,
which in many cases has not yet been achieved. As optimization occurs and
production volumes increase, per-unit costs should decrease to levels
historically experienced by the Company. Operating costs associated with the
Northeast Alberta assets totaled $32.3 million in 2002 or $0.91/Mcf.

For 2003, the Company expects operating costs on a per-unit-basis to decline
marginally in recognition of the disposal of higher cost assets in Northeast
Alberta.

GENERAL AND ADMINISTRATIVE EXPENSES
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
GENERAL AND ADMINISTRATIVE EXPENSES (thousands of dollars)                 2002           2001           2000
--------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>            <C>            <C>
Gross general and administrative expenses                              $    30,868    $    26,374    $    18,982
Operating recoveries                                                       (15,238)       (15,766)       (11,369)
--------------------------------------------------------------------------------------------------------------------
General and administrative expenses before SARP                             15,630         10,608          7,613
Share Appreciation Rights Plan ("SARP")                                        582          1,738          2,047
--------------------------------------------------------------------------------------------------------------------
Net general and administrative expenses                                $    16,212    $    12,346    $     9,660
--------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------
Net general and administrative expenses per Mcfeq                      $      0.15    $      0.14    $      0.11
--------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                                       8

General and administrative expenses, net of operating recoveries and before
costs associated with the Share Appreciation Rights Plan ("SARP"), increased to
$15.6 million in 2002 as compared to $10.6 million in 2001 (2000 - $7.6
million). The increase is a result of additional salaries incurred in respect of
the Summit office and field personnel, as well as additional administrative
expenditures incurred to set up and staff the Trust. During the year, the
Company increased head office staff by more than 40 percent and field staff by
60 percent in order to manage the Company's increasing asset base and to
adequately staff the Trust. Cost increases associated with additional staffing
levels include salary, benefits and rent. Paramount does not capitalize any
general and administrative expenses.

Certain costs associated with setting up the Trust including legal and
professional fees and advisory fees have been deferred and will be included as a
cost associated with the disposition of the Northeast Alberta assets.

At the Annual General Meeting of the shareholders held June 14, 2001, a
resolution was approved to introduce an employee stock option plan as a
substitute for the SARP. Share appreciation rights previously held by employees
have been grandfathered until their expiry and are capped at a price of $14.50,
that being the grant price of an equal number of stock options. Under the SARP,
participants are entitled to receive a benefit of an amount equal to the
positive difference between the exercise price and $14.50, which difference is
charged to general and administrative expenses. At December 31, 2002, 238,000
SARP's remained outstanding. Employees exercising options have the choice of
receiving cash from the Company for the positive difference between the exercise
price and market price of the Company shares or receiving Company shares. Cash
consideration paid is charged to general and administrative costs as incurred.
During 2002, 177,000 options were exercised for consideration of $0.6 million as
compared to $1.7 million in 2001 (2000 - $2.0 million).

General and administrative expenses are expected to decline in 2003 as the
Trust's operations will be excluded from Paramount's activities.

INTEREST EXPENSE

<TABLE>
<CAPTION>
------------------------------------------- ---------------- ----------------- ----------------
INTEREST EXPENSE (thousand of dollars)                 2002              2001             2000
------------------------------------------- ---------------- ----------------- ----------------
<S>                                         <C>              <C>               <C>
Interest expense                                   $ 23,943          $ 19,291         $ 22,313
Total Debt, December 31                            $539,270          $316,600         $315,000
Debt to cash flow                                      2.07              1.04             1.41
------------------------------------------- ---------------- ----------------- ----------------
</TABLE>

Interest expense, representing interest on bank debt, increased to $23.9 million
from $19.3 million in 2001 (2000 - $22.3 million). The increase reflects
significantly higher average debt levels during 2002 necessary to fund the
Summit acquisition and the higher interest rates charged on the facility.

To finance the acquisition of Summit, the Company negotiated a $600 million
credit facility with a syndicate of Canadian Chartered banks, including a $466
million production facility, a $109 million bridge facility and a $25 million
working capital facility.

<PAGE>

                                       9

The term of the credit facility was initially structured to coincide with the
closing of the transfer by Paramount to the newly formed Trust of a portion of
its Northeast Alberta assets. As the Trust Rights Offering did not close until
March 11, 2003, Paramount requested a formal extension of the existing facility.
Upon closing of the Trust transaction the proceeds received by Paramount from
the sale of the assets to the Trust have been used to permanently reduce bank
indebtedness. On March 11, 2003, the term of the facility was extended to April
30, 2003, the bridge facility was paid down in its entirety and the credit
facility reduced to $315.5 million.

The Company had a note payable in the amount of $33 million to Paramount Oil and
Gas Ltd. The note was paid in full on March 7, 2003.

DRY HOLE COSTS

Under the successful efforts method of accounting, costs of drilling exploratory
wells are initially capitalized and, if subsequently determined to be
unsuccessful, are charged to dry hole expense. All other exploration costs,
including geological and geophysical costs and annual lease rentals, are charged
to exploration expense as incurred. For 2002, dry hole costs amounted to $120.1
million as compared to $8.9 million in 2001 and $7.0 million in 2000. The
provision includes $4.7 million of costs associated with wells drilled in the
current year, $7.5 million of expired mineral leases, $41.9 million associated
with exploratory wells drilled in Canada in previous years, which the Company
has determined will not be capable of production in economic quantities, and
$66.0 million related to certain exploratory projects in the United States which
the Company has determined to be unsuccessful.

Geological and geophysical expenses decreased during 2002 to $9.3 million (2001
- $10.6 million; 2000 - $6.8 million).

DEPLETION, DEPRECIATION AND AMORTIZATION

The current year provision for depletion and depreciation expense totaled $169.4
million as compared to $105.4 million in 2001 (2000 - $50.6 million). On a
unit-of-production basis, depletion and depreciation costs averaged $1.56/Mcfeq
as compared to $1.21/Mcfeq in 2001 (2000 - $0.59/Mcfeq). A larger depletable
base due to the 2002 capital expenditure program and acquisition of Summit
combined with reduced proved reserves increased the depletion factor during the
fourth quarter.

Under the successful efforts method of accounting, depletion and depreciation is
provided based on estimated proved recoverable reserves of each producing
property. Capital costs associated with undeveloped land of $218 million and
non-producing petroleum and natural gas properties of $149 million totaling $367
million are excluded from capital costs subject to depletion in 2002 (2001 -
$402 million).

For 2003, the provision for depletion and depreciation is expected to decrease
reflecting the disposition of assets in Northeast Alberta to the Trust and the
corresponding reduction in production volumes. Increases or decreases in the
depletion rate on a unit-of-production basis will be influenced by the reserves
added through the 2003 drilling program or by acquisition.

<PAGE>

                                       10

FUTURE SITE RESTORATION AND ABANDONMENT COSTS

On an annual basis the Company reviews the liability for future site restoration
and abandonment costs. For 2002 the provision totaled $3.4 million as compared
to $2.4 million in 2001 (2000 - $1.7 million). Current estimates for site
restoration of all the Company's properties total approximately $58 million,
excluding assets in Northeast Alberta which were sold to the Trust during the
first quarter of 2003. At December 31, 2002, $23.0 million is reflected as an
accumulated provision in the financial statements. This amount includes an
accumulated provision for future site restoration of $10.6 million included as
part of the acquisition of Summit Resources Limited.

WRITE-DOWN OF PETROLEUM AND NATURAL GAS PROPERTIES

The Company has recorded a provision of $31.3 million in 2002 (2001, 2000 - nil)
in respect of impairment in certain producing non-core oil and gas assets
located in Alberta and Southeast Saskatchewan.

INCOME TAXES

In 2002, Paramount recorded Large Corporations and other tax expense of $9.2
million as compared to $2.7 million in 2001 (2000 - $2.3 million). The Company
did not pay current income tax in 2002.

The future income tax benefit recorded in 2002 totaled $46.9 million as compared
to a $56.1 million provision in 2001 (2000 - $72.0 million provision). The
Company also recorded a $104.9 million future tax liability in respect of the
Summit acquisition, which represents the tax effect of the difference between
the value attributed to the Summit capital assets and the value of the related
tax pools.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
ESTIMATED INCOME TAX POOLS (millions of dollars)                  DECEMBER 31, 2002
------------------------------------------------------------------------------------
<S>                                                               <C>
Undepreciated capital costs (UCC)                                            $313.5
Canadian oil and gas property expenses (COGPE)                                302.2
Canadian exploration expenses (CEE)                                             9.4
Canadian development expenses (CDE)                                           148.1
Foreign exploration and development expenses (FEDE)                            22.4
Other                                                                           0.7
------------------------------------------------------------------------------------
Total estimated income tax pools                                             $796.3
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
</TABLE>

Paramount has available approximately $796 million of unutilized tax pools at
December 31, 2002. These tax pools will be available for deduction in 2003 in
accordance with Canadian income tax regulations at varying rates of
amortization.

<PAGE>

                                       11

The disposition of the Northeast Alberta assets to the Trust will result in a
reduction to COGPE and UCC.

CASH FLOW AND EARNINGS

<TABLE>
<CAPTION>
----------------------------------------------- ---------------- ----------------- ----------------
(thousands of dollars)                                     2002              2001             2000
----------------------------------------------- ---------------- ----------------- ----------------
<S>                                             <C>              <C>               <C>
Cash flow from operations                              $259,916          $303,937         $223,446
Net earnings                                           $ 10,307          $118,902         $ 86,062
Weighted average shareholders' equity                  $540,745          $477,705         $373,623
After-tax rate of return (%)                                1.9              24.9             23.0
----------------------------------------------- ---------------- ----------------- ----------------
</TABLE>

Paramount's cash flow from operations decreased 14 percent to $259.9 million or
$4.37 per basic common share ($4.36 per diluted common share) from $303.9
million or $5.11 per basic and diluted common share in 2001 (2000 - $223.4
million or $3.76 per basic and diluted common share). The decrease is due to
lower natural gas prices in 2002, offset somewhat by higher gas and liquids
production during the year, as a result of the Summit acquisition.
Fourth-quarter cash flow totaled $62.1 million, an increase of 30 percent from
$47.7 million during the same period in 2001 (2000 - $97.2 million). The
weighted average common shares outstanding totaled 59.5 million in 2002,
unchanged from 59.5 million in 2001 and 2000.

Earnings decreased to $10.3 million or $0.17 per basic common share ($0.16 per
diluted common share) compared to $118.9 million or $2.00 per basic and diluted
common share in 2001 (2000 - $86.1 million or $1.45 per basic and diluted common
share). The lower earnings in 2002 are a result of decreased cash flows, as well
as larger non-cash charges for depletion and depreciation, dry hole costs, and
the write-down of petroleum and natural gas properties. The impact of these
charges was partially offset by a significant future tax recovery.

Paramount's three-year average after-tax rate of return on a book basis, based
upon the weighted average shareholders' equity invested, was 17 percent.

NETBACKS
<TABLE>
<CAPTION>
----------------------------------------------- ---------------- ----------------- ----------------
NETBACKS ($/Mcfeq)                                         2002              2001             2000
----------------------------------------------- ---------------- ----------------- ----------------
<S>                                             <C>              <C>               <C>
Gross revenue                                             $3.98             $5.87            $4.54
Royalties (net of ARTC)                                    0.68              1.11             0.93
Operating costs                                            0.79              0.68             0.56
----------------------------------------------- ---------------- ----------------- ----------------
Operating netback                                          2.51              4.08             3.05
General and administrative                                 0.15              0.14             0.11
Lease rentals                                              0.04              0.05             0.06
Interest on long-term debt                                 0.22              0.21             0.26
Current and Large Corporations tax                         0.08              0.31             0.03
----------------------------------------------- ---------------- ----------------- ----------------
Cash netback                                              $2.02             $3.37            $2.59
----------------------------------------------- ---------------- ----------------- ----------------
----------------------------------------------- ---------------- ----------------- ----------------
</TABLE>

<PAGE>

                                       12

CAPITAL EXPENDITURES
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES (thousands of dollars)                              2002           2001           2000
-------------------------------------------------------------------------------------------------------------
<S>                                                              <C>             <C>            <C>
Land                                                             $      6,410    $    39,166    $    24,016
Geological and geophysical                                              9,303         10,646          6,784
Drilling                                                              124,076        127,736        108,811
Production equipment and facilities                                    77,407         94,775         92,690
-------------------------------------------------------------------------------------------------------------
Exploration and development expenditures                              217,196        272,323        232,301
-------------------------------------------------------------------------------------------------------------
Summit Resources Limited acquisition                                  449,648              -              -
Dry hole and geological and geophysical costs expensed               (129,361)       (19,590)       (13,803)

Petroleum and natural gas property impairment                         (42,183)             -              -
Property acquisitions                                                  28,610         19,048         61,550
Property dispositions                                                  (4,995)       (11,763)       (34,205)
Other                                                                   2,349          1,166          3,205
-------------------------------------------------------------------------------------------------------------
Net capital expenditures                                              521,264        261,184        249,048
Adoption of new accounting policy                                           -              -         14,900
-------------------------------------------------------------------------------------------------------------
Change in cost of petroleum and natural gas properties            $   521,264    $   261,184    $   263,948
-------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------
</TABLE>

During 2002, expenditures for exploration and development activities totaled
$217.2 million as compared to $272.3 million in 2001 (2000 - $232.3 million). A
total of 135 gross (99.4 net) wells were drilled during the year, including 15
gross (6.3 net) wells in the fourth quarter, compared to 196 gross (158.7 net)
wells in 2001 (2000 - 163 gross, 128.7 net).

Net capital expenditures, including property acquisitions net of dispositions
and the acquisition of Summit, amounted to $521.3 million in 2002 as compared to
$261.2 million in 2001 (2000 - $249.0 million).

Dry hole and geological and geophysical costs expensed totaled $129.4 million in
2002 as compared to $19.6 million in 2001 (2000 - $13.8 million). Included in
this amount are $41.9 million associated with exploratory wells drilled in
Canada in previous years, and $66.0 million related to exploratory projects in
the United States, which the Company has determined to be unsuccessful. Seismic
costs during 2002 totaled $9.3 million, as compared to $10.6 million in 2001
(2000 - $6.8 million).

In conjunction with the cash compensation received from the Alberta Crown
related to the Surmont natural gas/bitumen issue, the Company has made a
provision of approximately $9.1 million (net of $1.8 million accumulated
depletion and depreciation) in recognition of the impairment in asset value
resulting from the shut-in. This amount represents the net book value of the
assets carried in the financial statements.

Paramount has also recorded a $31.3 million impairment charge in respect of
producing non-core oil and gas assets located in Alberta and Southeast
Saskatchewan.

<PAGE>

                                       13

For 2003, Paramount's capital expenditure budget will be funded by internally
generated cash flow and minor property dispositions. Any deficiency will draw
upon existing credit facilities.

INVESTMENTS

SHORT-TERM INVESTMENTS
The Company has the following short-term investments:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                               OPENING        PURCHASED        CLOSING                          GAIN ON
                                             2002 SHARES       (SOLD)        2002 SHARES     INVESTMENT           SALE
--------------------------------------------------------------------------------------------------------------------------
<S>                                           <C>            <C>             <C>           <C>               <C>
INVESTMENTS
Peyto Exploration and Development Corp.       8,709,072      (8,709,072)             -     $          -      $ 40,105,111
Triquest Energy Corp.***                      5,000,000      (5,000,000)             -                -           725,000
Fox Creek Petroleum Corp.                     1,028,571       1,144,591      2,173,162        2,234,000
Jurassic Oil and Gas Ltd.                                       850,000        850,000        1,020,000
Spearhead Resources Inc.*                                                                     5,000,000
Altius Energy Corp.**                                                                         4,690,240
--------------------------------------------------------------------------------------------------------------------------
                                                                                           $ 12,944,240      $ 40,830,111
--------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------
</TABLE>
*    Spearhead Resources Inc. $5 million 8 percent secured convertible debenture
     due September 12, 2003
**   Altius Energy Corp. $2.7 million US 14 percent secured convertible
     debenture due April 9, 2005
***  During the year Triquest shares were consolidated on a 4-for-1 basis.
     Actual Triquest shares sold in 2002 were 1,250,000.

At December 31, 2002, all short-term investments were either debentures, or
warrants or shares in private companies, therefore a market value for these
assets is not readily accessible. The Company believes that the market value of
its short-term investments approximates their book value.

INVESTMENT IN DRILLING COMPANY

Paramount owns a 50 percent equity interest in Wilson Drilling Ltd., a private
company established to operate 3 drilling rigs in Western Canada. The Company
accounts for its interest using proportionate consolidation whereby its pro-rata
share of the financial results is combined on a line-by-line basis with similar
items in the Company's financial statements.

INVESTMENT IN PIPELINE COMPANY

Paramount owns a 50 percent equity interest, before payout (45 percent after
payout) in Shiha Energy Transmission Ltd., a private company established to
transport natural gas from operations in the Liard core area, Northwest
Territories to facilities in British Columbia. The Company accounts for its
interest using proportionate consolidation whereby its pro-rata share of the
financial results is combined on a line-by-line basis with similar items in the
Company's financial statements.

<PAGE>

                                       14

INVESTMENT IN ENGINEERING COMPANY

Paramount owns a 50 percent equity interest in a private company whose principal
business is to provide consulting and technical engineering services. The
Company accounts for its interest using proportionate consolidation whereby its
pro-rata share of the financial results is combined on a line-by-line basis with
similar items in the Company's financial statements.

DEFERRED REVENUE

During 2002, Paramount recognized in revenue $39.4 million (2001 - $1.2 million;
2000 - $1.2 million) of deferred revenue primarily related to the settlement of
natural gas commodity hedging contracts that were previously put in place to
shelter the Company from declining gas prices. Paramount's accounting policy
recognizes these gains in the accounting years of related production. The
deferred hedging gains of $7.8 million at December 31, 2002 will be recognized
in revenue in 2003.

BANK DEBT, LIQUIDITY AND RISK MANAGEMENT

Paramount's debt and equity capital structure as at December 31, 2002, was as
follows:

<TABLE>
<CAPTION>
-------------------------------------- ------------------------------------ -----------------------------------
(thousands of dollars, except per                    AT COST                           AT MARKET(1)
share)                                    AMOUNT        %       $/SHARE(2)     AMOUNT        %       $/SHARE(2)
-------------------------------------- ------------ --------- ------------- ------------ --------- -------------
<S>                                    <C>          <C>       <C>           <C>          <C>       <C>
Bank debt, net of working capital          555,243       54         9.34        555,243       32          9.34
Future income taxes                        279,855       27         4.71        279,855       16          4.71
Common share equity                        190,193       19         3.20        891,879       52         15.00
-------------------------------------- ------------ --------- ------------- ------------ --------- -------------
TOTAL                                    1,025,291      100        17.25      1,726,977      100         29.05
-------------------------------------- ------------ --------- ------------- ------------ --------- -------------
</TABLE>

(1)  Close at December 31, 2002 - $15.00 /share.
(2)  At December 31, 2002 - 59,458,600 basic common shares outstanding.

To finance the acquisition of Summit, the Company negotiated a $600 million
credit facility with a syndicate of Canadian Chartered Banks, including a $466
million production facility, a $25 million working capital facility, and a $109
million bridge facility. Upon receipt of the Surmont proceeds the bridge
facility was permanently reduced by approximately $47.1 million.

Upon closing of the Initial offering of units by Paramount Energy Trust (the
"Trust"), the proceeds received by the Company in exchange for petroleum and
natural gas properties sold to the Trust were used to permanently reduce bank
indebtedness. Effective March 12, 2003, the available borrowing base under the
current credit facility was reduced to $315.5 million.

<PAGE>

                                       15

Also of significant importance to the Company is the Canada/US exchange ratio,
since a substantial percentage of the natural gas sales and crude oil sales of
the Company are made into and priced effectively on US markets. Any improvement
in the Canadian dollar relative to its US counterpart will have a negative
impact on the wellhead price received for our production. To manage this risk,
Paramount has entered into currency swap agreements that have fixed the exchange
rates on US $40.9 million of future production revenue over the next three years
at CDN $58.6 million. In addition, the Company's US $20 million bank loan is
also designated as a currency hedge.

As at December 31, 2002, the Company's issued share capital consisted of
59,458,600 common shares (December 31, 2001 and 2000 - 59,453,600 common
shares). Paramount instituted a "Normal Course Issuer Bid" to acquire a maximum
of 5 percent of its issued and outstanding shares commencing September 1, 2001,
and ending August 31, 2002. During 2002, no shares were purchased pursuant to
the plan.

RISKS AND UNCERTAINTIES

Companies involved in the exploration for and production of oil and natural gas
face a number of risks and uncertainties inherent in the industry. The Company's
performance is influenced by commodity pricing, transportation and marketing
constraints and government regulation and taxation.

Natural gas prices are influenced by the North American supply and demand
balance as well as transportation capacity constraints. Seasonal changes in
demand, which are largely influenced by weather patterns, also affect the price
of natural gas.

Stability in natural gas pricing is available through the use of short and
long-term contract arrangements. Paramount utilizes a combination of these types
of contracts, as well as spot markets, in its natural gas pricing strategy. As
the majority of the Company's natural gas sales are priced to US markets, the
Canada/US exchange rate can strongly affect revenue.

Oil prices are influenced by global supply and demand conditions as well as for
worldwide political events. As the price of oil in Canada is based on a US
benchmark price, variations in the Canada/US exchange rate further affect
Paramount's oil price.

The Company's access to oil and natural gas sales markets is restricted, at
times, by pipeline capacity. In addition, it is also affected by the proximity
of pipelines and availability of processing equipment. Paramount controls as
much of its marketing and transportation activities as possible in order to
minimize any negative impact from these external factors.

The oil and gas industry is subject to extensive controls, regulatory policies
and income taxes imposed by the various levels of government. These controls and
policies, as well as income tax laws and regulations, are amended from time to
time. The Company has no control over government intervention or taxation levels
in the oil and gas industry; however, it operates in a manner to ensure that it
is in compliance with all regulations and is able to respond to changes as they
occur.

<PAGE>

                                       16

Paramount's operations are subject to the risks normally associated with the oil
and gas industry including hazards such as unusual or unexpected geological
formations, high reservoir pressures and other conditions involved in drilling
and operating wells. The Company minimizes these risks using prudent safety
programs and risk management, including insurance coverage against potential
losses.

The Company recognizes that the industry is faced with an increasing awareness
with respect to the environmental impact of oil and gas operations. Paramount
has reviewed the environmental risks to which it is exposed and has determined
that there is no current material impact on the Company's operations; however,
the cost of complying with environmental regulations is increasing. Paramount
will ensure continued compliance with environmental legislation.

KYOTO PROTOCOL ON GREENHOUSE GAS EMISSIONS

Canada is signatory to an International Treaty to achieve a 6 percent reduction
from 1990 greenhouse gas emission levels by 2008-2012, which represents
approximately a 25 percent cut from current levels. At this time the Company
does not know what final course of action the Canadian or United States
governments will take in this regard and accordingly cannot measure the
potential risk to our business.

2003 CASH FLOW FORECAST AND SENSITIVITY ANALYSIS

The Company's earnings and cash flow are highly sensitive to changes in
commodity prices, exchange rates and other factors that are beyond the control
of the Company. Current volatility in commodity prices creates uncertainty as to
Paramount's cash flow and capital expenditure budget. The Company will therefore
assess results throughout the year and revise budgets as necessary to reflect
most current information. The following analysis assesses the magnitude of these
sensitivities on the Company's 2003 cash flow using the following base
assumptions:

a)   2003 PRODUCTION
     Natural gas                                          160 MMcf/d
     Crude oil/liquids                                    7,000 Bbl/d

b)   2003 AVERAGE PRICES
     Natural gas                                          $5.80Mcf
     Crude oil/liquids (W.T.I.)                           $28.00/Bbl

c)   2003 CASH FLOW                                       $200 million

d)   2003 NET CAPITAL EXPENDITURES                        $150 million

<PAGE>

                                       17

The following analysis assesses the estimated after-tax impact on cash flow with
variations in production, price, interest and exchange rates:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------ -----------------
SENSITIVITY (millions of dollars)                                                 CASH FLOW
------------------------------------------------------------------------------ -----------------
<S>                                                                            <C>
     Gas sales change of 10 MMcf/d                                                  13.5
     Gas price change of $0.10/Mcf                                                   3.7
     Oil and natural gas liquids sales change of 100 Bbl/d                           0.8
     Oil and natural gas liquids price change of $1.00/Bbl (W.T.I)                   1.6
     Sensitivity to Canada/US exchange rate fluctuation of  $0.01 CDN                0.5
     Average interest rate change of 1%                                              2.0
------------------------------------------------------------------------------ -----------------
</TABLE>

RECENT ACCOUNTING PRONOUNCEMENTS

HEDGING RELATIONSHIPS

The CICA issued Accounting Guideline 13 - Hedging Relationships, which deals
with the identification, designation, documentation and effectiveness of hedging
relationships for the purpose of applying hedge accounting. The guideline
establishes conditions for applying hedge accounting, but does not specify hedge
accounting methods. The guideline is effective for fiscal years beginning on or
after July 1, 2003. The Company anticipates that adoption of Accounting
Guideline 13 will not have a material effect on its consolidated financial
statements.

IMPAIRMENT OF LONG-LIVED ASSETS

The CICA recently issued Handbook Section 3063 - Impairment of Long-Lived

Assets. This new Section establishes standards for the recognition, measurement
and disclosure of the impairment of long-lived assets by profit-oriented
enterprises. The section is effective for fiscal years beginning on or after
April 1, 2003.

Under the new Section, impairment of long-lived assets held for use is
determined by a two-step process, with the first step determining when an
impairment is recognized and the second step measuring the amount of the
impairment. To test for and measure impairment, long-lived assets are grouped at
the lowest level for which identifiable cash flows are largely independent. An
impairment loss is recognized when the carrying amount of a long-lived asset
exceeds the sum of the undiscounted cash flows expected to result from its use
and eventual disposition. An impairment loss is measured as the amount by which
the long-lived asset's carrying amount exceeds its fair value. This represents a
significant change to Canadian GAAP, which previously measured the amount of the
impairment as the difference between the long-lived asset's carrying value and
its net recoverable amount (i.e. undiscounted cash flows plus residual value).
The potential impact of this pronouncement on the Company's consolidated
financial statements is not known at present.

<PAGE>

                                       18

DISPOSAL OF LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS

The CICA recently issued Handbook Section 3475 - Disposal of Long-Lived Assets
and Discontinued Operations, which establishes standards for the recognition,
measurement, presentation and disclosure of the disposal of long-lived assets by
profit-oriented enterprises. It also establishes standards for the presentation
and disclosure of discontinued operations.

Although earlier adoption is encouraged, section 3475 applies to disposal
activities initiated by a company's commitment to a plan on or after May 1,
2003. The Company anticipates that adoption of this pronouncement will not have
a material effect on its consolidated financial statements.<PAGE>
                                                                     EXHIBIT 4.3

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's Discussion and Analysis ("MD&A") should be read in conjunction with
the interim unaudited consolidated financial statements for the three and six
months ended June 30, 2003 and the audited consolidated financial statements and
MD&A for the year ended December 31, 2002.

DRILLING

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                SIX MONTHS ENDED JUNE 30
-------------------------------------------------------------------------------------------------
WELLS DRILLED                         2003                                  2002
-------------------------------------------------------------------------------------------------
                           GROSS (1)          NET (2)           Gross (1)          Net (2)
                       --------------------------------------------------------------------------
<S>                    <C>                    <C>               <C>                <C>
Natural gas                           96                 75               102                 80
Oil                                   10                  9                 3                  3
Other                                 -                  -                  2                  1
Dry                                    8                  6                 9                  7
-------------------------------------------------------------------------------------------------
TOTAL                                114                 90               116                 91
-------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------
</TABLE>

(1)  "Gross" wells means the number of wells in which Paramount has a working
     interest.

(2)  "Net" wells means the aggregate number of wells obtained by multiplying
     each gross well by Paramount's percentage working interest therein.

During the six months ended June 30, 2003, Paramount participated in the
drilling of 114 gross wells (90 net) including 37 wells (33 net) in the second
quarter, compared to 116 gross wells (91 net) during the same period in 2002.

CAPITAL EXPENDITURES

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                                                  SIX MONTHS ENDED JUNE 30
----------------------------------------------------------------------------------------------------
(thousands of dollars)                                        2003            2002            2001
----------------------------------------------------------------------------------------------------
<S>                                                        <C>              <C>            <C>
Land                                                       $   7,441        $  3,531       $ 18,861
Geological and geophysical                                     4,171           6,883          7,219
Drilling                                                      55,435         106,196         94,090
Production equipment and facilities                           36,021          60,442         76,423
----------------------------------------------------------------------------------------------------
NET EXPLORATION AND DEVELOPMENT EXPENDITURES                 103,068         177,052        196,593
Summit Resources Limited acquisition                               -         437,933              -
Dry hole and seismic costs expensed                          (23,620)        (10,053)       (11,802)
Petroleum and natural gas property impairme nt                (9,868)        (49,136)             -
Property acquisitions                                              -          28,400          6,962
Property dispositions                                       (324,845)         (1,344)        (7,068)
Other                                                            490             505            633
Depletion and depreciation expense                           (83,183)        (60,600)       (32,000)
----------------------------------------------------------------------------------------------------
NET CHANGE IN CAPITAL ASSETS                               $(337,958)       $522,757       $153,318
----------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                                       2

Capital additions for the quarter were concentrated in the Kaybob and Cameron
Hills areas. For the six months ended June 30, 2003, net exploration and
development expenditures totaled $103.1 million.

During the second quarter 2003, Paramount closed a number of minor non-core
property dispositions for net proceeds of approximately $39 million. Total
proceeds received to date for the minor property dispositions is approximately
$59 million. The proceeds received from the minor property dispositions have
been applied against the Company's debt facilities.

STOCK OPTIONS

During the quarter 1,455,500 stock options were issued at an exercise price of
$9.00 per option. Also during the quarter, 941,500 stock options issued in 2001,
the majority of which were at exercise prices of $14.50 and $13.35 per option,
were re-priced to exercise prices of $10.22 and $9.07 per option, respectively.
Total stock options issued and outstanding at June 30, 2003 were 2,977,000.

REVENUE

Natural gas revenue before hedging totaled $195.6 million for the six months
ended June 30, 2003, as compared to $130.1 million during the same period in
2002. The increase in natural gas revenue results from higher commodity prices
received during the period. Stronger natural gas demand resulted in an increase
of 115 percent in Paramount's year-to-date average natural gas sales price to
$6.45/Mcf (pre-hedge) as compared to $3.00/Mcf (pre-hedge) for the comparable
period in 2002. Included in gross revenue are $40.3 million of natural gas
hedging losses. The 2003 year-to-date average natural gas price after hedging
was $5.08/Mcf.

For the three months ended June 30, 2003, natural gas revenue before hedging
totaled $76.3 million as compared to $81.1 million for the same period in 2002.
The 13 percent reduction in quarter-over-quarter sales was primarily due to the
disposition of the Northeast Alberta assets to the Trust in March 2003.

Natural gas sales volumes averaged 167.4 MMcf/d to June 30, 2003, as compared to
221.5 MMcf/d reported for the same period in 2002. Second quarter natural gas
sales averaged 142.0 MMcf/d, a 39 percent decrease from 231.4 MMcf/d reported
for the equivalent period in 2002. The decrease in natural gas sales is
primarily the result of the disposition of the Northeast Alberta assets to the
Trust.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
REVENUE ANALYSIS                                                SIX MONTHS ENDED JUNE 30
---------------------------------------------------------------------------------------------------
(thousands of dollars)                                 2003               2002              2001
---------------------------------------------------------------------------------------------------
<S>                                                 <C>                <C>               <C>
Natural gas and other                               $ 195,596          $ 130,138         $ 349,552
Crude oil and natural gas liquids                      55,621             17,400            13,973
Commodity hedging gain (loss)                         (44,322)            31,495           (36,769)
Gain (loss) on sale of short-term investments          (1,020)            40,105             2,982
Other revenue                                             671                  -                 -
---------------------------------------------------------------------------------------------------
GROSS REVENUE                                         206,546            219,138           329,738
Royalties                                             (50,912)           (25,600)          (69,059)
---------------------------------------------------------------------------------------------------
NET REVENUE                                         $ 155,634          $ 193,538         $ 260,679
---------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                                       3

Oil and natural gas liquids revenue before hedging for the six months ended June
30, 2003 increased 220% to $55.6 million as compared to $17.4 million for the
comparable period in 2002. The increase in oil and natural gas liquids revenue
results from higher commodity prices, the addition of Summit's oil and natural
gas liquids production and new oil production from Cameron Hills. Stronger oil
and natural gas liquids demand resulted in an increase of 29 percent in
Paramount's year-to-date average oil and natural gas liquids sales price to
$40.03/Bbl (pre-hedge) as compared to $31.09/Bbl (pre-hedge) in the comparable
period in 2002. Included in gross revenue are $4.0 million of oil and natural
gas liquids hedging losses. The 2003 year-to-date crude oil price after hedging
was $37.97/Bbl.

For the three months ended June 30, 2003, oil and natural gas liquids revenue
before hedging totaled $25.2 million as compared to $8.1 million for the same
period in 2002.

Oil and natural gas liquids production volumes increased 148 percent to average
7,677 Bbl/d for the six months ended June 30, 2003 as compared to 3,092 Bbl/d
for the comparable period in 2002. The increase is attributable to the
acquisition of Summit, which at the time of acquisition produced approximately
5,000 Bbl/d of oil and natural gas liquids. Cameron Hills oil production
contributed approximately 154 Bbl/d for the six months ended June 30, 2003. Once
all five Cameron Hills oil wells are on line, gross production is estimated to
be 1,500 Bbl/d of which 1,372 Bbl/d will be net to Paramount.

Oil and natural gas liquids production volumes totaled 7,465 Bbl/d in the second
quarter of 2003, as compared to 2,639 Bbl/d for the comparable quarter of 2002.
The 5% decrease from oil and natural gas liquids production of 7,892 Bbl/d in
the first quarter of 2003 was due primarily to minor property dispositions
closed during the quarter, offset somewhat by new oil production at Sturgeon
Lake and Cameron Hills.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
CASH NETBACKS PER UNIT OF TOTAL PRODUCTION                          SIX MONTHS ENDED JUNE 30
---------------------------------------------------------------------------------------------------------
($/BOE@6:1)                                                 2003               2002               2001
---------------------------------------------------------------------------------------------------------
<S>                                                      <C>                <C>                <C>

Sales price before hedging                               $  39.00           $   20.37          $   50.65
Less:
    Royalties                                               (7.90)              (3.54)             (9.62)
    Operating costs                                         (5.77)              (5.60)             (4.07)
---------------------------------------------------------------------------------------------------------
CASH NETBACK, BEFORE HEDGING                                25.33               11.23              36.96
Commodity hedging gain (loss)                               (6.88)               4.35              (5.12)
---------------------------------------------------------------------------------------------------------
CASH NETBACK, AFTER HEDGING                              $  18.45           $   15.58          $   31.84
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                                       4

ROYALTIES

Alberta gas crown royalties are a cash royalty calculated on the Crown's share
of production using the Alberta Reference Price. The Alberta Reference Price is
the monthly weighted average well head price for gas consumed in Alberta and gas
exported from Alberta reduced by allowances for transportation and marketing. A
subsequent cost of service credit is applied to account for the Crown's share of
allowable capital and processing fees to arrive at the net royalty. Generally
the Crown's share of production will increase in a higher price environment.

Royalties for the six months ended June 30, 2003 averaged $7.90/BOE or 20
percent of Paramount's average sales price of $39.00/BOE. This compares to
$3.54/BOE or 17 percent of the average sales price reported for the same period
in 2002. The increased rate results from the higher commodity prices received
during the quarter, before hedging losses, as compared to prior year. Hedging
losses do not reduce royalty expense due to the Crown's use of the Alberta
Reference Price to calculate royalties, as opposed to the Company's realized
price.

For the three months ended June 30, 2003, royalties totaled $19.7 million as
compared to $16.5 during the same period a year earlier.

OPERATING COSTS

For the six months ended June 30, 2003, operating costs totaled $37.2 million
compared to $40.5 million during the same period a year earlier.

On a unit-of-production basis, average operating costs increased 3 percent to
$5.77/BOE from $5.60/BOE in 2002. This increase reflects seasonal maintenance
associated with the Company's facilities as well as a general increase in the
cost of field services and supplies, as compared to prior year. For the three
months ended June 30, 2003, operating costs totaled $18.3 million as compared to
$22.6 million for the same period in 2002, as a result of the disposition of the
Northeast Alberta assets to the Trust and other property dispositions recorded
in 2003.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses totaled $9.4 million for the six months
ended June 30, 2003, as compared to $5.7 million recorded for the same period a
year earlier. On a unit-of-production basis, general and administrative expenses
increased to $1.45/BOE as compared to $0.79/BOE for the period ended June 30,
2003. The increase from 2002 is due primarily to lower overhead recoveries
related to lower capital spending levels compared to prior year. Paramount does
not capitalize any general and administrative expenses.

DRY HOLE COSTS

The Company follows the Successful Efforts Method of accounting for petroleum
and natural gas operations. Under this method the Company capitalizes only those
costs that result directly in the discovery of petroleum and natural gas
reserves. The cost of unproductive wells, abandoned wells and surrendered leases
are charged to earnings in the year of abandonment or

<PAGE>

                                       5

surrender. For the six months ended June 30, 2003, $19.4 million in dry hole
costs were recorded, as compared to $3.2 million in the same period of 2002. Of
the dry hole expense recorded in 2003, approximately $11.5 million results from
wells drilled in prior years, which were determined in the current year to be
incapable of production in economic quantities.

WRITE-DOWN OF US PETROLEUM AND NATURAL GAS PROPERTIES

During the three months ended June 30, 2003, the Company recorded a write-down
of $9.9 million, representing the remainder of its petroleum and natural gas
assets in California.

CURRENT INCOME TAXES

At December 31, 2002, the Company had accumulated tax pools of approximately
$796 million, which will be available for deduction in 2003 in accordance with
Canadian income tax regulations at varying rates of amortization. Paramount does
not expect to pay current income taxes in 2003.

In 2003, the Alberta provincial and Canadian federal governments introduced
legislation to reduce corporate taxes. The changes are considered substantively
enacted for the purposes of Canadian GAAP and, accordingly, the Company's future
income tax liability has been reduced by $33.4 million. The effect of this
reduction has been recognized on the income statement as a future tax recovery
for the three and six-month periods ended June 30, 2003.

CASH FLOW AND EARNINGS

Cash flow from operations totaled $95.0 million or $1.58 per basic and diluted
common share, representing a 31 percent decrease from the $139.2 million, or
$2.34 per basic and diluted common share reported for the corresponding period
in 2002. The decrease is due to lower production levels, as well as commodity
hedging losses, offset somewhat by higher natural gas and oil and natural gas
liquids prices, as compared to prior year. Fully diluted weighted average shares
outstanding totaled 60.2 million at June 30, 2003.

Cash flow will continue to be directed towards the Company's capital expenditure
program and the reduction of bank indebtedness.

Net loss for the six months ended June 30, 2003 totaled $0.8 million or $0.01
per basic and fully diluted common share, compared to net income of $45.5
million, or $0.77 per basic common share ($0.76 per fully diluted common share)
reported for the same period a year earlier. The net loss for the six month
period is the result of a commodity hedging loss of $44.3 million, offset by a
$33.4 million future tax gain due to changes in federal and provincial tax
rates. A one-time loss on sale of property and equipment of $21.7 million was
recorded as a result of the disposition of a non-core property in Alberta.

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