FOR: PARAMOUNT RESOURCES LTD.
TSX SYMBOL: POU
MAY 15, 2003 - 16:00 EST
Paramount Resources Ltd. Announces Results For The First
Quarter Ended March 31, 2003
CALGARY, ALBERTA--Paramount Resources Ltd. ("Paramount") is
pleased to announce its financial and operating results for the
three months ended March 31, 2003.
/T/
Highlights (unaudited)
FINANCIAL Three Months Ended March 31
($ thousands except per share amounts) 2003 2002 % Change
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Gross Revenue $ 121,724 $ 92,413 32%
Cash Flow (1)
From operations 58,489 58,197 1%
Per share (basic & diluted) 0.97 0.98 -1%
Earnings
Net earnings 624 18,912 -97%
Per share (basic & diluted) 0.01 0.32 -97%
Net Exploration and Development
Expenditures 52,409 106,261 -51%
Total Assets 1,286,306 1,246,899 3%
Net Debt(2) 325,529 321,714 1%
Shareholders' Equity 504,658 554,597 -9%
Common shares outstanding (000's)
-March 31 60,169 59,459 1%
-April 30 60,169 - -
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OPERATING
Production
Natural gas (MMcf/d) 193.2 211.5 -9%
Crude oil and liquids (Bbl/d) 7,892 3,548 122%
Total Production (MMcfeq/d)@ 10:1 272.1 247.0 10%
Total Production (BOE/d) @ 6:1 40,088 38,798 3%
Average Prices
Natural gas (pre-hedge) ($/Mcf) $ 6.85 $ 2.58 166%
Natural gas ($/Mcf) $ 5.35 $ 3.55 51%
Crude oil and liquids ($/Bbl) $ 38.95 $ 29.03 34%
Drilling Activity
Gas 67 96 -30%
Oil 5 3 67%
Other - 2 -
D&A 5 8 -38%
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Total Wells 77 109 -29%
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(1) Cash flow from operations is a non-GAAP term that represents net
earnings adjusted for non-cash items, dry hole costs and geological and
geophysical costs. The Company considers cash flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
necessary to fund future growth through capital investment and to repay
debt.
(2) Net debt is equal to the sum of accounts payable and accrued
liabilities, shareholder loan, bank loans, drilling rig indebtedness and
mortgage, less current assets.
/T/
Review of Operations
Significant Events
- In February 2003, Paramount Energy Trust units were dividended
to shareholders and began trading as PMT.UN on the Toronto Stock
Exchange.
- In March 2003, Paramount concluded the transaction to transfer
the remaining producing properties in Northeast Alberta to the
Trust. The properties transferred to the Trust averaged 97 MMcf/d
of gas production (16,167 BOE/d) in 2002.
- Paramount's property rationalization program resulted in
agreements to sell 16.1 MMcf/d and 1,436 Bbl/d (4,119 BOE/d) for
proceeds of $ 89 million.
- Cameron Hills oil development was completed and oil production
from the area commenced in April 2003.
Kaybob
In the Kaybob operating area, Paramount drilled 12 (8.4 net)
wells and participated in an additional 6 (2.8 net) non-operated
wells in the first quarter of 2003. This drilling program
resulted in 11.7 net cased wells; 5.6 net producing gas and oil
wells, 3.3 net completed and non-producing wells and 2.9 net
cased wells waiting on completion. Paramount's drilling and
completion interests vary due to the conversion of farm-out
interests after the drilling operations are completed. Drilling
and completion operations planned for April were suspended
prematurely due to an early spring breakup, resulting in the
three wells not being completed.
First quarter capital spending is estimated to be $17.5 million
versus a budgeted amount of $18.0 million. Production was added
at all of the major producing properties. Given a dry summer it
is anticipated that some production from the uncompleted wells
may be added prior to next winter.
First quarter 2003 natural gas and crude oil/natural gas liquid
production forecasts were 90.8 MMcf/d and 2,109 Bbl/d (17,242
BOE/d) and compared closely to the actual production rate of 87.1
MMcf/d and 2,404 Bbl/d (16,920 BOE/d). The natural gas
production for the quarter is 4 percent under forecast due to
three wells being completed for oil versus natural gas. Oil and
natural gas liquids production is 14 percent over forecast due to
the unexpected oil completions and higher liquids production from
the Kakwa property.
Annual production targets for Kaybob in 2003 are 90 MMcf/d and
2,200 Bbl/d of oil and natural gas liquids (17,200 BOE/d).
Sturgeon Lake / Mirage
In the Sturgeon Lake / Mirage operating unit, Paramount drilled
3.3 net wells, and re-completed 8.2 net existing wells. This
program added new reserves of 10.1 BCFeq. Pipeline and facility
construction is proceeding with 25 percent of the new reserves
already on production, and the remainder to be producing by the
third quarter of 2003.
The Mirage field saw the most activity with three re-completions
in uphole Cretaceous zones, and a new well drilled for Cretaceous
production. This activity resulted in production additions of 2
MMcf/d. Sturgeon Lake South, which was acquired over the last two
years, had four re-completions of existing wells, with one
already on production at 35 Bbl/d. The Goose River area had one
re-completion and a new well drilled. These will be tied- in by
the third quarter 2003. The Valhalla region had three successful
wells drilled and will be tied-in after spring break up.
The forecasted average production rates for the year for Sturgeon
Lake/Mirage are 15 MMcf/d of natural gas and 2,200 Bbl/d crude
oil and natural gas liquids (4,700 BOE/d). We had some unforeseen
downtime at Sturgeon Lake through the first quarter and we have
production which is being capacity limited at a third party
facility. This decrease is more than offset by increased volumes
at Mirage and Valhalla with better than expected results.
Northwest Alberta
In Northwest Alberta and Cameron Hills NWT Paramount participated
in the drilling of 22 (20.2 net) wells in the first quarter of
2003. Completions were attempted on 19 net wells with 8.3 net
2003 new drills proceeding to tie-in during the first quarter. No
additional drilling is forecast in Northwest Alberta for the
remainder of the year due to seasonal access. However, seismic
programs conducted in the first quarter are expected to firm up
drilling locations for the first quarter of 2004.
New wells drilled in the first quarter increased production by
11.5 MMcf/d of raw gas production and 500 Bbls/d of oil. Initial
deliverability of the new wells in Haro and Bistcho exceeded the
available capacity at their respective processing facilities.
Declining throughput at those facilities during the year is
expected to provide the necessary capacity required to fully
exploit the deliverability of the new drills.
An estimated $30 million net was expended during the first
quarter conducting the drilling, completion, and tie-in
operations outlined above. Included in this expenditure is $5
million for an oil pipeline connecting the Bistcho Lake facility
to Zama in addition to $5 million for construction of an oil
battery at Cameron Hills, NWT. Additional production was brought
onstream in the first quarter through the tie-in of wells drilled
in previous years.
Oil production from Cameron Hills commenced on April 7, 2003.
Operational challenges associated with startup of the newly
constructed Cameron Hills oil battery have delayed achieving the
1,500 Bbls/d target until mid May.
N.E. B.C / Liard
In February 2003 Paramount re-completed the b-83-K/94-O-14 well
(100% WI) that was originally drilled in March 2002. The well was
brought on stream on March 26 at 2.3 MMcf/d. Also in 2003
Paramount (100% WI) drilled an exploration test at McKay Lakes,
K-36. This well was drilled to test a Mattson sub-crop play
concept. The well reached total depth at 800 meters and was
abandoned due to the Mattson reservoir interval being wet.
Paramount participated in the Chevron et al Liard 2K-29 (I-40)
Nahanni well as to a 2.76 percent working interest. The well
flowed at 30 MMcf/d from the Nahanni on production test and is
slated to be brought on production at around 20 MMcf/d at the end
of April.
Southern Alberta / Saskatchewan / Montana / North Dakota
Production through the first quarter from the Southern Operating
Unit averaged 10.8 MMcf/d and 2,974 Bbls/d. No new production or
reserves additions were made in the Southern Operating Area in
the first quarter.
The Southern Operating Unit continued the process of
consolidation and focus in the first quarter of 2003. This
process will see the Southern Operating Unit divest of smaller
interest and non-operated / non-core properties and pursue the
growth of fewer, higher interest core properties. This process
will conclude in the second quarter of 2003 and see the Southern
Operating Area move from having in excess of 75 individual
properties down to seven or eight core properties.
Exploration
In late 2002 Paramount agreed to farm out to Anadarko Canada Ltd.
its interest in two Federal Exploration Licenses in the
Arrowhead/West Bovie Area in exchange for Anadarko drilling five
deep and three shallow exploration wells. Two of the wells were
suspended prior to reaching their objectives due to spring break
up. These wells will resume drilling next season when access
conditions permit. Of the remaining wells, three are classified
as gas discoveries (two deep and one shallow). Two wells
discovered hydrocarbons but require further evaluation and one
shallow well was abandoned. In light of these discoveries
Anadarko, on behalf of itself and Paramount, has submitted to the
NEB six Significant Discovery applications that will hold lands
associated with the discoveries made to date.
In 2002 Paramount agreed to farm out to Anadarko Canada Ltd. its
interest in Federal Exploration License 380 in the Liard Area in
exchange for Anadarko shooting a seismic program with a
subsequent option to drill a deep exploration well. Anadarko shot
a 3D seismic survey over the exploration license in 2002 and in
February of 2003 spud the Liard P-16 well. This well reached a
total depth of 3,125 meters (3,064 meters TVD) and encountered
gas within the Nahanni formation. Anadarko's current plans are to
stimulate and test the capability of the well as soon as spring
breakup is over.
Situated at the Arctic Circle, the Colville Lake Area has
significant potential for large-scale gas and condensate reserves
trapped structurally and stratigraphically within sandstones of
Cambrian Age. Paramount, over the last three years, has acquired
a significant land base in the area of some 650,000 acres (~ 28
Alberta townships). In late 2002 Paramount acquired a 50-percent
partner in all of its lands in the area in order to accelerate
the exploration of these lands. Apache Canada as part of the
partnership agreement participated in the drilling of two
1,450-meter wells on Paramount's Nogha prospect. The first well
Nogha C-49 was drilled, cased and completed as a Mt. Clarke gas
well. The second well, Nogha M-17, was also drilled and cased
although completion operations were suspended due to spring
breakup. In addition to the evaluation of the Nogha Block, the
partners purchased and reprocessed 2D trade seismic data and
carried out a new 156 km 2D seismic survey over Federal
Exploration License 399. This seismic will be evaluated in the
spring to define future drilling locations. On Federal
Exploration License 414 trade seismic data was purchased and
reprocessed. This data is currently being mapped to assist in the
planning of a seismic survey that will be carried out later this
year.
Financial
Petroleum and natural gas revenue totaled $120.6 million for the
three months ended March 31, 2003, as compared to $76.8 million
for the corresponding period in 2002. The increase in revenue is
a result of higher crude oil and natural gas prices, as well as a
10 percent increase in average production to 272.1 MMcfeq/d
(40,088 BOE/d) in the current quarter as compared to 247.0
MMcfeq/d (38,798 BOE/d) in the first quarter of 2002.
Cash flow from operations for the three months ended March 31,
2003 totaled $58.5 million or $0.97 per basic and fully diluted
common share, a 1 percent increase from the $58.2 million or
$0.98 per basic and fully diluted common share reported for the
comparable quarter in 2002.
Net earnings for the current quarter totaled $0.6 million or
$0.01 per basic and fully diluted common share, as compared to
$18.9 million or $0.32 per basic and fully diluted common share
for the three months ended March 31, 2002.
Outlook
As previously reported, Paramount is selling 16.1 MMcf/d and
1,436 Bbl/d (4,119 BOE/d) for proceeds of $89 Million. As a
result of these transactions, Paramount now expects daily
production of 150 to 160 MMcf/d and 7,000 Bbl/d or 32,000 to
33,600 BOE/d on a 6:1 basis and cash flow of approximately $200
million or $ 3.30/share. Paramount's capital expenditure program
budget for all of 2003 is $150 to $175 million. As a result of
excess cash flow, the disposition program, and the closing of the
transactions associated with the Paramount Energy Trust creation,
year-end debt levels are projected to be reduced to approximately
$200 million.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's Discussion and Analysis ("M D & A") should be read
in conjunction with the interim unaudited consolidated financial
statements for the three months ended March 31, 2003 and the
audited consolidated financial statements and M D & A for the
year ended December 31, 2002.
During the first quarter 2003, Paramount Resources Ltd.
("Paramount" or the "Company") completed the formation and
structuring of Paramount Energy Trust (the "Trust"), through the
following transactions:
1. On February 3, 2003, Paramount transferred to the Trust
natural gas assets in the Legend area of Northeast Alberta for
net proceeds of $28 million and 9,907,767 units of the Trust.
2. On February 3, 2003, Paramount declared a dividend-in-kind of
an aggregate of 9,907,767 units of the Trust. The dividend was
paid to shareholders of Paramount common shares of record on the
close of business on February 11, 2003. The dividend was declared
after the Trust received all regulatory clearances with respect
to its final prospectus in Canada and its registration statement
in the United States. The final prospectus and registration
statement qualified and registered (i) the Dividend Trust Units,
(ii) Rights to purchase further Trust Units, and (iii) the Trust
Units issuable upon exercise of the Rights.
3. On March 11, 2003, in conjunction with the closing of a rights
offering by the Trust, Paramount disposed of additional natural
gas assets in Northeast Alberta to Paramount Operating Trust for
net proceeds of $175 million. The combined production of the
Northeast Alberta assets, including the Legend assets, averaged
97 MMcf/d during 2002.
The Company closed several minor non-core property dispositions
during the quarter. Net proceeds of approximately $20 million
were received during the first three months of 2003. In total,
Paramount has agreed to sell properties in Southern Alberta,
Saskatchewan and North Dakota for proceeds of approximately $89
million. Closing of all dispositions is expected to occur before
the end of June 2003. The proceeds received to date for the minor
property dispositions and the closing of the transactions
associated with the Trust have been applied against the Company's
debt facilities.
CAPITAL EXPENDITURES
/T/
CAPITAL EXPENDITURES
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Three Months Ended March 31
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Wells Drilled 2003 2002
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Gross (1) Net (2) Gross (1) Net (2)
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Natural gas 67 47.6 96 76.5
Oil 5 5.0 3 2.8
Standing/Service - - 2 1.4
Dry 5 4.2 8 7.3
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Total 77 56.8 109 88.0
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(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 three months ended March 31, 2003, Paramount participated in
the drilling of 77 gross wells (56.8 net), compared to 109 gross wells
(88.0 net) during the same period in 2002.
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Three Months Ended March 31
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Capital Expenditures (thousands of
dollars) 2003 2002 2001
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Land $ 2,206 $ 2,141 $ 11,094
Geological and geophysical 748 558 2,440
Drilling 39,307 77,838 85,199
Production equipment and facilities 10,148 22,115 17,024
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Net exploration and
development expenditures $ 52,409 $ 102,652 $ 115,757
Dry hole and seismic costs expensed (9,639) (2,280) (4,469)
Property acquisitions - 8,370 1,239
Property dispositions (263,030) (2,428) (1,104)
Other 275 90 116
Depletion and depreciation expense (43,072) (30,678) (17,866)
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Net change in capital assets $ (263,057) $ 75,726 $ 93,673
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/T/
The majority of Paramount's capital expenditure program is
completed in the winter months, due to inaccessibility of our
remote locations in warmer months; capital additions for the
quarter were concentrated in the Kaybob and Cameron Hills areas.
For the three months ended March 31, 2003, net exploration and
development expenditures totaled $52.4 million, of which
approximately $13.0 million was spent on properties that were
subsequently sold to the Trust.
SHARE CAPITAL
During the quarter 710,000 stock options were exercised for total
proceeds of $10.3 million. As a result, common shares
outstanding increased at March 31, 2003, to 60,168,600, as
compared to 59,458,600 at December 31, 2002.
An additional 37,000 stock options and share appreciation rights
were exercised for cash consideration of $141,000, which amount
was charged to general and administrative expenses.
REVENUE
Natural gas revenue during the quarter increased 38 percent to
$92.9 million as compared to $67.6 million for the comparable
quarter in 2002. The increase in natural gas revenue results from
higher commodity prices received during the quarter. Stronger
natural gas demand resulted in an increase of 51 percent in
Paramount's average natural gas sales price to $5.35/Mcf as
compared to $3.55/Mcf in the comparable quarter in 2002. Included
in natural gas sales are $26.2 million of hedging losses. On a
per unit basis the 2003 first quarter price includes
approximately $1.50/Mcf loss from natural gas commodity hedges
that were in place during the period. Natural gas sales volumes
averaged 193.2 MMcf/d in the quarter as compared to 211.5 MMcf/d
for the comparable quarter in 2002. Compared to the fourth
quarter of 2002, natural gas sales decreased 26 percent from
262.6 MMcf/d. The decrease in natural gas sales is primarily the
result of the disposition of the Northeast Alberta assets to the
Trust.
/T/
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Three Months Ended March 31
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Revenue Analysis (thousands of dollars) 2003 2002 2001
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Natural gas and other $ 92,939 $ 67,563 $ 178,554
Crude oil and natural gas liquids 27,662 9,273 8,446
Gain on sale of short-term
investments - 15,577 2,982
Other revenue 1,123 - -
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Gross revenue 121,724 92,413 189,982
Royalties (31,217) (9,081) (43,661)
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Net revenue $ 90,507 $ 83,332 $ 146,321
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/T/
Oil and natural gas liquids revenue during the period increased
198% to $27.7 million as compared to $9.3 million for the
comparable quarter in 2002. The increase in oil and natural gas
liquids revenue results from higher commodity prices and the
addition of Summit's oil and natural gas liquids production.
Stronger oil and natural gas liquids demand resulted in an
increase of 34 percent in Paramount's average oil and natural gas
sales price to $38.95/Bbl as compared to $29.03/Bbl in the
comparable quarter in 2002. Included in the oil and natural gas
liquids sales are $2.9 million of hedging losses. On a per unit
basis the 2003 first quarter price includes approximately
$4.03/Bbl loss from oil and natural gas liquids commodity price
hedges that were in place during the period. Oil and natural gas
liquids volumes increased 122 percent to average 7,892 Bbl/d for
the quarter as compared to 3,548 Bbl/d for the comparable quarter
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.
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 three months ended March 31, 2003 averaged
$1.28/Mcfeq or 26 percent of Paramount's average sales price of
$4.92/Mcfeq. This compares to $0.41/Mcfeq or 12 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 the
first quarter of 2002. 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.
OPERATING COSTS
For the three months ended March 31, 2003, operating costs
totaled $18.9 million compared to $18.0 million during the same
period a year earlier.
On a unit-of-production basis, average operating costs decreased
5 percent to $0.77/Mcfeq from $0.81/Mcfeq in 2002. Historically,
Paramount's operating costs on a unit-of-production basis have
been higher during the first quarter as compared to annual
average. Many of Paramount's properties are inaccessible in the
warmer months due the ground conditions of their locations and
this requires maintenance and repair projects to be performed in
the winter months. For the remainder of 2003, the Company
expects operating costs in total and on a unit-of-production
basis to decline in recognition of the disposal of higher cost
assets in Northeast Alberta. In addition, as experienced in
previous years when new production comes onstream and
efficiencies are optimized from work done during the winter,
operating costs in total and on a unit-of-production basis are
reduced.
/T/
GENERAL AND ADMINISTRATIVE EXPENSES
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Three Months Ended March 31
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General and Administrative Expenses
(thousands of dollars) 2003 2002 2001
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General and administrative expenses $ 4,627 $ 2,689 $ 2,635
Share appreciation rights and stock
options exercised for cash 141 376 813
Stock-based compensation expensed - 229 -
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Total general and administrative
expenses $ 4,768 $ 3,294 $ 3,448
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/T/
General and administrative expenses totaled $4.8 million for the
three months ended March 31, 2003, as compared to $3.3 million
recorded for the same period a year earlier. On a
unit-of-production basis, general and administrative expenses
before costs associated with the Share Appreciation Rights Plan
increased to $0.19/Mcfeq as compared to $0.12/Mcfeq for the
period ended March 31, 2002. In 2002, 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. Costs increases associated
with additional staffing levels include salary, benefits and
rent. General and administrative expenses are expected to decline
for the remainder of 2003 as the Trust's operations will be
excluded from Paramount's activities effective March 11, 2003.
Paramount does not capitalize any general and administrative
expenses.
DRYHOLE 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 surrender. For
the three months ended March 31, 2003, $8.9 million in dryhole
costs were recorded, as compared to $1.7 million in the first
quarter of 2002. Of the dry hole expense recorded in 2003,
approximately $4.9 million results from wells drilled in prior
years, which were determined in the current year to be incapable
of production in economic quantities.
CURRENT INCOME TAX
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.
CASH FLOW AND EARNINGS
Cash flow from operations totaled $58.5 million or $0.97 per
basic and fully diluted common share, representing a 1 percent
increase from the $58.2 million, or $0.98 per basic and fully
diluted common share reported for the corresponding period in
2002. Fully diluted weighted average shares outstanding totaled
60.1 million in the current quarter.
Cash flow will continue to be directed towards the Company's
capital expenditure program and the reduction of bank
indebtedness.
Net earnings for the three months ended March 31, 2003 totaled
$0.6 million or $0.01 per basic and fully diluted common share,
compared to net income of $18.9 million, or $0.32 per basic and
fully diluted common share reported for the same period a year
earlier. The lower net income for the quarter is the result of a
significant commodity hedging loss of $29.1 million and an
increase in depletion and depreciation expense as compared to
2002.
/T/
Consolidated Balance Sheets
March 31 December 31
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(thousands of dollars) 2003 2002
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(unaudited)
ASSETS
Current Assets
Short-term investments (market value:
2003 - $13,995; 2002 -$14,168) $ 13,995 14,168
Accounts receivable (note 5) 108,524 91,042
Prepaid expenses 14,883 19,213
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137,402 124,423
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Property, Plant and Equipment
Petroleum and natural gas properties, at cost 1,475,437 1,961,369
Accumulated depletion and depreciation (326,533) (549,408)
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1,148,904 1,411,961
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$ 1,286,306 $ 1,536,384
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 158,629 $ 140,396
Shareholder loan (note 5) - 33,000
Bank loans (notes 2, 4 and 5) 296,294 498,097
------------------------------------------------------------------------
454,923 671,493
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Drilling rig indebtedness (note 5) 1,354 1,443
Mortgage (note 5) 6,654 6,730
Provision for future site restoration
and abandonment costs 18,316 22,954
Deferred revenue 5,344 7,804
Future income taxes 295,057 279,855
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326,725 318,786
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Commitments and contingencies (note 5)
Shareholders' Equity
Share capital (note 6)
Issued and outstanding
60,168,600 common shares (2002-
59,458,600 common shares) 200,510 190,193
Retained earnings 304,148 355,912
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504,658 546,105
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$ 1,286,306 $ 1,536,384
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See accompanying notes to consolidated financial statements
Consolidated Statements of Earnings and Retained Earnings (unaudited)
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Three Months Ended March 31
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(thousands of dollars except per share amounts) 2003 2002
------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 120,601 $ 76,836
Royalties (net of ARTC) (31,217) (9,081)
Gain on sale of investments - 15,577
Other revenue 1,123 -
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90,507 83,332
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Expenses
Operating 18,866 17,992
Interest 7,062 2,591
General and administrative 4,768 3,294
Geological and geophysical 748 558
Dry hole costs 8,891 1,722
Lease rentals 775 643
Gain on sales of property, plant and
equipment (271) (413)
Provision for future site restoration
and abandonment costs 1,262 600
Depletion and depreciation 43,072 30,678
------------------------------------------------------------------------
85,173 57,665
------------------------------------------------------------------------
Earnings before taxes 5,334 25,667
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Income and other taxes
Large Corporations Tax and other 547 615
Future income tax 4,163 6,140
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4,710 6,755
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Net earnings 624 18,912
Retained earnings, beginning of period 355,912 346,064
Adjustment on disposition of assets to a
related party (note 3) (1,388) -
Dividends (note 3) (51,000) -
Adoption of new accounting policy (note 2) - (459)
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Retained earnings, end of period $ 304,148 $ 364,517
------------------------------------------------------------------------
------------------------------------------------------------------------
Net earnings per common share
- basic $ 0.01 $ 0.32
- diluted $ 0.01 $ 0.32
------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands)
- basic 59,998 59,459
- diluted 60,072 59,544
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Cash Flows (unaudited)
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Three Months Ended March 31
------------------------------------------------------------------------
(thousands of dollars) 2003 2002
------------------------------------------------------------------------
Operating activities
Net earnings $ 624 $ 18,912
Add (deduct) non-cash items
Depletion and depreciation 43,072 30,678
Gain on sales of property, plant and equipment (271) (413)
Provision for future site restoration
and abandonment costs 1,262 600
Future income taxes 4,163 6,140
Add items not related to operating activities
Dry hole costs 8,891 1,722
Geological and geophysical costs 748 558
------------------------------------------------------------------------
Cash flow from operations 58,489 58,197
Increase (decrease) in deferred revenue (2,460) 18,757
Change in non-cash operating working capital (28,527) 22,691
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27,502 99,645
------------------------------------------------------------------------
Financing activities
Bank loans - draws 10,000 7,236
Bank loans - repayments (211,803) -
Shareholder loan (33,000) -
Capital Stock 10,317 760
Mortgage (76) -
Drilling rig indebtedness (89) -
------------------------------------------------------------------------
(224,651) 7,996
------------------------------------------------------------------------
Cash flow (used in) provided by
operating and financing activities (197,149) 107,641
------------------------------------------------------------------------
Investing activities
Property, plant and equipment expenditures 51,936 102,184
Petroleum and natural gas property acquisitions - 8,370
Geological and geophysical costs 748 558
Proceeds on sale of property, plant and
equipment (note 3) (222,832) (2,571)
Change in non-cash investing working capital (27,001) (331)
------------------------------------------------------------------------
Cash flow (provided by) used in
investing activities (197,149) 108,210
------------------------------------------------------------------------
Decrease (increase) in cash - (569)
Cash, beginning of period - 740
------------------------------------------------------------------------
Cash, end of period $ - $ 171
------------------------------------------------------------------------
Income taxes paid $ 5,466 $ 25,000
------------------------------------------------------------------------
Interest paid $ 7,415 $ 2,676
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
/T/
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
(all tabular amounts expressed in thousands of dollars)
Paramount Resources Ltd. (the "Company") is involved in the
exploration and development of petroleum and natural gas
primarily in western Canada. The interim consolidated financial
statements are stated in Canadian dollars and have been prepared
by management in accordance with Canadian generally accepted
accounting principles. Certain information and disclosures
normally required to be included in notes to annual consolidated
financial statements has been condensed or omitted. The interim
consolidated financial statements should be read in conjunction
with the consolidated financial statements and the notes thereto
in Paramount's Annual Report for the year ended December 31,
2002.
The preparation of interim consolidated financial statements
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the interim
consolidated financial statements and the reported amounts of
revenues and expenses during the period. Actual results could
differ from those estimates.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements have been prepared
in a manner consistent with accounting policies utilized in the
consolidated financial statements for the year ended December 31,
2002.
2. CHANGE IN ACCOUNTING POLICY
(a) Stock Based Compensation
Effective January 1, 2002, the Company adopted the new Canadian
Institute of Chartered Accountants' standard on accounting for
Stock-Based Compensation. Under this new standard, the Company's
stock options and share appreciation rights, which can be settled
in cash at the discretion of the employee, are accounted for at
an amount equal to the difference between the exercise price and
the fair value at the date of grant, resulting in a liability and
corresponding compensation expense being recognized. The awards
are remeasured at each reporting date. As permitted by the new
standard, the Company applied the change retroactively for the
share appreciation rights without restatement of individual prior
periods. The impact of the adoption of the new standard on the
financial statements as at January 1, 2002, was as follows:
/T/
----------------------------------------------- Increase in liability $ 459 Decrease in retained earnings $ 459 -----------------------------------------------
/T/
The recognized expense for the three-month period ended March 31,
2003 was nil (2002 - $ 229,000).
This new standard requires the presentation of pro forma net
earnings as if the Company had accounted for all of its employee
stock options granted after December 31, 2001, under the fair
value method. Had compensation cost for the Company's stock-based
compensation plans been determined based on the fair value at the
grant date of these awards, the Company's net earnings and
earnings per share would have been reduced to the pro forma
amounts indicated below:
/T/
Three months ended March 31
------------------------------------------------------------------------
2003 2002
Net earnings as reported $ 624 $ 18,912
pro forma $ 596 $ 18,909
Net earnings per common share - basic as reported $ 0.01 $ 0.32
pro forma $ 0.01 $ 0.32
Net earnings per common share - diluted as reported $ 0.01 $ 0.32
pro forma $ 0.01 $ 0.32
------------------------------------------------------------------------
/T/
The fair value for these options was estimated at the date of
granting using a Black-Scholes Option Pricing Model with the
following assumptions: weighted-average risk-free interest rate
of 5.8 percent; dividend yield of 0 percent; weighted-average
volatility factor of the expected market price of the Company's
common shares of 39.5 percent; and a weighted-average expected
life of the options of 4 years.
(b) Bank Loans
On January 1, 2002, the Company adopted the new CICA Emerging
Issues Committee Abstract regarding balance sheet classification
of callable debt obligations and debt obligations expected to be
refinanced. All borrowings where the lender has the right to
demand repayment within 12 months or where the lender has the
right to refuse to roll over the borrowing for a further lending
period of longer than 12 months are required to be classified as
current liabilities. The impact of this change has been to
increase current liabilities by the amount of any such borrowings
then in place.
3. DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST
During the three months ended March 31, 2003, the Company
completed the formation and structuring of Paramount Energy Trust
(the "Trust") through the following transactions:
a) On February 3, 2003, Paramount transferred to the Trust
natural gas properties in the Legend area of Northeast Alberta
for net proceeds of $28 million and 9,907,767 units of the Trust.
b) On February 3, 3003, Paramount declared a dividend-in-kind of
an aggregate of 9,907,767 units of the Trust. The dividend was
paid to shareholders of Paramount common shares of record on the
close of business on February 11, 2003. The dividend was declared
after the Trust received all regulatory clearances with respect
to its final prospectus and registration statement in the United
States. The final prospectus and registration statement qualified
and registered (i) the Dividend Trust Units, (ii) Rights to
purchase further Trust Units, and (iii) the Trust Units issuable
upon exercise of the Rights.
c) On March 11, 2003, in conjunction with the closing of a rights
offering by the Trust, Paramount disposed of additional natural
gas properties in Northeast Alberta to Paramount Operating Trust
for net proceeds of $175 million.
In addition to transferring the natural gas properties to the
Trust, the Company transferred the related accumulated provision
for site restoration and abandonment costs. The Trust is a
related party as a result of a significant number of common
shareholders. As such, natural gas properties and related
liabilities were transferred at net book value, with no gain or
loss on disposition recorded. Details are as follows:
/T/
Natural gas properties $ 240,326 Future income tax liability 11,039 Site restoration liability (5,900) Costs of disposition 9,516 Adjustment to retained earnings (1,388) ----------------------------------------------- Net proceeds on disposition $ 253,593 ----------------------------------------------- -----------------------------------------------
/T/
Associated with the creation and financing of the Trust and the
transfer of natural gas properties to the Trust, the Company
incurred costs of approximately $9.5 million. These costs have
been included as a cost of disposition.
4. BANK LOANS
On June 28, 2002, 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. The term of
the facility is to April 30, 2003. Available borrowings under the
facility were reduced to $315.5 million upon completion of the
Trust disposition.
The Company has provided a first floating charge over all the
assets and a limited recourse guarantee from Paramount Oil and
Gas Ltd., a related entity with a significant ownership interest
in the Company. The facility bears interest at prime rates,
bankers acceptance rates or libor rates plus a margin ranging
from 50 to 150 basis points. There are no contractual repayment
requirements under this facility.
5. FINANCIAL INSTRUMENTS
The Company's financial instruments included in the consolidated
balance sheet are comprised of short-term investments, accounts
receivable, accounts payable and accrued liabilities, shareholder
loan, bank loans, mortgage and drilling rig indebtedness.
(a) Commodity Price Hedges
Financial forward sales arrangements entered into by the Company
are unchanged from those outstanding at December 31, 2002. Had
these financial contracts been settled on March 31, 2003, using
prices in effect at that time, the mark-to-market before-tax loss
would have totaled $34.1 million. During 2003, $29.1 million of
net losses related to commodity hedging contracts (2002 - $18.5
million of net gains) are included in petroleum and natural gas
sales.
(b) Foreign Exchange Hedges
Foreign currency index swap transactions entered into by the
Company are unchanged from those outstanding at December 31,
2002. At March 31, 2003, the estimated fair value of these hedges
based on the Company's assessment of available market information
was a loss of $1.3 million.
(c) Fair Values of Financial Assets and Liabilities
Borrowings under bank credit facilities and the issuance of
commercial paper are for short periods and are market rate based;
thus, carrying values approximate fair value. Fair values for
derivative instruments are determined based on the estimated cash
repayment or receipt necessary to settle the contract at
period-end. Cash payments or receipts are based on discounted
cash flow analysis using current market rates and prices
available to the Company.
The fair values of other financial instruments, including
accounts receivable, accounts payable and accrued liabilities and
shareholder loan, approximate their carrying values due to the
short-term maturity of those instruments.
The fair values of the mortgage and drilling rig indebtedness
approximate their carrying values, as there have been no
significant changes in long-term interest rates from the dates
these liabilities were incurred to the balance sheet date.
(d) Credit Risk
The Company is exposed to credit risk from financial instruments
to the extent of non-performance by third parties, and
non-performance by counterparties to swap agreements. The Company
minimizes credit risk associated with possible non-performance by
financial instrument counterparties by entering into contracts
with only highly rated counterparties; and controls third-party
credit risk with credit approvals, limits on exposures to any one
counterparty, and monitoring procedures. The Company sells
production to a variety of purchasers under normal industry sale
and payment terms. The Company's accounts receivable are with
customers and joint venture partners in the petroleum and natural
gas industry and are subject to normal credit risks.
6. SHARE CAPITAL
(a) Authorized Capital
The authorized capital of the Company consists of an unlimited
number of non-voting preferred shares without nominal or par
value, issuable in series, and an unlimited number of common
shares without nominal or par value.
(b) Issued Capital
During the three months ended March 31, 2003, a total of 747,000
stock options were exercised for proceeds of $10.3 million. At
March 31, 2003, 60,168,600 common shares of the Company were
issued and outstanding.
(c) Stock Option Plan/Share Appreciation Rights Plan
During 2001, the Company replaced the Share Appreciation Rights
Plan ("SARP") with the Employee Incentive Stock Option plan (the
"plan"). Under the plan, stock options are granted at the current
market price on the date of issuance. Participants in the plan,
upon exercising their stock options, have the option of receiving
a cash payment equal to the difference between the exercise price
and the market price of the Company's common shares, or receiving
common shares issued from Treasury. Cash payments made in respect
of the plan are charged to general and administrative expenses
when incurred. Options granted vest over four years and have a
four-and-a-half year contractual life. The Company has reserved
5.9 million stock options for issuance pursuant to the plan. On
February 6, 2003, all remaining outstanding SARPs were cancelled.
/T/
Stock option/SARP transactions for the respective periods are as follows:
------------------------------------------------------------------------
2003 2002
------------------------------------------------------------------------
Number of
Average Number of Average options/
grant price options/SARPs grant price SARPs
------------------------------------------------------------------------
Outstanding, January 1 $14.25 1,949,500 $14.08 2,173,500
Granted 12.02 645,000 16.74 44,000
Exercised 14.41 (747,000) 13.25 (125,000)
Cancelled 14.22 (240,000) 13.21 (20,500)
------------------------------------------------------------------------
Outstanding, March 31 $13.29 1,607,500 $14.20 2,072,000
------------------------------------------------------------------------
Exercisable, March 31 $12.02 592,000 $13.75 400,600
------------------------------------------------------------------------
------------------------------------------------------------------------
The following summarizes information about stock options outstanding
at March 31, 2003:
------------------------------------------------------------------------
Weighted
average
remaining Number
contrac- Weighted exercisable Weighted
Number tual average at average
Year outstanding at life exercise March 31, exercise
of grant March 31, 2003 (years) price/share 2003 price/share
------------------------------------------------------------------------
2003 592,000 2 $12.02 592,000 $12.02
2002 80,000 3 $15.90 - -
2001 935,500 2 $14.16 - -
------------------------------------------------------------------------
1,607,500 2 $13.29 592,000 $12.02
------------------------------------------------------------------------
------------------------------------------------------------------------
/T/
Stock options granted during the three months ended March 31,
2003, have remaining contractual lives equivalent to those stock
options exercised during the period.
7. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform
with the current financial statement presentation.
