Paramount Resources Ltd. Announces Results for the Third Quarter Ended September 30, 2003
FOR: PARAMOUNT RESOURCES LTD.
TSX SYMBOL: POU
NOVEMBER 12, 2003 - 21:46 ET
Paramount Resources Ltd. Announces Results for the Third
Quarter Ended September 30, 2003
CALGARY, ALBERTA--
Paramount Resources Ltd. ("Paramount") is pleased to announce its
financial and operating results for the three months ended
September 30, 2003.
/T/
FINANCIAL HIGHLIGHTS (unaudited)
Three Months Nine Months
FINANCIAL Ended September 30 ended September 30
(thousands of
dollars except for % %
per share amounts) 2003 2002 Change 2003 2002 Change
------------------------------------------------------------------------
------------------------------------------------------------------------
Gross Revenue 86,940 116,467 -25% 293,486 335,605 -13%
Cash Flow (1)
From operations 29,071 58,661 -50% 124,119 197,814 -37%
Per share - basic 0.48 0.99 -52% 2.06 3.33 -38%
- diluted 0.47 0.98 -52% 2.05 3.32 -38%
Earnings (loss)
Net earnings (loss) (7,851) 6,180 -227% (8,663) 51,706 -117%
Per share - basic (0.13) 0.10 -230% (0.14) 0.87 -116%
- diluted (0.13) 0.10 -230% (0.14) 0.86 -116%
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Exploration &
development
expenditures 36,185 26,097 39% 139,253 203,149 -31%
------------------------------------------------------------------------
Total Assets 1,180,551 1,654,742 -29%
------------------------------------------------------------------------
Net Debt (2) 298,148 597,752 -50%
------------------------------------------------------------------------
Shareholders'
Equity 495,371 587,504 -16%
------------------------------------------------------------------------
Common shares
outstanding
(thousands)
- September 30 60,169 59,459 1%
- October 31 60,169
------------------------------------------------------------------------
------------------------------------------------------------------------
OPERATING
Production
Natural gas (MMcf/d) 135.8 259.3 -48% 156.8 234.3 -33%
Crude oil and
liquids (Bbl/d) 7,461 7,832 -5% 7,605 4,690 62%
Total Production
(BOE/d)@6:1 30,098 51,049 -41% 33,735 43,740 -23%
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Average Prices
Natural gas
(pre-hedge)($/Mcf) 5.74 3.04 89% 6.25 3.15 98%
Natural gas ($/Mcf) 5.02 3.72 35% 5.10 3.88 31%
Crude oil and
liquids ($/Bbl) 34.21 36.71 -7% 36.18 34.25 6%
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Drilling Activity
Gas 26 2 1200% 122 104 17%
Oil 2 2 - 12 5 140%
Other - - - - 2 -
D & A 2 - - 10 9 11%
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Total Wells 30 4 650% 144 120 20%
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/T/
(1) Cash flow from operations is a non-GAAP term that represents
net earnings adjusted for non-cash items, dry hole, 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.
REVIEW OF OPERATIONS
Kaybob
Drilling, completion and construction activity in the Kaybob area
increased dramatically in the third quarter compared to second
quarter levels. Three drilling rigs and two service rigs have
been kept active for most of the third quarter. Paramount
participated in the drilling of 16 (12.7 net) wells in the third
quarter resulting in 9 (7.3 net) gas wells, 2 (2.0 net) oil wells
and 5 (3.4 net) standing wells. Construction of pipelines and
lease facilities have kept pace with the drilling and completion
rigs; as of November 1, 2003, ten of the wells drilled in the
third quarter have been put on production. Capital spending
increased from $4 million in the second quarter to $21 million in
the third quarter.
Gas volumes averaged 82 MMcf/d in the third quarter. This
marginal increase in production over second quarter (80 MMcf/d)
is the result of gas that was returned to production following
plant maintenance and an increase in drilling and tie in
activities which have added new gas wells to offset property
declines. Current gas production from the Kaybob properties is
approximately 90 MMcf/d. Oil and natural gas liquids production
averaged 2,505 Bbl/d versus 2,111 Bbl/d in the second quarter
2003. This increase in production is due to the return of shut-in
natural gas liquids, optimization at the Kaybob West oil property
and two new oil wells that were drilled in the area.
Construction was completed on Paramount's Kaybob North oil
battery. This will significantly lower oil and condensate
operating costs in the area. This facility provides an attractive
alternative to third-party oil processing in the area, and will
generate additional revenue to Paramount. Partner and regulatory
approvals are being sought to expand the Kaybob North oil battery
to include water disposal and heavy oil blending operations. Sour
gas field compression was added in the Pine Creek area to permit
the production of shut-in sour gas and increase the economic
viability to develop sour gas plays in the area. Construction has
started at the Clover gas plant to add plant inlet compression in
order to be able to handle additional volumes of gas that we plan
to place on production in the fourth quarter.
Initial results from the wells drilled in the third quarter as
part of our down-spacing program are very encouraging. Drilling
activity will continue in the fourth quarter to exploit new gas
reserves in existing gas pools. Paramount expects to have three
drilling rigs active in this area for the remainder of the year,
drilling an additional 17 net wells prior to year end. This
activity is planned for the Pine Creek, Clover and Kaybob North
properties. Operations will resume on two wells that were
suspended in the second quarter due to the early spring break-up
in 2003. Production volumes are now expected to exceed the
year-end exit rate targets of 100 MMcf/d of gas and 2,500 Bbl/d
of oil and natural gas liquids for the Kaybob Core Area.
Grande Prairie
The Sturgeon Lake/Mirage Core Area has been renamed the Grande
Prairie Core Area following the sale of the Sturgeon Lake South
assets, which was effective July 1, 2003, and closed October 1,
2003. The sale of Sturgeon Lake included daily production of
1,700 Bbl/d oil and 3.0 MMcf/d gas, and proven reserves at
January 1, 2003 of 2.7 MMBbl oil and 4.2 Bcf gas, for a total
consideration of $54.3 million. The Sturgeon Lake South property
was our oldest oil property, having been developed in the late
1950's, and also incurred the highest per-unit operating costs of
any Paramount property.
The Grande Prairie area exited the third quarter with production
rates of 15.1 MMcf/d of natural gas and 2,300 Bbl/d of oil and
liquids (before the Sturgeon Lake sale). New drilling and tie ins
before the end of the year are expected to increase natural gas
exit rates for the year considerably despite the sale of the
Sturgeon Lake assets.
In Mirage, the shallow gas development program continued, with 13
(9.5 net) wells drilled during the quarter, nine of which were
successful on initial completion and four are awaiting reworks.
Production is presently at 6 MMcf/d from the program with five
additional wells in the process of being tied in.
At Saddle Hills, Paramount successfully drilled the 4-35 Wabamun
well, which tested at rates in excess of 15 MMcf/d and 300 Bbl/d.
The well is presently being tied in and will commence production
in November 2003. The 6-25 Wabamun location spud November 3, 2003
as planned and should have results available prior to the end of
the year.
At Valhalla, production commenced through the newly constructed
Paramount pipeline system; two wells are planned for the fourth
quarter to take advantage of the new infrastructure.
At Shadow and Goose River, three new wells were placed on
production, opening up new properties, which will be areas of
increased activity into the next drilling season.
Budget planning has commenced for 2004, which will see continued
high growth rates in this area. Already 65 potential locations
have been identified with a projected budget tripling that of
2003.
Northeast British Columbia and Liard, Northwest Territories
All production in this area was adversely affected due to a
14-day turnaround at the Fort Nelson Plant. Net gas production
has been relatively steady and we are exiting the third quarter
at 11 MMcf/d
Paramount has elected to participate in the Chevron Liard 3-K-29
and 2-M-25 wells anticipated to spud early next year. If
successful this will be the fourth Chevron producing well in the
Liard field. The Chevron Liard M-25 well workover was
successfully recompleted for a current net daily production of 10
MMcf/d (0.2 MMcf/d net).
The Clarke Lake c-15-J well was drilled and cased earlier in the
third quarter and is still being evaluated. Paramount is
currently participating in the Clarke Lake Petro-Canada b-57-I
well. If successful, this well could be tied in before year end.
Northwest Alberta / Cameron Hills, Northwest Territories
No new drilling or construction projects were initiated in the
Northwest Alberta Core Area during the third quarter due to
seasonal access constraints. Activities have been focused on
identifying opportunities and preparatory efforts required to
execute those projects during the coming winter season. Some of
the more prominent projects include the drilling and tie in of
four gross wells targeting oil in Cameron Hills, N.W.T., and
follow-up drilling to the Haro gas discovery of the first quarter
of 2003.
Net production for the third quarter averaged 21.5 MMcf/d and 900
Bbl/d . Operational challenges associated with wax have prevented
Paramount from realizing the full oil production capabilities
from Cameron Hills this quarter. A wax blockage in the Cameron
K-74 gathering line is expected to be cleared late in the fourth
quarter of 2003 and will result in an additional 500 Bbl/d of
production.
Southern Alberta / Saskatchewan / Montana / North Dakota
Production in the third quarter of 2003 from the Southern Core
Area averaged 9 MMcf/d and 2,179 Bbls/d reflecting the results of
continued property dispositions started late last year.
Production from the Southern Core Area to date in 2003 has
averaged 9.5 MMcf/d and 2,618 Bbl/d.
Operations during the third quarter were focused in the Alder
Flats, Chain/Craigmyle and Long Coulee areas of Alberta and
Lougheed, Saskatchewan. In Alder Flats, two Mannville gas wells
were tied in and commenced production in September at a gross
rate of 1.0 MMcf/d. In Chain/Craigmyle, four wells were drilled
or recompleted in the Edmonton formation resulting in four new
gas wells, three of which are currently producing with the fourth
waiting on compression. Gas production additions were also made
from the reconfiguration of the Delia 7-15 compressor station to
lower the inlet suction pressure and from the tie in of solution
gas at the Craigmyle 8-35 Battery. In Long Coulee one Mannville
and one Bow Island well were put on production and a successful
recompletion for a second Bow Island gas well was undertaken. In
Lougheed, Saskatchewan several successful recompletions for
increased Midale oil production were undertaken.
The Southern Core Area has completed the process of consolidation
and focus in the third quarter of 2003. This process has seen the
Southern Core Area divest of smaller interest and
non-operated/non-core properties to pursue the growth of fewer,
higher interest core properties.
FINANCIAL
Petroleum and natural gas sales before hedging totaled $96.8
million for the three months ended September 30, 2003, as
compared to $101.6 million for the comparable period in 2002. The
decrease is due to lower production as a result of the
disposition of properties to Paramount Energy Trust in the first
quarter of 2003, offset somewhat by higher natural gas prices as
compared to the third quarter of 2002.
Cash flow from operations for the three months ended September
30, 2003 totaled $29.1 million or $0.47 per diluted common share
as compared to $58.7 million or $0.98 per diluted common share
for the third quarter of 2002. Paramount recorded a net loss for
the current quarter of $7.9 million or $0.13 per diluted common
share as compared to net income of $6.2 million or $0.10 per
diluted common share for the comparable period in 2002. The
decreases in cash flow and net income are due primarily to third
quarter pre-tax commodity hedging losses of $10.4 million and a
bad debt charge of $6 million relating to the bankruptcy of
Mirant Canada Energy Marketing Ltd. as compared to $14.4 million
pre-tax commodity hedging gains in the third quarter of 2002. The
majority of the Company's natural gas hedging contracts expired
at the end of October 2003.
The Company had a natural gas sales contract with Mirant Canada
Energy Marketing Ltd. ("Mirant"), which was assigned to a third
party effective July 1, 2003, prior to the purchaser filing for
bankruptcy protection under the Companies' Creditors Arrangement
Act on July 15, 2003. The Company was owed approximately $8
million for June natural gas sales which has not yet been
received. The $6 million bad debt provision recorded represents
the Company's best estimate of the portion of the receivable
which may not be collected.
U.S. Notes Offering
Paramount Resources Ltd. issued U.S. $175 million of 7 7/8
percent unsecured Senior Notes due 2010 in the United States on
October 27, 2003, and the proceeds from the offering were used to
repay senior bank debt. In addition, Paramount also closed a new
Senior Credit facility with its existing banking syndicate
totalling $203 million on the same day. The combined debt
financing available is now approximately $430 million. At the end
of the third quarter the Company had $272 million of loans drawn
against its credit facility. The subsequent close of the Sturgeon
Lake property sale has reduced this by a further $54.3 million.
OUTLOOK
Paramount has now completed the 18-month process of creating the
Paramount Energy Trust while at the same time maintaining a
significant, albeit lonely, intermediate-sized Canadian
exploration and production company. The Company is now well
financed with a balance sheet positioned to allow it to react to
opportunities which may present themselves; a well defined short
to medium-term growth platform in particular with the
down-spacing program at Kaybob and the inventory of opportunities
for growth in Grande Prairie, and Paramount has established
long-term growth projects at Cameron Hills, Liard, and Colville
Lake, all in the Northwest Territories, as well as significant
opportunities for bitumen development in Northeast Alberta.
Paramount has maintained its long-term perspective on the energy
industry in Canada and looks forward to a period of renewed
growth as it moves forward from this process to unlock
shareholder value.
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 nine months ended September 30, 2003
and the audited consolidated financial statements and MD&A for
the year ended December 31, 2002.
/T/
Wells Drilled 2003 2002
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Gross (1) Net (2) Gross (1) Net (2)
----------------------------------------------
Natural gas 122 84.5 104 80.6
Oil 12 10.5 5 3.9
Other - - 2 1.4
Dry 10 3.2 9 7.3
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Total 144 98.2 120 93.1
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(1) "Gross" wells means the number of wells in which Paramount has a
working interest or a royalty interest that that may be converted to
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 nine months ended September 30, 2003, Paramount participated
in the drilling of 144 gross wells (98.2 net), compared to 120 gross
wells (93.1 net) during the same period in 2002.
CAPITAL EXPENDITURES
Nine Months Ended September 30
----------------------------------------------------------------------
(thousands of dollars) 2003 2002 2001
----------------------------------------------------------------------
Land $ 12,523 $ 5,140 $ 31,507
Geological and geophysical 5,242 8,121 8,907
Drilling 74,993 115,373 99,345
Production equipment and
facilities 46,495 74,515 85,634
----------------------------------------------------------------------
Exploration and development
expenditures 139,253 203,149 225,393
Summit Resources Limited
acquisition (30,005) 437,933 -
Dry hole and seismic costs
expensed (26,224) (12,270) (17,569)
Petroleum and natural gas
property impairment (9,868) (49,136) -
Property acquisitions - 28,595 12,566
Property dispositions (334,709) (2,423) (9,263)
Other 802 1,998 (8,475)
Depletion and depreciation
expense (116,358) (108,327) (46,123)
----------------------------------------------------------------------
Net change in capital assets $ (377,109) $ 499,519 $ 156,529
----------------------------------------------------------------------
----------------------------------------------------------------------
/T/
Capital additions for the third quarter were concentrated in the
Kaybob, Grande Prairie and Southern Alberta areas. For the nine
months ended September 30, 2003, net exploration and development
expenditures totaled $139.3 million.
During the third quarter 2003, Paramount closed several minor
non-core property dispositions for net proceeds of approximately
$9 million. Total proceeds received to date for the minor
non-core property dispositions is approximately $68 million. The
proceeds received from the minor property dispositions have been
applied against the Company's debt facilities.
REVENUE
Natural gas revenue before hedging totaled $267.3 million for the
nine months ended September 30, 2003, as compared to $204.8
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 98 percent in Paramount's year-to-date average pre-hedged
natural gas sales price to $6.25/Mcf as compared to $3.15/Mcf for
the same period in 2002. Natural gas hedging losses for the nine
months ended September 30, 2003 was $49.2 million. The 2003
year-to-date average natural gas price after hedging was
$5.10/Mcf.
For the three months ended September 30, 2003, natural gas
revenue before hedging totaled $71.7 million as compared to $74.6
million for the same period in 2002. The 4 percent reduction in
quarter-over-quarter sales was primarily due to the disposition
of the Northeast Alberta assets to the Trust in March 2003. The
Northeast Alberta assets contributed approximately $28 million of
natural gas revenue in the third quarter of 2002. The decline in
natural gas revenue as a result of the Northeast Alberta assets
disposition was partially offset by the increase in the realized
pre-hedged natural gas sales, which averaged $5.74/Mcf for the
three months ended September 30, 2003 as compared to $3.04/Mcf
for the same period in 2002.
Natural gas sales volumes averaged 156.8 MMcf/d to September 30,
2003, as compared to 234.3 MMcf/d reported for the same period in
2002. Third quarter natural gas sales averaged 135.8 MMcf/d, a 48
percent decrease from 259.3 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 and the minor non-core property dispositions. The
Northeast Alberta assets contributed approximately 99 MMcf/d of
natural gas sales volumes in the third quarter of 2002.
/T/
Revenue Analysis Nine Months Ended September 30
----------------------------------------------------------------------
(thousands of dollars) 2003 2002 2001
----------------------------------------------------------------------
Natural gas and other $ 267,330 $ 204,766 $ 420,300
Crude oil and natural gas
liquids 80,661 44,399 24,217
Commodity hedging gain (loss) (54,745) 45,920 (6,796)
Gain (loss) on sale of
short-term investments (1,020) 40,105 2,982
Other revenue 1,260 415 -
----------------------------------------------------------------------
Gross revenue 293,486 335,605 440,703
Royalties (71,848) (46,287) (87,268)
----------------------------------------------------------------------
Net revenue $ 221,638 $ 289,318 $ 353,435
----------------------------------------------------------------------
----------------------------------------------------------------------
/T/
Oil and natural gas liquids revenue before hedging for the nine
months ended September 30, 2003 increased 82% to $80.7 million as
compared to $44.4 million for the comparable period in 2002. The
increase in oil and natural gas liquids revenue resulted 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 12 percent in Paramount's year-to-date average
pre-hedged oil and natural gas liquids sales price to $38.86/Bbl
as compared to $34.68/Bbl in the same period in 2002. Oil hedging
losses for the nine months ended September 30, 2003 were $5.6
million. The 2003 year-to-date crude oil price after hedging was
$36.18/Bbl.
Oil and natural gas liquids production volumes increased 62
percent to average 7,605 Bbl/d for the nine months ended
September 30, 2003 as compared to 4,690 Bbl/d for the comparable
period in 2002. The increase was attributable to the combined
impact of the acquisition of Summit, which at the time of
acquisition produced approximately 5,000 Bbl/d of oil and natural
gas liquids and the new oil production from Cameron Hills.
Cameron Hills oil production contributed approximately 310 Bbl/d
for the nine months ended September 30, 2003.
For the three months ended September 30, 2003, oil and natural
gas liquids revenue before hedging totaled $25.0 million as
compared to $27.0 million for the same period in 2002. The
average pre-hedged oil and natural gas liquids price received for
the three months ended September 30, 2003 was $36.50/Bbl as
compared to $37.45/Bbl for the same period in 2002.
Oil and natural gas liquids production volumes totaled 7,461
Bbl/d in the third quarter of 2003, as compared to 7,832 Bbl/d
for the comparable quarter of 2002. The 5 percent decrease in oil
and natural gas liquids production was due primarily to minor
non-core property dispositions closed during the year, offset
somewhat by new oil production at Sturgeon Lake and Cameron
Hills.
/T/
Cash Netbacks Per Unit
of Total Production Nine Months Ended September 30
----------------------------------------------------------------------
----------------------------------------------------------------------
($/BOE@6:1) 2003 2002 2001
----------------------------------------------------------------------
Sales price before hedging $ 37.78 $ 20.87 $ 40.60
Less:
Royalties (7.80) (3.88) (7.97)
Operating costs (6.40) (5.24) (3.97)
----------------------------------------------------------------------
Cash netback, before hedging 23.58 11.75 28.66
Commodity hedging gain (loss) (5.94) 3.85 (0.62)
----------------------------------------------------------------------
Cash netback, after hedging $ 17.64 $ 15.60 $ 28.04
----------------------------------------------------------------------
----------------------------------------------------------------------
/T/
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 nine months ended September 30, 2003 averaged
$7.80/BOE or 21 percent of Paramount's average sales price of
$37.78/BOE. This compares to $3.88/BOE or 19 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 period, before hedging losses, as compared to prior
year.
For the three months ended September 30, 2003, royalties totaled
$20.9 million as compared to $20.7 during the same period a year
earlier.
OPERATING COSTS
For the nine months ended September 30, 2003, operating costs
totaled $58.9 million compared to $62.6 million during the same
period a year earlier.
On a unit-of-production basis, average operating costs increased
22 percent to $6.40/BOE from $5.24/BOE in 2002. This increase is
partially attributable to the higher operating costs of our
mature Sturgeon Lake property, averaging $11.13/BOE for nine
months ended September 30, 2003. The operational challenges that
delayed Paramount in achieving full oil production from Cameron
Hills also increased operating costs per unit in the third
quarter of 2003. The cost optimization will be realized in the
fourth quarter once the Cameron K-74 production is brought
on-line. For the three months ended September 30, 2003, operating
costs totaled $21.7 million as compared to $22.1 million for the
same period in 2002.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses totaled $14.1 million for the
nine months ended September 30, 2003, as compared to $10.4
million recorded for the same period a year earlier. On a
unit-of-production basis, 2003 year-to-date general and
administrative expenses increased to $1.53/BOE as compared to
$0.87/BOE for the period ended September 30, 2002. 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.
BAD DEBT
The Company had a natural gas sales contract with Mirant Canada
Energy Marketing Ltd. ("Mirant"), which was assigned to a third
party effective July 1, 2003, prior to Mirant filing for
bankruptcy protection under the Companies' Creditors Arrangement
Act on July 15, 2003. The Company is owed approximately $8
million for June natural gas sales which has not yet been
received. The $6 million bad debt provision recorded represents
the Company's best estimate of the portion of the receivable
which may not be collected.
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 surrender. For
the nine months ended September 30, 2003, $21.0 million in dry
hole costs were recorded, as compared to $4.1 million in the same
period of 2002. Of the dry hole expense recorded in 2003,
approximately $16.7 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 nine months ended September 30, 2003, the Company
recorded a write-down of $9.9 million, representing the remainder
of its petroleum and natural gas assets in California.
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 in the future income tax expense (recovery)
for the nine-month period ended September 30, 2003.
CASH FLOW AND EARNINGS
Cash flow from operations for the nine months ended September 30,
2003 totaled $124.1 million or $2.06 per basic common share
($2.05 per fully diluted common share), representing a 37 percent
decrease from the $197.8 million, or $3.33 per basic common share
($3.32 per fully 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 60.5 million for the nine months ended
September 30, 2003.
Cash flow will continue to be directed towards the Company's
capital expenditure program funding ongoing working capital
requirements.
Net loss for the nine months ended September 30, 2003 totaled
$8.7 million or $0.14 per basic and fully diluted common share,
compared to net earnings of $51.7 million, or $0.87 per basic
common share ($0.86 per fully diluted common share) reported for
the same period a year earlier. The net loss for the nine month
period is primarily the result of a commodity hedging loss of
$54.7 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.
SUBSEQUENT EVENTS
On October 1, 2003, the Company sold its Sturgeon Lake properties
in the Grande Prairie Core Area, including the associated oil
batteries and gas plants, to an unrelated third party for
proceeds of $54.3 million. The carrying value of this property
included in property, plant and equipment was approximately $36
million, resulting in a pre-tax gain on sale of approximately $18
million.
On October 27, 2003, the Company replaced its existing credit
facility with a new $203 million committed
revolving/non-revolving term facility with the same syndicate of
Canadian chartered banks. Borrowings under the facility bear
interest at the bank's prime lending rate, bankers' acceptance or
LIBOR rates plus applicable margins, ranging from 50 to 300 basis
points, dependent on certain conditions. The revolving nature of
the new facility expires on March 31, 2004. The Company may
request an extension on the revolving credit facility of up to
364 days, subject to the approval of the lenders. To the extent
that any lenders participating in the syndicate do not approve an
extension, the amount due to those lenders will convert to a
1-year non-revolving term loan with principal due in full on
March 31, 2005. Advances drawn on the facility are secured by a
first floating charge over all the assets of the Company.
The Company issued U.S. $175 million of 7 7/8 percent Senior
Notes due 2010 on October 27, 2003. Interest on the notes is
payable semi-annually, beginning in 2004. The Company may redeem
some or all of the notes at any time after November 1, 2007 at
redemption prices ranging from 100 percent to 103.938 percent of
the principal amount, plus accrued and unpaid interest to the
redemption date, depending on the year in which the notes are
redeemed. In addition, the Company may redeem up to 35% of the
notes prior to November 1, 2006 at 107.875 percent of the
principal amount, plus accrued interest to the redemption date,
using the proceeds of certain equity offerings. The notes are
unsecured and rank equally with all of the Company's existing and
future unsecured indebtedness.
RECENT ACCOUNTING PRONOUNCEMENTS
Variable Interest Entities
The Canadian Institute of Chartered Accountants ("CICA") recently
issued Accounting Guideline No. 15, Consolidation of Variable
Interest Entities (the "Guideline"). The Guideline requires the
consolidation of entities in which an enterprise absorbs a
majority of the entity's expected losses, receives a majority of
the entity's expected residual returns, or both, as a result of
ownership, contractual or other financial interests in the
entity. Currently, entities are generally consolidated by an
enterprise when it has a controlling financial interest through
ownership of a majority voting interest in the entity. The
Guideline applies to annual and interim periods beginning on or
after November 1, 2004, except for certain disclosure
requirements. Entities should provide disclosures about variable
interest entities in which they hold significant variable
interests for periods beginning on or after January 1, 2004. The
Company does not expect the implementation of this Guideline to
have a material impact on its financial statements.
Asset Retirement Obligation
The Canadian Institute of Chartered Accountants recently issued
section 3110 - Asset Retirement Obligation which addresses
statutory, regulatory, contractual and other legal obligations
associated with the retirement of a tangible long-lived asset
that results from its acquisition, construction, development or
normal operation.
Under Section 3110, asset retirement obligations are initially
measured at fair value at the time the obligation is incurred
with a corresponding amount capitalized as part of the asset's
carrying value and depreciated over the asset's useful life using
a systematic and rational allocation method.
On initial recognition, the fair value of an asset retirement
obligation is determined based upon the expected present value of
future cash flows. In subsequent periods, the carrying amount of
the liability would be adjusted to reflect (a) the passage of
time, and (b) revisions to either the timing or the amount of the
original estimate of undiscounted cash flows.
The change in liability due to the passage of time is measured by
applying an interest method of allocation to the opening
liability and is recognized as an increase in the carrying value
of the liability and an expense. The expense must be recorded as
an operating item in the income statement, not as a component of
interest expense. A change in the liability resulting from
revisions to either the timing or the amount of the original
estimate of undiscounted cash flows is recognized as an increase
or decrease in the carrying amount of the liability with an
offsetting increase or decrease in the carrying amount of the
associated asset.
As of January 1, 2003, the amount to be recorded as the fair
value of the liability was estimated to be $30.2 million.
Stock-Based Compensation and Other Stock-Based Payments
In December 2001, The Canadian Institute of Chartered Accountants
issued Handbook Section 3870, Stock-Based Compensation and Other
Stock-Based Payments, which requires fair value accounting for
all stock-based payments to non-employees, and for employees
awards that are direct awards of stock, or call for settlement in
cash or other assets, and for stock appreciation rights. For all
other employee awards, the present standard allows disclosure of
pro forma net income and pro forma earnings per share in the
income statement. In October 2003, the Canadian Institute of
Chartered Accountants amended Handbook Section 3870 to require
recognition of expense, based on the fair value method, for all
employee stock-based compensation transactions for fiscal years
beginning on or after January 1, 2004.
The Recommendations of the Section should also be applied to the
following awards that are outstanding at the start of the first
fiscal year beginning on or after January 1, 2002 in which date
of adoption of this Section is initially applied:
(a) awards that call for settlement in cash or other assets;
(b) stock appreciation rights that call for settlement by the
issuance of equity instruments; and
(c) any other award that is modified so as to become an award
included in (a) or (b) above. The award should be accounted for
as a new award, and not using modification accounting.
The cumulative amount, applicable to (a) or (b) above, that would
have been recognized in prior years had this Section been
applied, less any amount previously recognized, should be
recognized as the effect of a change in accounting policy and
charged to opening retained earnings for the fiscal year in which
this Section is initially applied, without restatement of prior
periods.
For awards other than those described above, this Section is
adopted for fiscal years beginning on or after January 1, 2004.
We plan to adopt the fair-value method of accounting for stock
options in the fourth quarter of 2003. We plan to apply the
fair-value based method prospectively, whereby compensation cost
will be recognized for all options granted on or after January 1,
2003. This alternative is only available to companies that elect
to adopt the fair-value method of accounting for stock-based
compensation for fiscal years beginning before January 1, 2004.
The impact of adopting the fair-value based method is expected to
be immaterial in 2003.
/T/
PARAMOUNT RESOURCES LTD.
CONSOLIDATED BALANCE SHEETS
September 30 December 31
---------------------------------------------------------------------
(thousands of dollars) 2003 2002
---------------------------------------------------------------------
(unaudited)
ASSETS (note 4)
Current assets
Short-term investments
(market value: $16,592; 2002 - $14,168) $ 16,292 $ 14,168
Accounts receivable 82,915 91,042
Prepaid expenses 14,871 19,213
---------------------------------------------------------------------
114,078 124,423
Property, plant and equipment, net 1,034,852 1,411,961
Goodwill (note 2) 31,621 -
---------------------------------------------------------------------
$ 1,180,551 $ 1,536,384
---------------------------------------------------------------------
---------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 132,503 $ 140,396
Shareholder loan - 33,000
Bank loans (note 4) 272,041 498,097
---------------------------------------------------------------------
404,544 671,493
---------------------------------------------------------------------
Drilling rig indebtedness 1,184 1,443
Mortgage 6,498 6,730
Provision for future site restoration
and abandonment costs 20,097 22,954
Deferred revenue 741 7,804
Future income taxes (note 7) 252,116 279,855
---------------------------------------------------------------------
280,636 318,786
---------------------------------------------------------------------
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 294,861 355,912
---------------------------------------------------------------------
495,371 546,105
---------------------------------------------------------------------
$ 1,180,551 $ 1,536,384
---------------------------------------------------------------------
---------------------------------------------------------------------
See accompanying notes to consolidated financial statements
PARAMOUNT RESOURCES LTD.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS
(unaudited)
Three Months Nine Months
ended September 30 ended September 30
---------------------------------------------------------------------
(thousands of dollars except
for per share amounts) 2003 2002 2003 2002
---------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 96,774 $101,627 $347,991 $249,165
Commodity hedging gain (loss)
(note 5) (10,423) 14,425 (54,745) 45,920
Royalties (net of ARTC) (20,936) (20,687) (71,848) (46,287)
Gain (loss) on sale of
investments - - (1,020) 40,105
Other revenue 589 415 1,260 415
---------------------------------------------------------------------
66,004 95,780 221,638 289,318
---------------------------------------------------------------------
Expenses
Operating 21,738 22,051 58,906 62,593
Surmont compensation - net - 669 - (37,291)
Interest on bank loans 3,017 8,979 14,313 14,216
General and administrative 4,709 4,692 14,066 10,444
Bad debt expense (note 8) 5,977 - 5,977 -
Lease rentals 1,070 1,343 2,547 2,967
Geological and geophysical 1,071 1,238 5,242 8,121
Dry hole costs 1,533 979 20,982 4,149
Loss (gain) on sale of
property and equipment (1,313) (3) 19,481 (133)
Provision for future site
restoration and abandonment
costs 848 618 3,043 1,818
Depletion and depreciation 33,175 47,727 116,358 108,327
Write-down of US petroleum
and natural gas properties - - 9,868 40,000
---------------------------------------------------------------------
71,825 88,293 270,783 215,211
---------------------------------------------------------------------
Earnings (loss) before taxes (5,821) 7,487 (49,145) 74,107
Income and other taxes
Large corporations tax and other 422 (54) 1,710 (1,284)
Future income tax (recovery)
(note 7) 1,608 (1,253) (42,192) (21,117)
---------------------------------------------------------------------
Net earnings (loss) (7,851) 6,180 (8,663) 51,706
Retained earnings,
beginning of period 302,712 391,131 355,912 346,064
Adjustment on disposition of
assets to a related party
(note 3) - - (1,388) -
Dividends (note 3) - - (51,000) -
Adoption of new accounting
policy - - - (459)
---------------------------------------------------------------------
Retained earnings,
end of period $294,861 $397,311 $294,861 $397,311
---------------------------------------------------------------------
---------------------------------------------------------------------
Net earnings (loss) per
common share
-basic $ (0.13) $ 0.10 $ (0.14) $ 0.87
-diluted $ (0.13) $ 0.10 $ (0.14) $ 0.86
---------------------------------------------------------------------
Weighted average number of
common shares outstanding
(thousands)
-basic 60,169 59,459 60,112 59,457
-diluted 60,287 59,616 60,520 59,524
---------------------------------------------------------------------
See accompanying notes to consolidated financial statements
PARAMOUNT RESOURCES LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
Three Months Nine Months
ended September 30 ended September 30
---------------------------------------------------------------------
(thousands of dollars) 2003 2002 2003 2002
---------------------------------------------------------------------
Operating activities
Net earnings (loss) $ (7,851) $ 6,180 $ (8,663) $ 51,706
Add (deduct) non-cash items
Write-down of Surmont assets - - - 9,136
Future income tax (recovery) 1,608 1,253 (42,192) 21,117
Depletion and depreciation 33,175 47,727 116,358 108,327
Write-down of US petroleum
and natural gas properties - - 9,868 40,000
Provision for future site
restoration and abandonment
costs 848 618 3,043 1,818
Loss (gain) on sale of
property and equipment (1,313) (3) 19,481 (133)
Add items not related to
operating activities
Surmont compensation - 669 - (46,427)
Dry hole 1,533 979 20,982 4,149
Geological and geophysical 1,071 1,238 5,242 8,121
---------------------------------------------------------------------
Cash flow from operations 29,071 58,661 124,119 197,814
(Decrease) increase in
deferred revenue (2,223) (11,734) (7,063) 16,091
Change in non-cash operating
working capital (3,900) (56,123) (12,850) 66,598
---------------------------------------------------------------------
22,948 (9,196) 104,206 280,503
---------------------------------------------------------------------
Financing activities
Bank loan - draws - (12,297) 10,000 209,168
Bank loan - repayments (2,849) - (236,056) -
Shareholder loan - 33,000 (33,000) 33,000
Capital stock - (459) 10,317 414
Mortgage (79) - (232) -
Drilling rig indebtedness (88) (3,070) (259) (926)
---------------------------------------------------------------------
(3,016) 17,174 (249,230) 241,656
---------------------------------------------------------------------
Cash flow provided by
(used in) operating and
financing activities 19,932 7,978 (145,024) 522,159
---------------------------------------------------------------------
Investing activities
Property, plant and equipment
expenditures 34,623 25,923 134,070 195,233
Acquisition of Summit
Resources Limited - - - 338,581
Petroleum and natural gas
property acquisitions - 195 - 28,595
Geological and geophysical
costs 1,071 1,238 5,242 8,121
Proceeds on sale of property
and equipment (10,374) (1,374) (271,855) (4,707)
Surmont compensation - 669 - (46,427)
Change in non-cash investing
working capital (5,388) 292 (12,481) 3,503
---------------------------------------------------------------------
Cash flow (provided by) used
in investing activities 19,932 26,943 (145,024) 522,899
---------------------------------------------------------------------
Decrease in cash - (18,965) - (740)
Cash, beginning of period - 18,965 - 740
---------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
---------------------------------------------------------------------
---------------------------------------------------------------------
Income taxes paid $ - $ - $ 5,466 $ 25,000
---------------------------------------------------------------------
Interest paid $ 3,169 $10,205 $13,798 $ 14,006
---------------------------------------------------------------------
See accompanying notes to consolidated financial statements
/T/
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
(all tabular dollar amounts expressed in thousands of dollars)
Paramount Resources Ltd. ("Paramount" or 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 ("GAAP"). Certain information and
disclosures normally required to be included in notes to annual
consolidated financial statements have 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, except as noted below:
Goodwill
Goodwill, which represents the excess of purchase price over fair
value of net assets acquired, is not amortized and is assessed by
the Company for impairment at least annually. Impairment is
assessed based on a comparison of the fair value of the net
assets acquired to the carrying value of the net assets,
including goodwill. Any excess of carrying value over and above
fair value is the impairment amount, and is charged to earnings
in the period identified.
2. ACQUISITION OF SUMMIT RESOURCES LIMITED
On May 12, 2002, Paramount and Summit Resources Limited
("Summit") jointly announced that they had entered into an
agreement pursuant to which Paramount made an offer to purchase
all of the issued and outstanding common shares of Summit for
cash consideration of $7.40 per share or approximately $249.6
million, including acquisition costs. This transaction has been
accounted for using the purchase method and is being accounted
for as of the date of substantial completion of the acquisition
of June 28, 2002.
The Company has finalized the purchase price equation for this
acquisition. The following table summarizes the fair value of the
assets acquired and liabilities assumed at the date of
acquisition:
/T/
-----------------------------------------------------------
Assets
Accounts receivable $ 13,997
Petroleum and natural gas properties 419,642
Goodwill 31,621
-----------------------------------------------------------
465,260
-----------------------------------------------------------
Liabilities
Accounts payable 21,946
Future income taxes 108,373
Debt 74,513
Other liabilities 10,866
-----------------------------------------------------------
215,698
-----------------------------------------------------------
Net assets acquired $ 249,562
-----------------------------------------------------------
-----------------------------------------------------------
/T/
3. DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST
During the first quarter of 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, 2003, Paramount declared a dividend-in-kind of
$51 million, consisting of an aggregate of 9,907,767 units of the
Trust. The dividend was paid to shareholders of Paramount's
common shares of record on the close of business on February 11,
2003.
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.
As the transfer of the Initial Assets and the Additional Assets
(collectively the "Trust Assets") represented a related party
transaction not in the normal course of operations involving two
companies under common control, the transaction has been
accounted for at the net book value of the Trust Assets as
recorded in Paramount. 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 LOAN
In 2002, the Company negotiated a $600 million credit facility
with a syndicate of Canadian chartered banks for general
corporate use and to fund the Summit acquisition. The credit
facility consisted of a $466 million production facility, a $109
million bridge facility and a $25 million working capital
facility. The available borrowings were reduced to a total of
$304.2 million as at September 30, 2003, reflecting the
dispositions of the Trust and other minor non-core properties.
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 62.5 to 162.5 basis points.
In October, the Company negotiated a new committed term facility
with the same syndicate of Canadian chartered banks (see note 9).
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
As at September 30, 2003, the Company has entered into financial
forward hedging arrangements as follows:
/T/
Price Term
---------------------------------------------------------------------
AECO
Sell 10,000 GJ/d $ 5.46 November 2002 - October 2003
Sell 20,000 GJ/d $ 5.06 November 2002 - October 2003
Sell 20,000 GJ/d $ 5.25 November 2002 - October 2003
Sell 15,000 GJ/d $ 7.55 November 2003 - March 2004
NYMEX
Sell 20 MMcf/d U.S. $3.83 November 2002 - October 2003
Sell 20 MMcf/d U.S. $3.90 November 2002 - October 2003
Sell 10 MMcf/d U.S. $4.10 November 2002 - October 2003
Buy 10 MMcf/d U.S. $4.94 August 2003 - October 2003
Buy 10 MMcf/d U.S. $4.99 August 2003 - October 2003
WTI
Sell 1,000 bbl/d U.S. $24.07 May 2002 - April 2004
Sell 1,000 bbl/d U.S. $24.33 January 2003 - December 2003
/T/
Had these financial contracts been settled on September 30, 2003,
using prices in effect at that time, the mark-to-market before
tax gain would have totaled $0.1 million.
Subsequent to September 30, 2003, the Company entered into
financial agreements as follows:
/T/
Price Term
---------------------------------------------------------------------
AECO
Sell 15,000 GJ/d $6.42 November 2003 - March 2004
Sell 20,000 GJ/d $5.50-$7.80
(collar) November 2003 - March 2004
WTI
Sell 1,000 bbl/d U.S. $25.00-$30.25
(collar) January 2004 - December 2004
/T/
(b) Foreign exchange hedges
Foreign currency index swap transactions entered into by the
Company are unchanged from those outstanding at December 31,
2002. At September 30, 2003, the estimated fair value of these
hedges based on the Company's assessment of available market
information was a gain of $2.4 million.
(C) Fair values of financial assets and liabilities
Borrowings under bank credit facilities are for short periods and
are market rate based; thus, carrying values approximate fair
values. 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,
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
Common share transactions for the respective periods are as
follows:
/T/
-----------------------------------------------------------------------
Nine months ended Year Ended
September 30, 2003 December 31, 2002
-----------------------------------------------------------------------
Common Common
Shares Amount Shares Amount
-----------------------------------------------------------------------
Balance, beginning
of year 59,458,600 $ 190,193 59,453,600 $ 189,320
Stock options
exercised for shares
during the period 710,000 10,317 5,000 72
Expense recognized in
respect of stock-based
compensation during
the period - - - 801
-----------------------------------------------------------------------
Balance, end
of period 60,168,600 $ 200,510 59,458,600 $ 190,193
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
(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, may request to receive
either a cash payment equal to the difference between the
exercise price and the market price of the Company's common
shares or common shares issued from Treasury. Irrespective of the
participant's request, the Company may choose, and has a history
of doing so, to only issue common shares. 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.
The recognized expenses in respect of the SARP for the three and
nine month periods ended September 30, 2003 were $nil (September
30, 2002 - $113,000 and $342,000 respectively). As the remaining
outstanding share appreciation rights were cancelled on February
6, 2003, no further expenses will be recorded in respect of the
share appreciation rights plan.
The Company accounts for its employee stock options using the
intrinsic 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 (loss) and net earnings (loss) per share would have been
adjusted to the pro forma amounts indicated below:
/T/
-----------------------------------------------------------------------
Three months Nine months
ended ended
September 30 September 30
-----------------------------------------------------------------------
2003 2002 2003 2002
-----------------------------------------------------------------------
Net earnings
(loss) as reported (7,851) 6,180 (8,663) 51,706
pro forma (8,206) 6,159 (9,394) 51,669
Net earnings
(loss) per common as reported (0.13) 0.10 (0.14) 0.87
share - basic pro forma (0.14) 0.10 (0.16) 0.87
Net earnings
(loss) per common as reported (0.13) 0.10 (0.14) 0.86
share - diluted pro forma (0.14) 0.10 (0.16) 0.86
-----------------------------------------------------------------------
/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 zero 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.
During the nine months ended September 30, 2003, the Company
issued 1,603,500 stock options at exercise prices ranging from
$9.00 to $10.01 per option. Also during the period, 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 $9.07 per option, respectively. The
following table summarizes information about stock options
outstanding at September 30, 2003:
/T/
----------------------------------------------------------------------
Exercise Number Weighted average Number
price range outstanding remaining exercisable
($/share) at September contractual at September
30, 2003 life (years) 30, 2003
----------------------------------------------------------------------
$ 9.00 1,417,500 4 69,000
$ 9.35 - 10.01 148,000 4 -
$ 9.07 271,000 3 -
$10.22 643,500 2 37,500
$12.02 571,000 2 571,000
----------------------------------------------------------------------
$ 9.67 3,051,000 3 677,500
----------------------------------------------------------------------
/T/
7. INCOME TAXES
In May 2003, the Government of Alberta introduced legislation to
reduce its corporate income tax rate by 0.5% effective April 1,
2003. In June 2003, the Canadian federal government introduced
legislation to change the taxation of resource income. The
legislation reduces the corporate income tax rate on resource
income from 28% to 21% over five years beginning January 1, 2003.
Over the same period, the deduction for resource allowance is
phased out and a deduction of actual crown royalties paid is
phased in. 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 in the future
income tax expense (recovery) for the nine month period ended
September 30, 2003.
8. BAD DEBT
The Company had a natural gas sales contract with Mirant Canada
Energy Marketing Ltd. ("Mirant"), which was assigned to a third
party effective July 1, 2003, prior to Mirant filing for
bankruptcy protection under the Companies' Creditors Arrangement
Act on July 15, 2003. The Company is owed approximately $8
million for June natural gas sales which has not yet been
received. The $6 million bad debt provision recorded represents
the Company's best estimate of the portion of the receivable
which may not be collected.
9. SUBSEQUENT EVENTS
(a) On October 1, 2003, the Company sold its Sturgeon Lake
properties in the Grande Prairie core area, including the
associated oil batteries and gas plants, to an unrelated third
party for proceeds of $54.3 million. The carrying value of this
property included in property, plant and equipment was
approximately $36 million, resulting in a pre-tax gain on sale of
approximately $18 million.
(b) On October 27, 2003, the Company replaced its existing credit
facility (described in note 4) with a new $203 million committed
revolving/non-revolving term facility with the same syndicate of
Canadian chartered banks. Borrowings under the facility bear
interest at the bank's prime lending rate, bankers' acceptance or
LIBOR rates plus applicable margins, ranging from 50 to 300 basis
points, dependent on certain conditions. The revolving nature of
the new facility expires on March 31, 2004. The Company may
request an extension on the revolving credit facility of up to
364 days, subject to the approval of the lenders. To the extent
that any lenders participating in the syndicate do not approve an
extension, the amount due to those lenders will convert to a
one-year non-revolving term loan with principal due in full on
March 31, 2005. Advances drawn on the facility are secured by a
first floating charge over all the assets of the Company.
(c) The Company issued U.S. $175 million of 7 7/8 percent Senior
Notes due 2010 on October 27, 2003. Interest on the notes is
payable semi-annually, beginning in 2004. The Company may redeem
some or all of the notes at any time after November 1, 2007 at
redemption prices ranging from 100 percent to 103.938 percent of
the principal amount, plus accrued and unpaid interest to the
redemption date, depending on the year in which the notes are
redeemed. In addition, the Company may redeem up to 35 percent of
the notes prior to November 1, 2006 at 107.875 percent of the
principal amount, plus accrued interest to the redemption date,
using the proceeds of certain equity offerings. The notes are
unsecured and rank equally with all of the Company's existing and
future unsecured indebtedness.
For further information: Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Operating Officer, (403) 290-3600 / Paramount Resources Ltd., B.K. (Bernie) Lee, Chief Financial Officer, (403) 290-3600, (403) 262-7994 (FAX), www.paramountres.com, Paramount Resources Ltd., C.H. (Clay) Riddell, Chairman and Chief Executive Officer, (403) 290-3600, (403) 262-7994 (FAX)
