FOR: PARAMOUNT RESOURCES LTD.
TSX SYMBOL: POU
MARCH 19, 2003 - 19:13 EST
Paramount Resources Ltd. Financial And Operating Results
For The Year Ended December 31, 2002
CALGARY, ALBERTA--Paramount Resources Ltd. ("Paramount") is
pleased to announce its financial and operating results for the
year ended December 31, 2002.
/T/
PARAMOUNT RESOURCES LTD
Highlights
FINANCIAL Three Months Ended Year Ended
($ thousands December 31 December 31
except per share 2002 2001 % 2002 2001 %
amounts) Change Change
--------------------------------------------------------------------
Gross Revenue 138,337 87,670 58% 473,942 528,373 -10%
Cash Flow
From operations 62,102 47,732 30% 259,916 303,937 -14%
Per share -basic 1.04 0.80 30% 4.37 5.11 -14%
-diluted 1.04 0.80 30% 4.36 5.11 -15%
Earnings (loss)
Net earnings
(loss) (41,399) (10,433) 297% 10,307 118,902 -91%
Per share -basic (0.70) (0.18) 289% 0.17 2.00 -92%
-diluted (0.70) (0.18) 289% 0.16 2.00 -92%
Capital Expenditures
Exploration and
development 14,047 46,930 -70% 217,196 272,323 -20%
Summit
acquisition 11,715 - - 449,648 - -
Other (108,400) 12,185 -990% (145,580) (11,139) 1207%
Net capital
expenditures (82,638) 59,115 -240% 521,264 261,184 100%
Total Assets 1,536,384 1,176,323 31% 1,536,384 1,176,323 31%
Net Debt 555,243 290,698 91% 555,243 290,698 91%
Shareholders'
Equity 546,105 535,384 2% 546,105 535,384 2%
Weighted Average
Common Shares
Outstanding 59,459 59,453 59,458 59,453
Common shares
outstanding at
Year-end (000's) 59,459 59,453 0% 59,459 59,453 0%
Common shares
outstanding
at February 28,
2003 (000's) 60,169 60,169
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OPERATING
Production
Natural gas
(MMcf/d) 262.6 218.2 20% 241.4 225.0 7%
Crude oil and
liquids (Bbl/d) 8,552 2,002 327% 5,663 2,165 162%
Total Production
(MMcfeq/d)@ 10:1 348.2 238.4 46% 298.0 246.7 21%
Total Production
(BOE/d) @ 6:1 52,326 38,365 36% 45,898 39,665 16%
Average Prices
Natural gas
(pre-hedge)($/Mcf) 4.54 3.03 50% 3.53 5.93 -40%
Natural gas
($/Mcf) 4.60 4.17 10% 4.08 6.12 -33%
Crude oil and
liquids ($/Bbl) 35.27 27.81 27% 34.64 35.48 -2%
Reserves (proved
and probable)
Natural gas (Bcf)
Proven 446.5 437.7 2%
Proven and
probable 618.6 563.7 10%
Crude Oil and
liquids (MBbl)
Proven 17,545 6,339 177%
Proven and
probable 22,845 7,967 187%
Estimated present
worth value
before
tax discounted @
10%
Proven ($mm) 983 696 41%
Proven and
probable ($mm) 1,258 870 45%
Drilling Activity
(gross)
Gas 10 31 -68% 114 167 -32%
Oil 4 4 - 9 12 -
Other (1) - - 1 1 -
D&A 2 (1) - 11 16 -31%
Total wells 15 34 -56% 135 196 -31%
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Success rate 87% 100% -13% 92% 92% 0%
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(1) Throughout this report, unless otherwise stated, crude oil and
liquids volumes have been converted to natural gas (Mcfeq) on
the basis that one barrel of oil equals 10 Mcf of gas
/T/
SIGNIFICANT EVENTS
- Acquisition of Summit Resources Limited
On June 28, 2002, Paramount closed the acquisition of Summit
Resources Limited ("Summit") for cash consideration of $251.4
million and assumed net debt of $87.0 million. The acquisition
diversified the Company's production base and consolidated
certain working interests in Central Alberta which the Company
believes to be highly prospective.
- Creation of an Independent Energy Trust
In conjunction with Paramount's acquisition of Summit, the
Company announced its intention to create an independent Energy
Trust (the "Trust"), providing shareholders an investment which
would complement Paramount's traditional exploration and
development strategy.
During the first quarter 2003, all necessary regulatory
clearances with respect to the Canadian prospectus and the U.S.
Registration Statement were received. Paramount subsequently
transferred a portion of its Northeast Alberta assets to the
Trust and issued a $51 million dividend in kind of Trust Units
received from the Trust to its shareholders. On March 11, 2003,
the Trust closed a rights offering, the proceeds of which
partially capitalized the Trust and allowed it to purchase from
Paramount additional assets in Northeast Alberta.
- Settlement of Bitumen/Natural Gas Co-Production Issue
On June 27, 2002, Paramount received compensation of $47.1
million in settlement for the Surmont shut-in order of May 1,
2000.
- Sale of Remaining Investment in Peyto Exploration and
Development Corp.
Paramount monetized its remaining investment in Peyto Exploration
and Development Corp. to realize cash proceeds of $45.0 million
in 2002 for a net gain of $40.1 million.
FINANCIALS
The financial and operating results at December 31, 2002 reflect
the acquisition of Summit Resources Limited effective June 28,
2002.
Petroleum and natural gas revenue totaled $473.9 million for the
year ended December 31, 2002, as compared to $528.4 million
reported for the corresponding period in 2001. Included in
petroleum and natural gas sales are $46.8 million of commodity
hedging gains attributable to petroleum and natural gas hedges in
place during 2002.
For the three months ended December 31, 2002, petroleum and
natural gas revenue totaled $138.3 million, up 58 percent from
$87.7 million for the same period in 2001. Compared to the third
quarter, quarterly revenue increased 19 percent from $116.5
million; a direct result of increased commodity prices. The
fourth quarter hedging gain totaled $0.9 million.
Cash flow from operations totaled $259.9 million or $4.37 per
common share, representing a 14 percent decrease from the $303.9
million, or $5.11 per common share, reported for 2001. Cash flow
during the fourth quarter amounted to $62.1 million or $1.04 per
common share, 30 percent higher than the $47.7 million or $0.80
per common share reported for the same period in 2001.
Net income for the year ended December 31, 2002, decreased 91
percent to $10.3 million or $0.17 per common share compared to
$118.9 million or $2.00 per common share reported for the same
period a year earlier. Net income includes a fourth quarter loss
of $41.4 million or $0.70 per common share as compared to a loss
of $10.4 million or $0.18 per common share in 2001.
Extraordinary to earnings in 2002 was a charge of $66 million for
exploratory dry hole costs associated with petroleum and natural
gas assets in California and Wyoming; $49.4 million of negative
revisions to the book value of undeveloped unproved exploratory
leases which the Company has determined will not be developed and
a $31.2 million write-down resulting from the impairment of
certain producing non-core oil and natural gas assets.
OPERATIONS
Daily production increased 16 percent during 2002 to 45,898 BOE/D
on a 6:1 basis as compared to average production of 39,665 BOE/D
in 2001. Natural gas production averaged 241.4 MMcf/d compared
to 225 MMcf/d in 2001. Crude oil and natural gas liquids
production averaged 5,663 Bbl/d in 2002 as compared to 2,165
Bbl/d in 2001, a 162 percent increase.
Capital expenditures related to exploration and development
totaled $217.2 million in 2002, including $124.1 million for
exploration and development drilling; $77.4 million for
production equipment and facilities; $9.3 million for geological
and geophysical expenditures and $6.4 million for land. Property
acquisitions net of dispositions totaled $23.6 million. A total
of 135 gross wells (99.4 net) were drilled resulting in 114
natural gas wells (83.7 net), 9 oil wells (6.7 net), 11 dry and
abandoned wells (8.0 net) and 1 service well (1.0 net).
Southern Alberta / Saskatchewan / Montana / North Dakota
Production through the fourth quarter from the Southern Operating
Unit averaged 10.4 MMcf/d and 3,010 Bbl/d. New production
additions came from the tie-in of two Mannville natural gas wells
at Retlaw, Alberta in mid December. Initial combined rates from
these wells totaled 1.6 MMcf/d. Paramount also participated in
two new wells in the Chain area of Alberta, both of which tested
gas in the Mannville. One well was tied-in and producing in
December; the second will be tied-in in the first quarter of
2003. At Blaine County, Montana, Paramount also participated in
a Bowes oil well. The well was completed and tested oil from the
Firemoon formation. Additional completion work is contemplated
for the second quarter of 2003.
The Southern Operating Unit began a process of consolidation in
the fourth quarter of 2002. This process will see the Southern
Operating Unit divest of smaller working interests and
non-operated / non-core properties, providing an opportunity for
the Company to pursue growth in core areas with higher working
interests. This process, which will carry over to the first
quarter of 2003, will reduce the number of individual properties
from 75 to 7 or 8 core properties.
Kaybob, Alberta
Fourth-quarter production in the Kaybob Operating Unit averaged
93 MMcf/d of natural gas and 2,460 Bbl/d of crude oil and natural
gas liquids. Average daily production for the year totaled 87.5
MMcf/d of natural gas and 2,290 Bbl/d of crude oil and natural
gas liquids. Drilling activity within the fourth quarter was
modest with 5 (2.67 net) wells drilled and rig released. A total
of 38 (29.01 net) wells were drilled in the year.
Fourth-quarter drilling activity focused on developing a summer
access area around Kaybob and included the farming out of a
portion of Paramount's working interest. Drilling targets
included all formations from Viking to Swanhills, resulting in
1.43 net gas wells, 0.49 net oil wells and 1.05 net D&A wells. A
number of workovers and recompletions of low rate producers and
suspended wells contributed to production increases in the
operating area.
Sturgeon Lake / Grande Prairie, Alberta
During the fourth quarter, production averaged 11.3 MMcf/d of
natural gas and 2,225 Bbl/d of crude oil and natural gas liquids.
One (0.25 net) well was drilled and 5 (4.5 net) recompleted
resulting in initial production increase of 1.5 MMcf/d and 75
Bbl/d. Activity during the first quarter of 2003 will include the
drilling of 6 (3.6 net) wells and the recompletion of an
additional 6 (5.7 net) others . Average production rates during
the first quarter 2003 are forecast to approximate 11 MMcf/d of
natural gas and 2,220 Bbl/d of crude oil and natural gas liquids.
Presently, Paramount has plans to tie in 6 wells by early summer.
Northwest Alberta
In Northwest Alberta and Cameron Hills, NWT, Paramount
participated in the drilling of 49 (38.6 net) wells in calendar
year 2002. The vast majority of field activities relating to
seismic acquisition, drilling, and construction occurred in the
first quarter due to the seasonal access of the area. Natural gas
sales averaged 30.4 MMcf/d in 2002. The highlight of 2002 was the
tie-in of 6 natural gas wells located in Cameron Hills, NWT to
processing facilities situated at Bistcho Lake in Northwest
Alberta. Paramount operates and owns 60 percent of the 50 MMcf/d
Bistcho Lake natural gas processing facility.
Paramount will be participating in 21 (19.2 net) wells in the
Northwest Alberta region in the first quarter of 2003. In
addition, Paramount anticipates bringing 5 oil wells on
production in Cameron Hills. The oil will flow from Cameron
through existing pipe to the Bistcho Lake facility and then on to
Zama Lake and into the Rainbow pipeline system through a newly
constructed line.
Liard, Northwest Territories / Northeast British Columbia
The Liard Basin continues to be an active exploration area for
Paramount. As a result of the 3D seismic programs shot last year,
the 2002/2003 winter drilling program is focused primarily on
deep Devonian play concepts. Along the Liard fault trend,
Paramount has an interest in 2-3 non-operated Devonian tests. Two
of these locations are targeting potential new pools while the
third is a delineation well located at the north end of the
Chevron Liard Nahanni pool. At Arrowhead, along the Bovie fault
trend, a farmout agreement with Anadarko includes the drilling of
4 Devonian tests as well as 3 shallower Chinkeh locations.
Paramount also plans to drill 1 Mattson location northeast of the
town of Fort Liard.
Average production from the Northeast, British Columbia/Northwest
Territories core area increased by 32 percent from 2001 to 2002
mainly due to the addition of the Clarke Lake property as part of
the Summit acquisition and the tie-in of two wells in the
Maxhamish area, a-96-J and b-43-K, in the first quarter of 2002.
Reserves also increased by 55 percent primarily due to the
acquisition of Clarke Lake.
A Maxhamish well, b-83-K, will be tied-in during the first
quarter of 2003 and the existing production and reserve recovery
will continue to be optimized by installing booster compression
and liquid lifting systems.
RESERVES
Paramount's year-end reserve balance for proved plus probable
reserves increased 24 percent to 125 million BOE at January 1,
2003 as compared to 102 million BOE at January 1, 2002. This
increased reserve balance equates to Paramount replacing its
production in 2002 by 243 percent.
On a proved plus probable basis natural gas reserves increased 10
percent to 618.6 Bcf. Crude oil reserves increased 267 percent to
18.2 million barrels; and natural gas liquids reserves increased
from 3.0 million barrels to 4.6 million barrels, a 53 percent
increase. The acquisition of Summit Resources Limited increased
reserves by 91Bcf of natural gas and 11.9 million barrels of
crude oil and natural gas liquids; exploration and development
expenditures increased reserves by 39 Bcf and 1.4 million
barrels; additional acquisitions added 2.65 million BOE and total
net positive revisions added an additional 3.2 million BOE.
Proved reserves increased 16 percent from 79.3 million BOE to 92
million BOE. This included a reduction of 6.5 million BOE from
the proved category for natural gas reserves shut-in at Surmont.
The transfer of the Northeast Alberta properties to Paramount
Energy Trust will subsequently reduce Paramount's proved natural
gas reserves by 164 Bcf and proved plus probable reserves by
203.6 Bcf..
OUTLOOK
Paramount looks forward to 2003 as commodity prices continue to
rise just in time to meet the incremental production gains from
our winter program. The Company estimates that it will produce
approximately 38,500 BOE/d on a 6:1 basis. Capital expenditures
will approximate $150 - $200 million while cash flow will
approximate $250 million or $4.20 per common share. Cash flow in
excess of the Company's capital expenditure program will be
utilized to reduce bank indebtedness.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Paramount is pleased to report its financial and operating
results for the year ended December 31, 2002.
The following discussion of financial position and results of
operations should be read in conjunction with the Consolidated
Financial Statements and Notes thereto. It offers Management's
analysis of Paramount's historical financial and operating
results and provides estimates of Paramount's future financial
and operating performance based on information currently
available. Actual results will vary from estimates and the
variances may be significant.
Paramount Resources Ltd. ("Paramount" or the "Company") is an
exploration, development and production company with established
operations in Alberta, British Columbia, Saskatchewan, the
Northwest Territories, Montana, North Dakota and California. The
Company has patiently executed its corporate growth strategy,
focusing on natural gas as a commodity, and high impact
exploration as the cornerstone to future success. Management's
vision continues to be based on the long-term fundamentals for
oil and natural gas in North America. During 2002, Paramount
continued to focus its efforts on building a strong asset base
through exploration and development, and the acquisition of
Summit Resources Limited.
Significant Events
- Acquisition of Summit Resources Limited
On June 28, 2002, Paramount closed the acquisition of Summit
Resources Limited ("Summit") for cash consideration of $251.4
million and assumed net debt of $87.0 million. The acquisition
diversified the Company's production base and consolidated
certain working interests in Central Alberta which the Company
believes are highly prospective.
- Creation of an Independent Energy Trust
In conjunction with Paramount's acquisition of Summit, the
Company announced its intention to create an independent Energy
Trust (the "Trust"), providing shareholders an investment which
would complement Paramount's traditional exploration and
development strategy.
During the first quarter 2003, all necessary regulatory
clearances with respect to the Canadian prospectus and a U.S.
Registration Statement were received. Paramount subsequently
transferred a portion of its Northeast Alberta assets to the
Trust and issued a $51 million dividend in kind of Trust Units
received from the Trust to its shareholders. On March 11, 2003,
the Trust closed a rights offering, the proceeds of which
partially capitalized the Trust and allowed it to purchase from
Paramount additional assets in Northeast Alberta.
- Settlement of Bitumen/Natural Gas Co-Production Issue
On June 27, 2002, Paramount received compensation of $47.1
million in settlement for the Surmont shut-in order of May 1,
2000.
- Sale of Remaining Investment in Peyto Exploration and
Development Corp.
Paramount monetized its remaining investment in Peyto Exploration
and Development Corp. to realize cash proceeds of $45.0 million
in 2002 for a net gain of $40.1 million.
Highlights
- Cash flow totaled $259.9 million or $4.37 per share.
- Natural gas sales averaged 241 MMcf/d; crude oil and natural
gas liquids production averaged 5,663 Bbl/d.
Accounting Policy
Paramount follows the "successful efforts" method of accounting
for its petroleum and natural gas operations. This method, unlike
the alternative "full cost" accounting method, usually generates
a more conservative value for net earnings as exploration
expenditures, including exploratory dry hole costs, geological
and geophysical costs, lease rentals on undeveloped properties as
well as the cost of surrendered leases and abandoned wells are
expensed rather than capitalized in the year incurred. However,
to make reported cash flow results comparable to industry
practice, Paramount reclassifies geological and geophysical costs
as well as surrendered leases and abandonment costs from
operating to investing activities.
Revenue
/T/
--------------------------------------------------------------------- Production Revenue (thousands of dollars) 2002 2001 2000 --------------------------------------------------------------------- Natural gas $ 311,438 $ 481,436 $ 375,746 Crude oil and natural gas liquids 72,750 28,442 21,676 Commodity hedging gain (loss) 46,813 15,808 (5,952) Gain on sale of short-term investments 40,830 2,982 - Other 2,111 (295) - --------------------------------------------------------------------- Gross revenue $ 473,942 $ 528,373 $ 391,470 ---------------------------------------------------------------------
/T/
Paramount's financial success is contingent upon the growth of
reserves and production volumes and the economic environment that
creates a demand for natural gas and crude oil. Such growth is a
function of the amount of cash flow that can be generated and
reinvested into a successful capital expenditure program. To
protect cash flow against commodity price volatility, the Company
will, from time to time, manage cash flow by utilizing commodity
price hedges. The hedging program is generally for periods of
less than one year and restricted to a maximum of 50 percent of
Paramount's current production volumes.
Petroleum and natural gas revenue totaled $431.0 million in 2002,
as compared to $525.7 million in 2001 (2000 - $391.5 million).
The decrease in revenue results from lower commodity prices
received during the year. Weaker natural gas demand resulted in a
decrease of 33% in Paramount's average natural gas sales price to
$4.08/Mcf as compared to $6.12/Mcf in 2001 (2000 - $4.59/Mcf).
Included in petroleum and natural gas sales are $46.8 million of
commodity hedging gains attributed primarily to natural gas
hedges. On a per unit basis the 2002 price includes approximately
$0.55/Mcf profit from natural gas commodity hedges that were in
place during the year. Natural gas sales volumes averaged 241
MMcf/d in 2002 as compared to 225 MMcf/d in 2001 (2000 - 220
MMcf/d). The increase in natural gas sales volumes is attributed
to the acquisition of Summit effective June 28, 2002, which added
approximately 50 MMcf/d of natural gas production.
Oil and natural gas liquids averaged $34.64/Bbl, as compared to
$35.48/Bbl in 2001 (2000 - $37.80/Bbl). Oil and natural gas
liquids production increased 162 percent to average 5,663 Bbl/d
in 2002 as compared to 2,165 Bbl/d in 2001 (2000 - 1,571 Bbl/d).
This increase is attributable to the acquisition of Summit which
at the time of acquisition produced approximately 5,000 Bbl/d of
oil and natural gas liquids.
Paramount's 2002 production profile continues to be significantly
weighted to natural gas but the Company has increased its oil and
natural gas liquids production with the Summit acquisition. In
2002 natural gas revenue contributed 83 percent of Paramount's
total petroleum and natural gas revenue compared to 95 percent in
2001.
Fourth quarter petroleum and natural gas revenue totaled $135.5
million as compared to $87.7 million for the comparable quarter
in 2001. The increase in sales resulted from an increase in
production volumes associated with the acquisition of Summit, as
well as an increase in natural gas prices, which averaged
$4.60/Mcf during the quarter as compared to $4.17/Mcf for the
comparable quarter in 2001. Natural gas sales averaged 263 MMcf/d
for the fourth quarter of 2002 compared to 218 MMcf/d for the
comparable quarter in 2001. Oil and natural gas liquids sales
averaged 8,552 Bbl/d in the fourth quarter of 2002 as compared to
2,002 Bbl/d for the comparable quarter in 2001.
At December 31, 2002, Paramount had the following natural gas
commodity price hedges in place representing approximately 40
percent of Paramount's average 2002 production:
/T/
Volume
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AECO Price Term
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10,000 GJ/d $5.46 November 2002 - October 2003
20,000 GJ/d $5.06 November 2002 - October 2003
20,000 GJ/d $5.25 November 2002 - October 2003
NYMEX
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20 MMcf/d US$3.83 November 2002 - October 2003
20 MMcf/d US$3.90 November 2002 - October 2003
10 MMcf/d US$4.10 November 2002 - October 2003
WTI
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1,000 Bbl/d US$24.07 May 2002 - April 2004
1,000 Bbl/d US$24.33 January 2003 - December 2003
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/T/
The unrealized loss on these financial hedges at December 31,
2002 totaled $28.7 million.
The Company also has in place foreign exchange hedges, which have
fixed the exchange rate on U.S. $40.9 million for CDN $58.6
million over the next three years at CDN $1.4322. For the year
ended December 31, 2002, gross revenue included losses from
foreign currency hedging activity of $3.4 million (2001 - $1.7
million).
During 2002, approximately 43 percent of Paramount's natural gas
sales were under long-term contracts to gas aggregators and
direct-sales purchasers as compared to 42 percent and 46 percent
for 2001 and 2000, respectively.
/T/
Natural Gas Sales per Market Group
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2002 2001 2000
Long-term contracts Bcf % Bcf % Bcf %
Aggregators
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Mirant Midwestern US, 14.7 16.6 17.4 21.2 19.6 24.3
Pacific Northwest
US, California
and Quebec
Progas Northeastern US 9.6 10.9 8.1 9.9 7.2 8.9
Canstates/Temco Northeastern US 1.5 1.7 1.9 2.2 3.2 4.0
TransCanada Eastern Canada 0.4 0.5 2.7 3.3 1.2 1.5
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Subtotal - aggregators 26.2 29.7 30.1 36.6 31.2 38.7
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Direct sales
Nexen Midwestern US 2.9 3.3 - - - -
Selkirk Northeastern US 6.0 6.8 4.5 5.5 6.0 7.4
West Windsor Eastern Canada 0.6 0.7 - - - -
BC Gas British Columbia 0.6 0.7 - - - -
Duke AECO 1.4 1.6 - - - -
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Subtotal -
direct sales 11.5 13.1 4.5 5.5 6.0 7.4
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Subtotal -
Long-term Contacts 37.7 42.8 34.6 42.1 37.2 46.1
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Short-term markets
Spot Chicago 3.2 3.6 - - - -
Spot Eastern Canada 2.7 3.1 - - - -
Spot California 13.8 15.7 14.6 17.8 14.6 18.1
Spot Alberta/ 30.7 34.8 32.9 40.1 28.7 35.8
Waddington
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Total(1) 88.1 100.0 82.1 100.0 80.5 100.0
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(1) Natural gas sales for 2000 reflect a 366-day year
/T/
For 2003, revenues will be impacted by drilling success and
production volumes as well as external factors such as the market
for natural gas, the exchange rate of the Canadian dollar
relative to the U.S. dollar and the W.T.I price for crude oil.
Additionally, the disposition of producing natural gas assets in
Northeast Alberta to the Trust will reduce production volumes and
corresponding reserves. Natural gas production in this area
averaged approximately 97 MMcf/d during 2002, exiting the year at
90 MMcf/d. A minor asset disposition package is also currently
being marketed, with bids expected to close early in 2003.
The Company anticipates a continued positive trend in commodity
prices for 2003 relative to the prices received in 2002.
Gain On Sale of Short-Term Investments
During the year Paramount disposed of 8.7 million shares of Peyto
Exploration and Development Corp. at an average price of $5.17
per share for net proceeds of $45.0 million resulting in a gain
of $40.1 million. In 2002, Paramount also disposed of 1.25
million shares of Triquest Energy Corp. at an average price of
$2.98 per share for net proceeds of $3.7 million resulting in a
gain of $0.7 million. Paramount routinely utilizes a portion of
its working capital to make short-term investments in private and
publicly traded oil and gas companies. Accordingly, related gains
and losses are included in cash flow from operations.
Bitumen/Natural Gas Co-Production
On February 28, 2002, Paramount entered into a Memorandum of
Agreement with the Province of Alberta and Conoco Canada
Resources Ltd. ("Conoco"), effective May 1, 2000. The Memorandum
of Agreement provided, inter alia, for compensation of $85
million to be paid to the Surmont Gas Producers by the Alberta
Crown in the form of reduced royalties as well as the granting to
the Province of Alberta by the Surmont Gas Producers of an 11
percent gross overriding royalty encompassing certain wells,
lands and leases affected by the shut-in order of May 1, 2000.
Compensation of $47.1 million was received in June 2002. This
amount has been recorded in the Consolidated Statement of
Earnings, net of the net book value of wells, lands and leases in
the affected area of $9.1 million.
Royalties
Royalties are paid by Paramount to the owners of mineral rights
with whom the Company holds leases. Paramount has mineral leases
with the Crown (Provincial and Federal Governments), freeholders
and other operators with whom the Company has joint interests.
/T/
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Royalties (thousands of dollars) 2002 2001 2000
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Crown royalties $71,535 $94,253 $76,470
Other royalties 3,658 5,953 4,587
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75,193 100,206 81,057
Alberta Royalty Tax Credit (749) (500) (516)
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Total royalties $74,444 $99,706 $80,541
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Average corporate royalty rate 17.2% 18.9% 20.6%
---------------------------------------------------------------------
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/T/
Alberta gas Crown royalties are a cash royalty calculated on the
Crown's share of production using the Alberta Reference Price.
The Alberta Reference Price is the monthly weighted average price
for gas consumed in Alberta and gas exported from Alberta reduced
for allowances for transportation and marketing. A subsequent
cost-of-service credit is applied to account for the Crown's
share of allowable capital and processing fees to arrive at the
net royalty.
For 2002, royalties net of the Alberta Royalty Tax Credit
("ARTC") decreased to $74.4 million from $99.7 million in 2001
(2000 - $80.5 million) due to lower natural gas commodity prices.
As a percentage of production revenue, Paramount's corporate
royalty rate decreased to 17.2 percent as compared to 18.9
percent in 2001 (2000 - 20.6 percent). Fourth-quarter royalties
reflected the increase in production volumes and commodity prices
compared to the prior year's quarter, and increased to $31.2
million as compared to $12.4 million during the fourth quarter
2001.
For 2003, Paramount's average corporate royalty rate is expected
to increase, giving effect to a corporate average natural gas
price which will be less than the Alberta Reference Price on
which royalties are calculated. This results from expected losses
on the Company's hedging program which are netted from revenues
in deriving at petroleum and natural gas sales. As in 2002, there
will continue to be minimal royalties paid to the Federal
Government for production from projects in the Northwest
Territories. Royalties for these projects are subject to payout
accounts.
Operating Expenses
/T/
--------------------------------------------------------------------- Operating Expenses (thousands of dollars) 2002 2001 2000 --------------------------------------------------------------------- Operating expenses $86,067 $61,045 $47,974 --------------------------------------------------------------------- --------------------------------------------------------------------- Net operating expenses per Mcfeq $0.79 $0.68 $0.56 --------------------------------------------------------------------- ---------------------------------------------------------------------
/T/
Paramount's 2002 operating expenses increased 38 percent to $86.1
million from $61.0 million in 2001 (2000 - $48.0 million). On a
unit-of-production basis, average operating costs increased to
$0.79 /Mcfeq from $0.68/Mcfeq in 2001 (2000 - $0.56/Mcfeq).
Fourth-quarter operating costs increased to $21.5 million as
compared to $17.5 million a year earlier, primarily due to the
increased well base in the current quarter associated with the
Summit acquisition.
Paramount constructs and operates plant facilities and gathering
systems as a corporate strategy in order to control the flow of
gas to market. These facilities incur fixed costs, which are in
addition to the costs incurred at the well level, thereby
increasing total operating expenses and the relative magnitude of
the per unit costs. As production declines in the Company's
traditional shallow gas areas, per-unit operating costs have
increased. In new core areas facilities are constructed in
anticipation of maximizing throughput, which in many cases has
not yet been achieved. As optimization occurs and production
volumes increase, per-unit costs should decrease to levels
historically experienced by the Company. Operating costs
associated with the Northeast Alberta assets totaled $32.3
million in 2002 or $0.91/Mcf.
For 2003, the Company expects operating costs on a per-unit-basis
to decline marginally in recognition of the disposal of higher
cost assets in Northeast Alberta.
General and Administrative Expenses
/T/
--------------------------------------------------------------------
General and Administrative Expenses
(thousands of dollars) 2002 2001 2000
--------------------------------------------------------------------
Gross general and administrative expenses $ 30,868 $ 26,374 $ 18,982
Operating recoveries (15,238) (15,766) (11,369)
--------------------------------------------------------------------
General and administrative
expenses before SARP 15,630 10,608 7,613
Share Appreciation Rights Plan ("SARP") 582 1,738 2,047
--------------------------------------------------------------------
Net general and administrative expenses $ 16,212 $ 12,346 $ 9,660
--------------------------------------------------------------------
--------------------------------------------------------------------
Net general and administrative
expenses per Mcfeq $ 0.15 $ 0.14 $ 0.11
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
General and administrative expenses, net of operating recoveries
and before costs associated with the Share Appreciation Rights
Plan ("SARP"), increased to $15.6 million in 2002 as compared to
$10.6 million in 2001 (2000 - $7.6 million). The increase is a
result of additional salaries incurred in respect of the Summit
office and field personnel, as well as additional administrative
expenditures incurred to set up and staff the Trust. During the
year, the Company increased head office staff by more than 32
percent and field staff by 62 percent in order to manage the
Company's increasing asset base and to adequately staff the
Trust. Cost increases associated with additional staffing levels
include salary, benefits and rent. Paramount does not capitalize
any general and administrative expenses.
Certain costs associated with setting up the Trust including
legal and professional fees and advisory fees have been deferred
and will be included as a cost associated with the disposition of
the Northeast Alberta assets.
At the Annual General Meeting of the shareholders held June 14,
2001, a resolution was approved to introduce an employee stock
option plan as a substitute for the SARP. Share appreciation
rights previously held by employees have been grandfathered until
their expiry and are capped at a price of $14.50, that being the
grant price of an equal number of stock options. Under the SARP,
participants are entitled to receive a benefit of an amount equal
to the positive difference between the exercise price and $14.50,
which difference is charged to general and administrative
expenses. At December 31, 2002, 238,000 SARP's remained
outstanding. Employees exercising options have the choice of
receiving cash from the Company for the positive difference
between the exercise price and market price of the Company shares
or receiving Company shares. Cash consideration paid is charged
to general and administrative costs as incurred. During 2002,
177,000 options were exercised for consideration of $0.6 million
as compared to $1.7 million in 2001 (2000 - $2.0 million).
General and administrative expenses are expected to decline in
2003 as the Trust's operations will be excluded from Paramount's
activities.
Interest Expense
/T/
--------------------------------------------------------------------- Interest Expense (thousand of dollars) 2002 2001 2000 --------------------------------------------------------------------- Interest expense $23,943 $19,291 $22,313 Total Debt, December 31 $539,270 $316,600 $315,000 Debt to cash flow 2.07 1.04 1.41 ---------------------------------------------------------------------
/T/
Interest expense, representing interest on bank debt, increased
to $23.9 million from $19.3 million in 2001 (2000 - $22.3
million). The increase reflects significantly higher average debt
levels during 2002 necessary to fund the Summit acquisition and
the higher interest rates charged on the facility.
To finance the acquisition of Summit, the Company negotiated a
$600 million credit facility with a syndicate of Canadian
Chartered banks, including a $466 million production facility, a
$109 million bridge facility and a $25 million working capital
facility.
The term of the credit facility was initially structured to
coincide with the closing of the transfer by Paramount to the
newly formed Trust of a portion of its Northeast Alberta assets.
As the Trust Rights Offering did not close until March 11, 2003,
Paramount requested a formal extension of the existing facility.
Upon closing of the Trust transaction the proceeds received by
Paramount from the sale of the assets to the Trust have been used
to permanently reduce bank indebtedness. On March 11, 2003, the
term of the facility was extended to April 30, 2003, the bridge
facility was paid down in its entirety and the credit facility
reduced to $315.5 million.
The Company had a note payable in the amount of $33 million to
Paramount Oil and Gas Ltd. The note was paid in full on March 7,
2003.
Dry Hole Costs
Under the successful efforts method of accounting, costs of
drilling exploratory wells are initially capitalized and, if
subsequently determined to be unsuccessful, are charged to dry
hole expense. All other exploration costs, including geological
and geophysical costs and annual lease rentals, are charged to
exploration expense as incurred. For 2002, dry hole costs
amounted to $120.1 million as compared to $8.9 million in 2001
and $7.0 million in 2000. The provision includes $4.7 million of
costs associated with wells drilled in the current year, $7.5
million of expired mineral leases, $41.9 million associated with
exploratory wells drilled in Canada in previous years, which the
Company has determined will not be capable of production in
economic quantities, and $66.0 million related to certain
exploratory projects in the United States which the Company has
determined to be unsuccessful.
Geological and geophysical expenses decreased during 2002 to $9.3
million (2001 - $10.6 million; 2000 - $6.8 million).
Depletion, Depreciation and Amortization
The current year provision for depletion and depreciation expense
totaled $169.4 million as compared to $105.4 million in 2001
(2000 - $50.6 million). On a unit-of-production basis, depletion
and depreciation costs averaged $1.56 /Mcfeq as compared to
$1.21/Mcfeq in 2001 (2000 - $0.59/Mcfeq). A larger depletable
base due to the 2002 capital expenditure program and acquisition
of Summit combined with reduced proved reserves increased the
depletion factor during the fourth quarter.
Under the successful efforts method of accounting, depletion and
depreciation is provided based on estimated proved recoverable
reserves of each producing property. Capital costs associated
with undeveloped land of $218.4 million and non-producing
petroleum and natural gas properties of $148.8 million totaling
$367 million are excluded from capital costs subject to depletion
in 2002 (2001 - $402 million).
For 2003, the provision for depletion and depreciation is
expected to decrease reflecting the disposition of assets in
Northeast Alberta to the Trust and the corresponding reduction in
production volumes. Increases or decreases in the depletion rate
on a unit-of-production basis will be influenced by the reserves
added through the 2003 drilling program or by acquisition.
Future Site Restoration and Abandonment Costs
On an annual basis the Company reviews the liability for future
site restoration and abandonment costs. For 2002 the provision
totaled $3.4 million as compared to $2.4 million in 2001 (2000 -
$1.7 million). Current estimates for site restoration of all the
Company's properties total approximately $58 million, excluding
assets in Northeast Alberta which were sold to the Trust during
the first quarter of 2003. At December 31, 2002, $23.0 million is
reflected as an accumulated provision in the financial
statements. This amount includes an accumulated provision for
future site restoration of $10.6 million included as part of the
acquisition of Summit Resources Limited.
Write-Down of Petroleum and Natural Gas Properties
The Company has recorded a provision of $31.3 million in 2002
(2001, 2000 - nil) in respect of impairment in certain producing
non-core oil and gas assets located in Alberta and Southeast
Saskatchewan.
Income Taxes
In 2002, Paramount recorded Large Corporations and other tax
expense of $9.2 million as compared to $2.7 million in 2001 (2000
- $2.3 million). The Company did not pay current income tax in
2002.
The future income tax benefit recorded in 2002 totaled $46.9
million as compared to a $56.1 million provision in 2001 (2000 -
$72.0 million provision). The Company also recorded a $104.9
million future tax liability in respect of the Summit
acquisition, which represents the tax effect of the difference
between the value attributed to the Summit capital assets and the
value of the related tax pools.
/T/
-------------------------------------------------------------------- Estimated Income Tax Pools (millions of dollars) December 31, 2002 -------------------------------------------------------------------- Undepreciated capital costs (UCC) $ 313.5 Canadian oil and gas property expenses (COGPE) 302.2 Canadian exploration expenses (CFE) 9.4 Canadian development expenses (COE) 148.1 Foreign exploration and development expenses (FEDE) 22.4 Other 0.7 -------------------------------------------------------------------- Total estimated income tax pools $ 796.3 -------------------------------------------------------------------- --------------------------------------------------------------------
/T/
Paramount has available approximately $796 million of unutilized
tax pools at December 31, 2002. These tax pools will be available
for deduction in 2003 in accordance with Canadian income tax
regulations at varying rates of amortization.
The disposition of the Northeast Alberta assets to the Trust will
result in a reduction to COGPE and UCC.
Cash Flow and Earnings
/T/
--------------------------------------------------------------------- (thousands of dollars) 2002 2001 2000 --------------------------------------------------------------------- Cash flow from operations $259,916 $303,937 $223,446 Net earnings $10,307 $118,902 $86,062 Weighted average shareholders' equity $540,745 $477,705 $373,623 After-tax rate of return (%) 1.9 24.9 23.0 --------------------------------------------------------------------- ---------------------------------------------------------------------
/T/
Paramount's cash flow from operations decreased 14 percent to
$259.9 million or $4.37 per basic common share ($4.36 per diluted
common share) from $303.9 million or $5.11 per basic and diluted
common share in 2001 (2000 - $223.4 million or $3.76 per basic
and diluted common share). The decrease is due to lower natural
gas prices in 2002, offset somewhat by higher gas and liquids
production during the year, as a result of the Summit
acquisition. Fourth-quarter cash flow totaled $62.1 million, an
increase of 30 percent from $47.7 million during the same period
in 2001 (2000 - $97.2 million). The weighted average common
shares outstanding totaled 59.5 million in 2002, unchanged from
59.5 million in 2001 and 2000.
Earnings decreased to $10.3 million or $0.17 per basic common
share ($0.16 per diluted common share) compared to $118.9 million
or $2.00 per basic and diluted common share in 2001 (2000 - $86.1
million or $1.45 per basic and diluted common share). The lower
earnings in 2002 are a result of decreased cash flows, as well as
larger non-cash charges for depletion and depreciation, dry hole
costs, and the write-down of petroleum and natural gas
properties. The impact of these charges was partially offset by a
significant future tax recovery.
Paramount's three-year average after-tax rate of return on a book
basis, based upon the weighted average shareholders' equity
invested, was 17 percent.
Netbacks
/T/
--------------------------------------------------------------------- Netbacks ($/Mcfeq) 2002 2001 2000 --------------------------------------------------------------------- Revenue $3.96 $5.87 $4.54 Royalties (net of ARTC) 0.68 1.11 0.93 Operating costs 0.79 0.68 0.56 --------------------------------------------------------------------- Operating netback 2.49 4.08 3.05 General and administrative 0.15 0.14 0.11 Lease rentals 0.04 0.05 0.06 Interest on long-term debt 0.22 0.21 0.26 Current and Large Corporations tax 0.08 0.31 0.03 --------------------------------------------------------------------- Cash netback $2.00 $3.37 $2.59 --------------------------------------------------------------------- --------------------------------------------------------------------- Capital Expenditures --------------------------------------------------------------------- Capital Expenditures (thousands of dollars) 2002 2001 2000 --------------------------------------------------------------------- Land $ 6,410 $ 39,166 $ 24,016 Geological and geophysical 9,303 10,646 6,784 Drilling 124,076 127,736 108,811 Production equipment and facilities 77,407 94,775 92,690 --------------------------------------------------------------------- Exploration and development expenditures 217,196 272,323 232,301 --------------------------------------------------------------------- Summit Resources Limited acquisition 449,648 - - Dry hole and geological and geophysical costs expensed (129,361) (19,590) (13,803) Petroleum and natural gas property impairment (42,183) - - Property acquisitions 28,610 19,048 61,550 Property dispositions (4,995) (11,763) (34,205) Other 2,349 1,166 3,205 --------------------------------------------------------------------- Net capital expenditures 521,264 261,184 249,048 Adoption of new accounting policy - - 14,900 --------------------------------------------------------------------- --------------------------------------------------------------------- Change in cost of petroleum and natural gas properties $ 521,264 $ 261,184 $263,948 --------------------------------------------------------------------- ---------------------------------------------------------------------
/T/
During 2002, expenditures for exploration and development
activities totaled $217.2 million as compared to $272.3 million
in 2001 (2000 - $232.3 million). A total of 135 gross (99.5 net)
wells were drilled during the year, including 15 gross (6.3 net)
wells in the fourth quarter, compared to 196 gross (158.7 net)
wells in 2001 (2000 - 163 gross, 128.7 net).
Net capital expenditures, including property acquisitions net of
dispositions and the acquisition of Summit, amounted to $521.3
million in 2002 as compared to $261.2 million in 2001 (2000 -
$249.0 million).
Dry hole and geological and geophysical costs expensed totaled
$129.4 million in 2002 as compared to $19.6 million in 2001 (2000
- $13.8 million). Included in this amount are $41.9 million
associated with exploratory wells drilled in Canada in previous
years, and $66.0 million related to exploratory projects in the
United States, which the Company has determined to be
unsuccessful. Seismic costs during 2002 totaled $9.3 million, as
compared to $10.6 million in 2001 (2000 - $6.8 million).
In conjunction with the cash compensation received from the
Alberta Crown related to the Surmont natural gas/bitumen issue,
the Company has made a provision of approximately $9.1 million
(net of $1.8 million accumulated depletion and depreciation) in
recognition of the impairment in asset value resulting from the
shut-in. The amount represents the net book value of the assets
carried in the financial statements.
Paramount has also recorded a $31.3 million impairment charge in
respect of producing non-core oil and gas assets located in
Alberta and Southeast Saskatchewan
For 2003, Paramount's capital expenditure budget will be funded
by internally generated cash flow and minor property
dispositions. Any deficiency will draw upon existing credit
facilities.
Investments
Short-Term Investments
The Company has the following short-term investments:
/T/
---------------------------------------------------------------------
Opening Purchased Closing Gain on
2002 Shares (Sold) 2002 Investment Sale
Shares
---------------------------------------------------------------------
Investments
Peyto Exploration
and Development
Corp. 8,709,072 (8,709,072) - $ - $40,105,111
Triquest Energy
Corp.(C) 5,000,000 (5,000,000) - - 725,000
Fox Creek
Petroleum
Corp. 1,028,571 1,144,591 2,173,162 2,234,000
Jurassic Oil
and Gas Ltd. 850,000 850,000 1,020,000
Spearhead
Resources Inc.(A) 5,000,000
Altius Energy
Corp.(B) 4,690,240
---------------------------------------------------------------------
$12,944,240 $40,830,111
---------------------------------------------------------------------
---------------------------------------------------------------------
(A)Spearhead Resources Inc. $5 million 8 percent secured convertible
debenture due September 12, 2003
(B)Altius Energy Corp. $2.7 million U.S. 14 percent secured
convertible debenture due April 9, 2005
(C)During the year Triquest shares were consolidated on a 4-for-1
basis. Actual Triquest shares sold in 2002 were 1,250,000.
/T/
At December 31, 2002, all short-term investments were either
debentures, or warrants or shares in private companies, therefore
a market value for these assets is not readily accessible. The
Company believes that the market value of its short-term
investments approximates their book value.
Investment in Drilling Company
Paramount owns a 50 percent equity interest in Wilson Drilling
Ltd., a private company established to operate 3 drilling rigs in
Western Canada. The Company accounts for its interest using
proportionate consolidation whereby its pro-rata share of the
financial results is combined on a line-by-line basis with
similar items in the Company's financial statements.
Investment in Pipeline Company
Paramount owns a 50 percent equity interest, before payout (45
percent after payout) in Shiha Energy Transmission Ltd., a
private company established to transport natural gas from
operations in the Liard core area, Northwest Territories to
facilities in British Columbia. The Company accounts for its
interest using proportionate consolidation whereby its pro-rata
share of the financial results is combined on a line-by-line
basis with similar items in the Company's financial statements.
Investment in Engineering Company
Paramount owns a 50 percent equity interest in a private company
whose principal business is to provide consulting and technical
engineering services. The Company accounts for its interest using
proportionate consolidation whereby its pro-rata share of the
financial results is combined on a line-by-line basis with
similar items in the Company's financial statements.
Deferred Revenue
During 2002, Paramount recognized in revenue $39.4 million (2001
- $1.2 million; 2000 - $1.2 million) of deferred revenue
primarily related to the settlement of natural gas commodity
hedging contracts that were previously put in place to shelter
the Company from declining gas prices. Paramount's accounting
policy recognizes these gains in the accounting years of related
production. The deferred hedging gains of $7.8 million at
December 31, 2002 will be recognized in revenue in 2003.
Bank Debt, Liquidity and Risk Management
Paramount's debt and equity capital structure as at December 31,
2002, was as follows:
/T/
---------------------------------------------------------------------
AT COST AT MARKET(1)
(thousands of dollars, $/Share $/Share
except per share) Amount % (2) Amount % (2)
---------------------------------------------------------------------
Bank debt, net of
working capital 555,243 55 9.34 555,243 32 9.34
Future income taxes 271,090 27 4.56 271,090 16 4.56
Common share equity 190,193 18 3.20 891,879 52 15.00
---------------------------------------------------------------------
Total 1,016,526 100 17.10 1,718,212 100 28.90
---------------------------------------------------------------------
(1)Close at December 31, 2002- $15.00 /share.
(2)At December 31, 2002- 59,458,600 basic common shares outstanding.
/T/
To finance the acquisition of Summit, the Company negotiated a
$600 million credit facility with a syndicate of Canadian
Chartered Banks, including a $466 million production facility, a
$25 million working capital facility, and a $109 million bridge
facility. Upon receipt of the Surmont proceeds the bridge
facility was permanently reduced by approximately $47.1 million.
Upon closing of the Initial offering of units by Paramount Energy
Trust (the "Trust"), the proceeds received by the Company in
exchange for petroleum and natural gas properties sold to the
Trust were used to permanently reduce bank indebtedness.
Effective March 12, 2003, the available borrowing base under the
current credit facility was reduced to $315.5 million.
Also of significant importance to the Company is the Canada/U.S.
exchange ratio, since a substantial percentage of the natural gas
sales and crude oil sales of the Company are made into and priced
effectively on U.S. markets. Any improvement in the Canadian
dollar relative to its U.S. counterpart will have a negative
impact on the wellhead price received for our production. To
manage this risk, Paramount has entered into currency swap
agreements that have fixed the exchange rates on U.S. $40.9
million of future production revenue over the next three years at
CDN $58.6 million. In addition, the Company's U.S. $20 million
bank loan is also designated as a currency hedge.
As at December 31, 2002, the Company's issued share capital
consisted of 59,458,600 common shares (December 31, 2001 and 2000
- 59,453,600 common shares). Paramount instituted a "Normal
Course Issuer Bid" to acquire a maximum of 5 percent of its
issued and outstanding shares commencing September 1, 2001, and
ending August 31, 2002. During 2002, no shares were purchased
pursuant to the plan.
Risks and Uncertainties
Companies involved in the exploration for and production of oil
and natural gas face a number of risks and uncertainties inherent
in the industry. The Company's performance is influenced by
commodity pricing, transportation and marketing constraints and
government regulation and taxation.
Natural gas prices are influenced by the North American supply
and demand balance as well as transportation capacity
constraints. Seasonal changes in demand, which are largely
influenced by weather patterns, also affect the price of natural
gas.
Stability in natural gas pricing is available through the use of
short and long-term contract arrangements. Paramount utilizes a
combination of these types of contracts, as well as spot markets,
in its natural gas pricing strategy. As the majority of the
Company's natural gas sales are priced to US markets, the
Canada/US exchange rate can strongly affect revenue.
Oil prices are influenced by global supply and demand conditions
as well as for worldwide political events. As the price of oil in
Canada is based on a US benchmark price, variations in the
Canada/US exchange rate further affect Paramount's oil price.
The Company's access to oil and natural gas sales markets is
restricted, at times, by pipeline capacity. In addition, it is
also affected by the proximity of pipelines and availability of
processing equipment. Paramount controls as much of its marketing
and transportation activities as possible in order to minimize
any negative impact from these external factors.
The oil and gas industry is subject to extensive controls,
regulatory policies and income taxes imposed by the various
levels of government. These controls and policies, as well as
income tax laws and regulations, are amended from time to time.
The Company has no control over government intervention or
taxation levels in the oil and gas industry; however, it operates
in a manner to ensure that it is in compliance with all
regulations and is able to respond to changes as they occur.
Paramount's operations are subject to the risks normally
associated with the oil and gas industry including hazards such
as unusual or unexpected geological formations, high reservoir
pressures and other conditions involved in drilling and operating
wells. The Company minimizes these risks using prudent safety
programs and risk management, including insurance coverage
against potential losses.
The Company recognizes that the industry is faced with an
increasing awareness with respect to the environmental impact of
oil and gas operations. Paramount has reviewed the environmental
risks to which it is exposed and has determined that there is no
current material impact on the Company's operations; however, the
cost of complying with environmental regulations is increasing.
Paramount will ensure continued compliance with environmental
legislation.
Kyoto Protocol on Greenhouse Gas Emissions
Canada is signatory to an International Treaty to achieve a 6
percent reduction from 1990 greenhouse gas emission levels by
2008-2012, which represents approximately a 25 percent cut from
current levels. At this time the Company does not know what final
course of action the Canadian or United States governments will
take in this regard and accordingly cannot measure the potential
risk to our business.
2003 Cash Flow Forecast and Sensitivity Analysis
The Company's earnings and cash flow are highly sensitive to
changes in commodity prices, exchange rates and other factors
that are beyond the control of the Company. Current volatility in
commodity prices creates uncertainty as to Paramount's cash flow
and capital expenditure budget. The Company will therefore assess
results throughout the year and revise budgets as necessary to
reflect most current information. The following analysis assesses
the magnitude of these sensitivities on the Company's 2003 cash
flow using the following base assumptions:
/T/
a) 2003 Production Natural gas 180 MMcf/d Crude oil/liquids 8,500 Bbl/d b) 2003 Average Prices Natural gas $5.80Mcf Crude oil/liquids (W.T.I.) $28.00/Bbl c) Cash Flow $240 million d) 2003 Net Capital Expenditures $200 million
/T/
The following analysis assesses the estimated after-tax impact on
cash flow with variations in production, price, interest and
exchange rates:
/T/
--------------------------------------------------------------------- Sensitivity (millions of dollars) Cash Flow --------------------------------------------------------------------- Gas sales change of 10 MMcf/d 13.5 Gas price change of $0.10/Mcf 4.2 Oil and natural gas liquids sales change of 100 Bbl/d 0.8 Oil and natural gas liquids price change of $1.00/Bbl (W.T.I) 2.0 Sensitivity to Canada/US exchange rate fluctuation of $0.01 CDN. 0.5 Average interest rate change of 1% 2.0 ---------------------------------------------------------------------
/T/
Recent Accounting Pronouncements
Hedging Relationships
The CICA issued Accounting Guideline 13 - Hedging Relationships,
which deals with the identification, designation, documentation
and effectiveness of hedging relationships for the purpose of
applying hedge accounting. The guideline establishes conditions
for applying hedge accounting, but does not specify hedge
accounting methods. The guideline is effective for fiscal years
beginning on or after July 1, 2003. The Company anticipates that
adoption of Accounting Guideline 13 will not have a material
effect on its consolidated financial statements.
Impairment of Long-Lived Assets
The CICA recently issued Handbook Section 3063 - Impairment of
Long-Lived Assets. This new Section establishes standards for the
recognition, measurement and disclosure of the impairment of
long-lived assets by profit-oriented enterprises. The section is
effective for fiscal years beginning on or after April 1, 2003.
Under the new Section, impairment of long-lived assets held for
use is determined by a two-step process, with the first step
determining when an impairment is recognized and the second step
measuring the amount of the impairment. To test for and measure
impairment, long-lived assets are grouped at the lowest level for
which identifiable cash flows are largely independent. An
impairment loss is recognized when the carrying amount of a
long-lived asset exceeds the sum of the undiscounted cash flows
expected to result from its use and eventual disposition. An
impairment loss is measured as the amount by which the long-lived
asset's carrying amount exceeds its fair value. This represents a
significant change to Canadian GAAP, which previously measured
the amount of the impairment as the difference between the
long-lived asset's carrying value and its net recoverable amount
(i.e. undiscounted cash flows plus residual value). The potential
impact of this pronouncement on the Consolidated Financial
Statements is not known at present.
Disposal of Long-Lived Assets and Discontinued Operations
The CICA recently issued Handbook Section 3475 - Disposal of
Long-Lived Assets and Discontinued Operations, establishes
standards for the recognition, measurement, presentation and
disclosure of the disposal of long-lived assets by
profit-oriented enterprises. It also establishes standards for
the presentation and disclosure of discontinued operations.
Although earlier adoption is encouraged, section 3475 applies to
disposal activities initiated by a company's commitment to a plan
on or after May 1, 2003. The Company anticipates that adoption of
this pronouncement will not have a material effect on its
consolidated financial statements.
/T/
Consolidated Balance Sheets
--------------------------------------------------------------------
As at December 31 (thousands of dollars) 2002 2001
--------------------------------------------------------------------
ASSETS (note 6)
Current Assets
Cash $ - $ 740
Short-term investments (market value:
2002 - $14,168; 2001 - $29,598) (note
14) 14,168 13,932
Accounts receivable (note 11) 91,042 72,356
Prepaid expenses 19,213 13,320
Deferred hedging loss (note 11) - 17,638
--------------------------------------------------------------------
124,423 117,986
--------------------------------------------------------------------
Property, Plant and Equipment (note 4)
Petroleum and natural gas properties, at
cost 1,961,369 1,440,105
Accumulated depletion and depreciation (549,408) (381,768)
--------------------------------------------------------------------
1,411,961 1,058,337
--------------------------------------------------------------------
$ 1,536,384 $1,176,323
--------------------------------------------------------------------
--------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 140,396 $ 92,084
Shareholder loan (notes 7 and 15) 33,000 -
Bank loans (notes 6 and 15) 498,097 -
--------------------------------------------------------------------
671,493 92,084
--------------------------------------------------------------------
Bank loans (notes 6 and 15) - 314,148
Drilling rig indebtedness (note 5) 1,443 2,452
Mortgage (note 6) 6,730 -
Provision for future site restoration
and abandonment costs 22,954 8,955
Deferred revenue (note 11) 7,804 1,427
Future income taxes (note 9) 279,855 221,873
--------------------------------------------------------------------
318,786 548,855
--------------------------------------------------------------------
Commitments and contingencies (notes 5, 11 and 13)
Shareholders' Equity
Share capital (note 8)
Issued and outstanding
59,458,600 common shares (2001-
59,453,600 common shares) 190,193 189,320
Retained earnings 355,912 346,064
--------------------------------------------------------------------
546,105 535,384
--------------------------------------------------------------------
$ 1,536,384 $1,176,323
--------------------------------------------------------------------
--------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Earnings and Retained Earnings
Three Months Ended Year Ended
December 31 December 31
--------------------------------------------------------------------
(thousands of dollars 2002 2001 2002 2001
except for per share
amounts)
--------------------------------------------------------------------
Revenue
Petroleum and natural
gas sales $ 135,501 $ 87,670 $ 431,001 $ 525,686
Royalties (net of ARTC) (28,157) (12,438) (74,444) (99,706)
Gain on sale of
investments (note 14) 725 - 40,830 2,982
Other income 2,111 - 2,111 (295)
--------------------------------------------------------------------
110,180 75,232 399,498 428,667
--------------------------------------------------------------------
Expenses
Operating 23,474 17,530 86,067 61,045
Surmont compensation -
net (note 10) - - (37,291) -
Interest 9,727 4,658 23,943 19,291
General and
administrative 5,768 3,470 16,212 12,346
Geological and
geophysical 1,182 1,739 9,303 10,646
Dry hole costs (note 4) 75,909 282 120,058 8,944
Lease rentals 1,585 1,227 4,552 4,319
(Gain) loss on sales of
property and equipment 121 1,159 (12) 1,537
Provision for future site
restoration and
abandonment costs 1,619 600 3,437 2,400
Depletion and
depreciation 61,106 59,310 169,433 105,433
Write-down of petroleum
and natural gas
properties (note 4) 31,254 - 31,254 -
--------------------------------------------------------------------
211,745 89,975 426,956 225,961
--------------------------------------------------------------------
Earnings (loss) before
taxes (101,565) (14,743) (27,458) 202,706
--------------------------------------------------------------------
Income and other taxes
(note 9)
Current income tax - - - 25,000
Large corporations tax
and other 7,866 615 9,150 2,729
Future income tax
(recovery) (68,032) (4,925) (46,915) 56,075
--------------------------------------------------------------------
(60,166) (4,310) (37,765) 83,804
--------------------------------------------------------------------
Net earnings (41,399) (10,433) 10,307 118,902
Retained earnings,
beginning of year 397,311 358,269 346,064 228,934
Adoption of new
accounting policies
(note 3) - (1,772) (459) (1,772)
--------------------------------------------------------------------
Retained earnings, end of
year $ 355,912 $ 346,064 $ 355,912 $ 346,064
--------------------------------------------------------------------
--------------------------------------------------------------------
Net earnings per common
share
- basic $ (0.70) $ (0.18) $ 0.17 $ 2.00
- diluted $ (0.70) $ (0.18) $ 0.16 $ 2.00
--------------------------------------------------------------------
Weighted average common
shares outstanding
(thousands)
- basic 59,459 59,454 59,458 59,454
- diluted 59,581 59,527 59,567 59,527
--------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Cash Flows
Three Months Ended Year Ended
December 31 December 31
--------------------------------------------------------------------
Years ended December 31 2002 2001 2002 2001
(thousands of dollars
except for per share
amounts)
--------------------------------------------------------------------
Operating activities
Net earnings $ (41,399) $ (10,433) $ 10,307 $ 118,902
Add (deduct) non-cash
items
Write-down of Surmont
assets - - 9,136 -
Depletion and
depreciation 61,106 59,310 169,433 105,433
Write-down of petroleum
and natural gas
properties 31,254 - 31,254 -
(Gain) loss on sales of
property and equipment 121 1,159 (12) 1,537
Provision for future site
restoration and
abandonment costs 1,619 600 3,437 2,400
Future income taxes (68,032) (4,925) (46,915) 56,075
Non-cash general and
administrative expenses 342 - 342 -
Add items not related to
operating activities
Surmont compensation - - (46,427) -
Dry hole costs 75,909 282 120,058 8,944
Geological and
geophysical costs 1,182 1,739 9,303 10,646
--------------------------------------------------------------------
Cash flow from operations 62,102 47,732 259,916 303,937
Increase (decrease) in
deferred revenue (10,360) (291) 6,073 (1,160)
Change in non-cash
operating working capital
(note 12) (26,453) (1,930) 40,145 (17,677)
--------------------------------------------------------------------
25,289 45,511 306,134 285,100
--------------------------------------------------------------------
--------------------------------------------------------------------
Financing activities
Bank loans - draws 12,646 46,488 146,952 3,627
Bank loans - repayments (25,219) - (37,516) -
Shareholder loan - - 33,000 -
Capital stock - - 72 -
Mortgage 6,730 - 6,730 -
Drilling rig indebtedness (83) (45) (1,009) (2,027)
--------------------------------------------------------------------
--------------------------------------------------------------------
(5,926) 46,443 148,229 1,600
--------------------------------------------------------------------
Cash flow provided by
operating and financing
activities 19,363 91,954 454,363 286,700
--------------------------------------------------------------------
Investing activities
Property and equipment
expenditures 14,615 54,303 209,848 266,172
Acquisition of Summit
Resources Ltd. (note 2) - - 251,422 -
Petroleum and natural gas
property acquisitions (175) (35,732) 28,420 8,345
Geological and
geophysical costs 1,182 1,739 9,303 10,646
Proceeds on sale of
property, plant and
equipment 284 19,886 (4,423) (2,857)
Surmont compensation - - (46,427) -
Change in non-cash
investing working capital
(note12) 3,457 51,026 6,960 4,070
--------------------------------------------------------------------
Cash flow used in
investing activities 19,363 91,222 455,103 286,376
--------------------------------------------------------------------
--------------------------------------------------------------------
Decrease (increase) in
cash - 732 (740) 324
Cash, beginning of year - 8 740 416
--------------------------------------------------------------------
Cash, end of year $ - $ 740 $ - $ 740
--------------------------------------------------------------------
--------------------------------------------------------------------
Cash flow from operations
per common share (note 3)
- basic $ 1.04 $ 0.80 $ 4.37 $ 5.11
- diluted $ 1.04 $ 0.80 $ 4.36 $ 5.11
--------------------------------------------------------------------
--------------------------------------------------------------------
Weighted average common
shares outstanding
(thousands)
- basic 59,459 59,454 59,458 59,454
- diluted 59,581 59,527 59,567 59,527
--------------------------------------------------------------------
--------------------------------------------------------------------
See accompanying notes to consolidated financial statements
/T/
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts expressed in thousands of dollars)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Paramount Resources Ltd. (the "Company") is involved in the
exploration and development of petroleum and natural gas
primarily in Western Canada. The consolidated financial
statements are stated in Canadian dollars and have been prepared
by management in accordance with Canadian generally accepted
accounting principles.
As a precise determination of many assets and liabilities is
dependent upon future events, the preparation of periodic
financial statements necessarily involves the use of estimates
and approximations. Accordingly, actual results could differ
from those estimates. The financial statements have, in
management's opinion, been properly prepared within reasonable
limits of materiality and within the framework of the Company's
accounting policies summarized below.
(a) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of
Paramount Resources Ltd. and its wholly owned subsidiaries
Paramount Energy Trust, Paramount Resources US LLC, 586319
Alberta Ltd., Summit Resources Ltd., Summit Resources Inc.,
977554 Alberta Ltd. and 910083 Alberta Ltd.
The Company accounts for its interest in a drilling company, a
drilling partnership, a pipeline company, and an engineering
company where it exercises joint control using proportionate
consolidation whereby its pro-rata share of all assets,
liabilities, revenues and expenses are combined on a line-by-line
basis with similar items in the Company's financial statements.
(b) JOINT OPERATIONS
Certain of the Company's exploration, development and production
activities related to petroleum and natural gas are conducted
jointly with others. These financial statements reflect only the
Company's proportionate interest in such activities.
(c) SHORT-TERM INVESTMENTS
Short-term investments consist of common shares and convertible
instruments held for sale. These investments are carried at the
lower of cost and market value.
(d) INVENTORY
Natural gas in storage is carried at the lower of cost and net
realizable value. Cost includes all amounts incurred to produce
or purchase the related gas, transportation to the storage
facility and the cost of storage. At December 31, 2002 and 2001,
there was no natural gas inventory.
(e) PETROLEUM AND NATURAL GAS PROPERTIES
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. Exploration
expenses, including geological and geophysical costs, lease
rentals and exploratory dry hole costs, are charged to earnings
as incurred. Leasehold acquisition costs, including costs of
drilling and equipping successful wells, are capitalized. The
net cost of unproductive exploratory wells, abandoned wells and
surrendered leases are charged to earnings in the year of
abandonment or surrender. Gains or losses are recognized on the
disposition of property, plant and equipment.
Depletion and depreciation of petroleum and natural gas
properties including well development expenditures, production
equipment, gas plants and gathering systems are provided on the
unit-of-production method based on estimated proven recoverable
reserves of each producing property or project. Depreciation of
other equipment is provided on a declining balance method at
rates varying from 4 to 30 percent.
Producing areas and significant unproved properties are assessed
annually, or as economic events dictate for potential impairment.
Any impairment loss is the difference between the carrying value
of the asset and its undiscounted net recoverable amount.
(f) FUTURE SITE RESTORATION AND ABANDONMENT COSTS
Estimated future site restoration and abandonment costs are
provided for in the financial statements. This estimate, net of
expected recoveries, includes the cost of equipment removal and
environmental cleanup based upon current regulations and economic
circumstances at year end. Actual site restoration costs are
deducted from the provision in the year incurred.
(g) FOREIGN CURRENCY TRANSLATION
The Company's foreign operations are considered integrated and
are translated into Canadian dollars using the temporal method.
Monetary assets and liabilities denominated in U.S. dollars are
translated into Canadian dollars at exchange rates in effect at
the balance sheet date. Other assets and liabilities are
translated at the rates prevailing at the respective transaction
dates. Revenues and expenses are translated at the average rate
prevailing during the year. Translation gains and losses are
reflected in income when incurred.
(h) FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instrument contracts to
manage its exposure to petroleum and natural gas prices, the
Canadian/US dollar exchange rate and interest rate fluctuations.
Gains or losses from foreign exchange and commodity hedge
contracts are recognized as part of petroleum and natural gas
sales in the same period as the related production revenue.
Amounts received or paid under interest rate swaps are recognized
in interest expense as incurred. The fair values of these
contracts are not reflected in the financial statements. The
Company does not enter into derivative instruments for trading or
speculative purposes.
The Company's policy is to formally designate each derivative
financial instrument as a hedge of a specifically identified
future revenue stream. The Company believes the derivative
financial instruments are effective as hedges, both at inception
and over the term of the instrument, as the term to maturity, the
notional amount and the commodity price basis in the instruments
all match the terms of the future revenue stream being hedged.
Realized and unrealized gains or losses associated with
derivative financial instrument contracts that have been
terminated or cease to be effective prior to maturity, are
deferred as other current, or non-current, assets or liabilities
on the balance sheet, as appropriate and recognized in earnings
in the period in which the underlying hedged transaction is
recognized. In the event a designated hedged item is sold,
extinguished or matures prior to the termination of the related
derivative instrument, any realized or unrealized gain or loss on
such derivative instrument is recognized in earnings.
(i) MEASUREMENT UNCERTAINTY
The amounts recorded for depletion and depreciation and
impairment of petroleum property and equipment and for site
restoration and abandonment are based on estimates of reserves,
future costs, petroleum and natural gas prices and other relevant
assumptions. By their nature, these estimates and those related
to the future cash flow used to assess impairment are subject to
measurement uncertainty, and the impact on the financial
statements of future periods could be material.
(j) INCOME TAXES
The Company follows the liability method of tax accounting for
income taxes. Under this method, future tax assets and
liabilities are determined based on differences between financial
reporting and income tax bases of assets and liabilities, and are
measured using enacted tax rates and laws that will be in effect
when the differences are expected to reverse. The effect on
future tax assets and liabilities of a change in tax rates is
recognized in net income in the period in which the change
occurs.
(k) STOCK OPTION PLAN
The Company has a stock based compensation plan consisting of a
stock option plan and a stock appreciation rights plan. These
plans are described in note 8.
As options granted under the Company's employee stock option plan
are issued at current market value, the option has no intrinsic
value and therefore no compensation expense is recorded when the
options are granted. Consideration paid by employees or directors
on the exercise of stock options is credited to share capital.
Awards issued under the stock appreciation plan, that call for
settlement in cash or other assets, are measured as the amount by
which the quoted market value of the shares of the Company's
stock covered by the grant exceeds the market price of the
underlying stock. Changes, either increase or decreases, in the
quoted market value of those shares between the date of grant and
the measurement date result are charged to earnings in the period
of change.
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 will make an offer to
purchase all of the issued and outstanding common shares of
Summit for cash consideration of $7.40 per share or approximately
$251.4 million, including acquisition costs. This transaction
has been accounted for using the purchase method and is being
accounted for as of the closing date of June 28, 2002.
The following table summarizes the estimated fair value of the
assets acquired and liabilities assumed at the date of
acquisition. The Company has not yet completed its final
evaluation of the assets acquired and the liabilities assumed.
Therefore, the purchase price is subject to change.
/T/
Assets
Accounts receivable $ 13,997
Petroleum and natural gas properties 449,648
---------------------------------------------------------------------
463,645
---------------------------------------------------------------------
Liabilities
Accounts payable 21,947
Future income taxes 104,897
Debt 74,513
Site restoration 10,562
Other liabilities 304
---------------------------------------------------------------------
212,223
---------------------------------------------------------------------
Net assets acquired $ 251,422
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
3. CHANGE IN ACCOUNTING POLICY
(a) STOCK-BASED COMPENSATION
Effective January 1, 2002, the Company adopted the new Canadian
Institute of Chartered Accountants Standard on Stock-Based
Compensation. Under this new standard, the Company's stock
options and SARs, 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 SARs 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 year ended December 31, 2002, was
$342,000.
This new standard requires the presentation of pro forma net
earnings as if the Company had accounted for 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/
---------------------------------------------------------------------
Year ended
December 31, 2002
Net earnings as reported $ 19,072
pro forma $ 19,023
Net earnings per common share
- basic as reported $ 0.32
pro forma $ 0.32
Net earnings per common share
- diluted as reported $ 0.31
pro forma $ 0.31
---------------------------------------------------------------------
/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%; dividend yield of 0%; weighted-average volatility factor
of the expected market price of the Company's common shares of
39.5%; and a weighted-average expected life of the options of 4
years.
(b) TREATMENT OF FOREIGN EXCHANGE GAINS AND LOSSES ON LONG-TERM
DEBT
In accordance with a newly issued Canadian Institute of Chartered
Accountants ("CICA") accounting standard, the Company no longer
defers and amortizes the gains or losses on foreign currency
denominated long-term debt. Such gains or losses are reflected in
the Income Statement in the period incurred. The new standard has
been applied retroactively without restatement of prior periods.
The impact of the new standard on the results of the year ended
December 31, 2002 was to increase net income by $0.4 million and
reduce current assets and retained earnings by $1.8 million,
representing the cumulative deferred foreign exchange losses at
the beginning of the period.
(c) BANK LOANS
On January 1, 2002, the Company adopted the new CICA
recommendation 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 (other than in the event of a default or breach
of covenants) 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.
At December 31, 2002, this change has increased current
liabilities by $498.1 million and reduced long-term bank loans by
a corresponding amount.
4. PROPERTY PLANT AND EQUIPMENT
/T/
---------------------------------------------------------------------
2002 2001
---------------------------------------------------------------------
Cost Accumulated Cost Accumulated
depletion and depletion and
depreciation depreciation
---------------------------------------------------------------------
Petroleum and natural
gas properties $1,263,544 $326,074 $919,667 $188,826
Gas plants,
gathering systems
and production
equipment 670,769 214,655 507,976 185,527
Other 27,056 8,679 12,462 7,415
---------------------------------------------------------------------
$1,961,369 $549,408 $1,440,105 $381,768
---------------------------------------------------------------------
Net book value $1,411,961 $1,058,337
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Capital costs associated with non-producing petroleum and natural
gas properties totaling approximately $367 million (2001 - $402
million) are currently not subject to depletion.
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 year ended December 31, 2002, the Company expensed $120.1
million in dry hole costs (2001- $8.9 million), of which $66.0
million related to exploratory projects in the United States. A
portion of the dry hole costs expensed related to prior year
capital projects that were determined in the current year to have
no future economic value. An additional provision of $31.3
million has been recorded in respect of properties in Alberta and
Saskatchewan whose net book values were in excess of undiscounted
reserve values at December 31, 2002.
5. JOINT VENTURES
The consolidated financial statements include the Company's
proportionate share of the assets and liabilities of its joint
ventures as follows:
/T/
---------------------------------------------------------------------
2002 2001
---------------------------------------------------------------------
Assets
Current assets $ 1,278 $ 1,983
Property, plant and equipment 8,520 6,822
---------------------------------------------------------------------
$ 9,798 $ 8,805
---------------------------------------------------------------------
---------------------------------------------------------------------
Liabilities and equity
Current liabilities $ 9,239 $ 6,908
Other liabilities 2,008 3,541
Deficit (1,449) (1,644)
---------------------------------------------------------------------
$ 9,798 $ 8,805
---------------------------------------------------------------------
---------------------------------------------------------------------
Revenues $ 2,591 $ 1,842
---------------------------------------------------------------------
Net earnings (loss) $ 195 $ (1,542)
---------------------------------------------------------------------
Cash flow provided by (used in)
Operating activities $ 3,452 $ 2,654
---------------------------------------------------------------------
Financing activities $ 1,063 $ (1,027)
---------------------------------------------------------------------
Investing activities $ (4,515) $ (1,627)
---------------------------------------------------------------------
/T/
Wilson Drilling Ltd. had a reducing term loan facility available
to a maximum of $6.0 million at December 31, 2002. The loan is
repayable in equal quarterly installments of $500,000 to December
2005. As at December 31, 2002, this facility had an effective
interest rate of 5.5 percent (December 31, 2001 - 5.25 percent).
Wilson Drilling Ltd. also has a long-term capital lease on one of
its drilling rigs with a Canadian Chartered Bank in the amount of
approximately $3 million. The lease runs until August 2007 and
has an imputed interest rate of 8.9%. The Company has provided a
guarantee as collateral for these facilities. Earnings attributed
to services provided to the Company have been eliminated from the
accompanying consolidated statement of earnings.
6. BANK LOANS
To finance the acquisition of Summit, the Company negotiated a
$600 million credit facility with a syndicate of Canadian
Chartered Banks, including a $466 million production facility, a
$109 million bridge facility and a $25 million working capital
facility. The term of the facility is to April 30, 2003.
Available borrowings under the bridge facility were permanently
reduced by $47.1 million upon receipt of the Surmont settlement.
The term of the credit facility was initially structured to
coincide with the closing of the transfer by Paramount of a
portion of its Northeast Alberta assets to a newly formed Energy
Trust. However, as this transaction had not yet closed as of
December 31, 2002, Paramount has requested a formal extension of
the existing facility. Accordingly, the loan facility has been
classified as short-term. Upon closing of the "Trust"
transaction proceeds received by Paramount from the sale of the
assets to the Trust will be used to permanently reduce bank
indebtedness (see note 15).
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 250 to 800 basis points. On October 1, 2002, the margins
increased by 50 basis points and increased by the same amount on
the first day of each month thereafter. There are no contractual
repayment requirements under this facility.
/T/
As at December 31, the following amounts were drawn under this
facility:
--------------------------------------------------------------------
2002 2001
--------------------------------------------------------------------
Production/working capital facility
- current interest rate of 7.5% $ 418,570 $ -
Bridge facility - current
interest rate of 13% 44,900 -
LIBOR advances - current
interest rate of 7.75% (2001 - 3.2%) 31,556 31,914
Wilson Drilling bank loan -
current interest rate of 5.5% 3,071 -
Bankers' acceptances - 30 day
average rate of 5.25% in 2001 - 282,234
--------------------------------------------------------------------
$ 498,097 $ 314,148
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
The Company has an office building which was acquired as a result
of the acquisition of Summit Resources Limited. The building is
mortgaged at an interest rate of 6.15 percent over a term of 5
years ending December 31, 2007.
The Company has letters of credit totaling $13.3 million
outstanding with a Canadian Chartered Bank. These letters of
credit reduce the amount available under the Company's existing
credit facility.
7. RELATED PARTY TRANSACTIONS
The Company has an unsecured note payable in the amount of $33
million (2001 - nil) to Paramount Oil and Gas Ltd. The note
bears interest at bank prime plus 1 percent, and is repayable
upon closing of a proposed rights offering by Paramount Energy
Trust (see note 15). The effective interest rate on the note
during 2002 was 5.5%.
8. SHARE CAPITAL
Authorized Capital
The authorized capital of the Company is comprised 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.
/T/
Issued Capital
-------------------------------------------------------------------
Common Shares Number Consideration
-------------------------------------------------------------------
Balance December 31, 2000 and 2001 59,453,600 $ 189,320
Stock options exercised during the year 5,000 72
Expenses recognized in respect of
stock-based compensation during the year - 801
-------------------------------------------------------------------
Balance December 31, 2002 59,458,600 $ 190,193
-------------------------------------------------------------------
/T/
The Company instituted a Normal Course Issuer Bid to acquire a
maximum of 5 percent of its issued and outstanding shares
commencing September 1, 2001, and ending August 31, 2002. During
2002 and 2001, no shares were purchased pursuant to the plan.
Stock Option Plan/Share Appreciation Rights Plan
During 2001, the Company replaced the Share Appreciation Rights
Plan (SARP) with an employee stock option plan. Under the plan,
stock options are granted at the current market price on the date
of issuance. Options granted vest over four years and have a
four-and-a-half year contractual life. Share appreciation rights
previously held by employees will be grandfathered until their
expiry on January 31, 2004, and will be capped at a price of
$14.50, that being the grant price of an equal number of stock
options. Under the SARP, participants are entitled to receive a
benefit of an amount equal to the positive difference between the
exercise price and $14.50, which difference will be charged to
general and administrative expenses. At December 31, 2002,
238,000 SARPs remained outstanding (December 31, 2001 - 479,000
SARPs) . During 2002, 177,000 SARPs were exercised at a cost of
$0.6 million (2001 - 329,500 SARPs, $1.7 million), which amount
is charged to general and administrative expenses.
As at December 31, 2002, 2.4 million stock options were reserved
for issuance under the Company's Employee Incentive Stock Option
Plan, of which 1.9 million shares are outstanding, exercisable to
September 30, 2006, at prices ranging from $12.00 to $16.50 per
share.
/T/
---------------------------------------------------------------------
SARPs/Stock options 2002 2001
---------------------------------------------------------------------
Average Rights/ Average Rights/
grant price Options grant price Options
---------------------------------------------------------------------
Balance,
beginning of
year $14.08 2,173,500 $12.72 1,184,500
Granted 15.90 80,000 14.33 1,694,500
Exercised 12.98 (195,000) 14.93 (329,500)
Cancelled 14.23 (109,000) 14.16 (376,000)
---------------------------------------------------------------------
Balance, end
of year $14.25 1,949,500 $14.08 2,173,500
---------------------------------------------------------------------
SARPs/Options
exercisable,
end of year $14.35 738,500 $13.23 213,500
---------------------------------------------------------------------
---------------------------------------------------------------------
The following summarizes information about stock options/SARPs
outstanding at December 31, 2002:
---------------------------------------------------------------------
Number
Weighted Weighted exercisable
Number remaining average at Weighted
Year outstanding at contractual exercise December 31, average
of December 31, life price/share 2002 exercise
grant 2002 (years) price/share
---------------------------------------------------------------------
2002 80,000 4 $15.90 - -
2001 1,631,500 3 $14.35 618,000 $14.55
2000 167,000 2 $13.00 55,500 $13.00
1999 56,000 2 $14.00 50,000 $14.00
1998 15,000 1 $12.00 15,000 $12.00
---------------------------------------------------------------------
1,949,500 $14.25 738,500 $14.35
---------------------------------------------------------------------
---------------------------------------------------------------------
9. INCOME TAXES
The income tax provision differs from the expected income taxes
obtained by applying the Canadian corporate tax rate to income before
taxes as follows:
---------------------------------------------------------------------
2002 2001
---------------------------------------------------------------------
Corporate tax rate 42.14% 43.18%
Calculated income tax (recovery)
expense ($11,571) $87,528
Increase (decrease) resulting from:
Non-deductible Crown charges, net
of Alberta Royalty Tax Credit 10,449 41,394
Federal resource allowance (29,958) (45,215)
Provincial income tax rate
adjustment (2,758) (8,842)
Large Corporation Tax and other 9,150 2,729
Non-taxable portion of gain on sale
of investments (8,603) -
Other (4,474) 6,210
---------------------------------------------------------------------
Income tax (recovery) expense ($37,765) $83,804
---------------------------------------------------------------------
---------------------------------------------------------------------
COMPONENTS OF FUTURE INCOME TAXES
---------------------------------------------------------------------
The net future tax liability comprises: 2002 2001
---------------------------------------------------------------------
Differences between tax base and
reported amounts of depreciable
assets $ 285,201 $ 217,617
Share issue costs (155) (190)
Provision for future site
restoration (7,255) (2,867)
Deferred hedging loss - 5,648
Other 2,064 1,665
---------------------------------------------------------------------
$ 279,855 $ 221,873
---------------------------------------------------------------------
-
/T/
As at December 31, 2002, the Company has tax pools of
approximately $796.3 million (2001 - $562.1 million) available
for deduction against future taxable income.
10. SURMONT COMPENSATION
During 2000, the Alberta Energy and Utilities Board issued a
decision regarding the Surmont natural gas/bitumen co-production
issue. As a result of this decision, the Board ordered the
shut-in of approximately 22 MMcf/d of the Company's production.
On February 28, 2002, the Company and the Surmont Gas Producers
entered into a Memorandum of Agreement with the Province of
Alberta effective May 1, 2000. The Memorandum provided for
compensation of approximately $85 million to be paid to the
Surmont Gas Producers by the Alberta Crown in the form of reduced
royalties, as well as the granting to the Province of Alberta by
the Surmont Gas Producers of an 11 percent gross overriding
royalty encompassing certain wells, land and leases affected by
the shut-in order of May 1, 2000.
In June 2002, the Company received approximately $47 million in
the form of reduced royalties from the Province of Alberta as
compensation for its proportionate share of the settlement. The
cash settlement, net of the net book value of wells, lands and
leases in the affected area of approximately $9 million, has been
recorded in net earnings in the current period.
11. FINANCIAL INSTRUMENTS
The Company's financial instruments included in the Consolidated
Balance Sheet are comprised of cash, short-term investments,
accounts receivable, accounts payable and accrued liabilities,
shareholder loan, bank loan, mortgage and drilling rig
indebtedness.
(a) FOREIGN EXCHANGE HEDGES
The Company has entered into the following currency index swap
transactions, fixing the exchange rate on receipts of US $40.9
million for CDN $58.6 million over the next three years at CDN
$1.4322. The US$/CDN$ closing exchange rate was 1.5776 as at
December 31, 2002, (December 31, 2001 - 1.5928).
/T/
---------------------------------------------------------------------
Year of settlement U.S. dollars Weighted average exchange rate
---------------------------------------------------------------------
2003 $16,570 1.4302
2004 12,360 1.4333
2005 12,000 1.4337
---------------------------------------------------------------------
$40,930 1.4322
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
At December 31, 2002 the estimated fair value of these hedges
based on the Company's assessment of available market information
was a loss of $6.0 million (2001 - loss of $4.6 million).
(b) NATURAL GAS COMMODITY PRICE HEDGES
At December 31, 2002, the Company has entered into financial
forward sales arrangements as follows:
/T/
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AECO Price Term
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10,000 GJ/d $5.46 November 2002 - October 2003
20,000 GJ/d $5.06 November 2002 - October 2003
20,000 GJ/d $5.25 November 2002 - October 2003
NYMEX
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20 MMcf/d US$3.83 November 2002 - October 2003
20 MMcf/d US$3.90 November 2002 - October 2003
10 MMcf/d US$4.10 November 2002 - October 2003
WTI
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1,000 Bbl/d US$24.07 May 2002 - April 2004
1,000 Bbl/d US$24.33 January 2003 - December 2003
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/T/
Had these financial contracts been settled on December 31, 2002,
using prices in effect at that time, the mark to market before
tax loss would have totaled $28.7 million.
During 2002, $46.8 million of net gains related to commodity
hedging contracts (2001 - $15.8 million net gains) are included
in petroleum and natural gas sales.
(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
payment or receipt necessary to settle the contract at year-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 cash,
accounts receivable, accounts payable and accrued liabilities,
shareholder loan and bank loans, 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.
12. CHANGE IN NON-CASH WORKING CAPITAL
/T/
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2002 2001
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Change in non-cash working capital:
Short-term investments $ (236) $ 11,257
Accounts receivable (18,686) 37,137
Prepaid expenses (5,893) (4,862)
Deferred hedging loss 17,638 (17,638)
Accounts payable and accrued
liabilities 48,312 (47,641)
Less working capital deficiency
acquired (note 2) (7,950) -
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$33,185 $(21,747)
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Operating activities $40,145 $(17,677)
Investing activities (6,960) (4,070)
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$33,185 $(21,747)
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Amounts paid during the year related to interest and large
corporations and other taxes were as follows:
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2002 2001
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Interest paid $23,278 $ 19,135
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Large corporations and other taxes paid $20,447 $ 2,729
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/T/
13. CONTINGENCIES
The Company is party to various legal claims associated with the
ordinary conduct of business. The Company does not anticipate
that these claims will have a material impact on the Company's
financial position.
14. GAIN ON SALE OF INVESTMENTS
During the year, the Company recorded gains on disposal of its
investments in Peyto Exploration and Development Corp. and other
short-term investments of $40.8 million.
15. SUBSEQUENT EVENTS
(a) On February 3, 2003, the Company transferred to Paramount
Energy Trust (the "Trust") assets in the Legend area of Northeast
Alberta for proceeds of $81 million, including 9,907,767 Trust
units and a $30 million note payable.
(b) On February 3, 2003, the Company declared a dividend-in-kind
of an aggregate 9,907,767 Trust units. The dividend was paid to
holders of the Company's common shares of record on the close of
business February 11, 2003.
(c) In March 2003, the Company disposed of a significant portion
of its Northeast Alberta natural gas properties to the Trust, the
majority unit holder of which is also a majority shareholder of
the Company. The Company received net proceeds on disposition of
$209 million, which proceeds were used to reduce bank
indebtedness.
As a result of the disposition, the Company's borrowing base on
its credit facility was reduced to $315.5 million.
16. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform
with the current year's financial statement presentation.
