Paramount Resources Ltd.: Financial and Operating Results for the Period Ended December 31, 2003
FOR: PARAMOUNT RESOURCES LTD.
TSX SYMBOL: POU
MARCH 24, 2004 - 09:00 ET
Paramount Resources Ltd.: Financial and Operating
Results for the Period Ended December 31, 2003
CALGARY, ALBERTA - Mar 24, 2004 /CNW/ - Paramount
Resources Ltd. ("Paramount" or the "Company") is pleased to
announce its financial and operating results for the year ended
December 31, 2003.
/T/
2003 Financial Highlights
($ thousands except per share amounts
and where stated otherwise) Three Months Ended December 31,
2003 2002 % Change
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FINANCIAL
Gross Revenue 88,361 138,337 (36)%
Cash Flow
From operations 43,157 62,102 (31)%
Per share - basic 0.72 1.04 (31)%
- diluted 0.71 1.04 (32)%
Earnings
Net earnings 11,296 (41,399) -
Per share - basic 0.18 (0.70) -
- diluted 0.18 (0.70) -
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Capital expenditures
Exploration and development 84,500 14,047 502%
Summit acquisition - - -
Acquisitions, dispositions and
other (43,869) (3,329) 1,218%
Net capital expenditures 40,631 10,718 279%
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Total assets
Net debt
Shareholders' equity
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Weighted average common shares
outstanding (thousands)
Common shares outstanding at
year end (thousands)
Common shares outstanding at
March 12, 2004 (thousands)
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OPERATING
Production
Natural gas (MMcf/d) 141 263 (46)%
Crude oil and liquids (Bbl/d) 5,877 8,552 (31)%
Total Production (Boe/d) @ 6:1 29,353 52,326 (44)%
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Average Prices
Natural gas (pre-hedge) ($/Mcf) 5.14 4.54 13%
Natural gas ($/Mcf) 5.39 4.60 17%
Crude oil and liquids (pre-hedge)
($/Bbl) 36.02 36.03 -
Crude oil and liquids ($/Bbl) 32.89 35.27 (7)%
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Reserves (proved and probable)
Natural gas (Bcf)
Crude oil and liquids (MBbl)
Estimated present value before tax
(discounted @10% using forecast
prices and costs)
Proved ($ millions)
Proved and probable ($ millions)
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Land (thousands of acres)
Total net land holdings
Net undeveloped land holdings
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Drilling Activity (gross)
Gas 58 10 480%
Oil 4 4 -
Other - (1) -
D&A 5 2 150%
Total wells 67 15 347%
Success rate 93% 87% 7%
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Year Ended December 31,
2003 2002 % Change
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FINANCIAL
Gross Revenue 381,847 473,942 (19)%
Cash Flow
From operations 167,276 259,916 (36)%
Per share - basic 2.78 4.37 (36)%
- diluted 2.77 4.36 (36)%
Earnings
Net earnings 2,633 10,307 (74)%
Per share - basic 0.04 0.17 (76)%
- diluted 0.04 0.16 (75)%
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Capital expenditures
Exploration and development 223,753 217,196 3%
Summit acquisition - 251,422 -
Acquisitions, dispositions and
other (368,731) 25,917 -
Net capital expenditures (144,978) 494,535 -
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Total assets 1,147,848 1,526,786 (25)%
Net debt 307,704 555,243 (45)%
Shareholders' equity 501,642 546,105 (8)%
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Weighted average common shares
outstanding (thousands) 60,098 59,458
Common shares outstanding at
year end (thousands) 60,095 59,459
Common shares outstanding at
March 12, 2004 (thousands) 59,393
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OPERATING
Production
Natural gas (MMcf/d) 153 241 (37)%
Crude oil and liquids (Bbl/d) 7,169 5,663 27%
Total Production (Boe/d) @ 6:1 32,630 45,898 (29)%
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Average Prices
Natural gas (pre-hedge) ($/Mcf) 5.99 3.53 70%
Natural gas ($/Mcf) 5.16 4.08 26%
Crude oil and liquids (pre-hedge)
($/Bbl) 38.27 35.20 9%
Crude oil and liquids ($/Bbl) 35.50 34.64 2%
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Reserves (proved and probable)
Natural gas (Bcf) 329.4 618.6 (47)%
Crude oil and liquids (MBbl) 12,513 22,846 (45)%
Estimated present value before tax
(discounted @10% using forecast
prices and costs)
Proved ($ millions) 597 983 (39)%
Proved and probable ($ millions) 734 1,258 (42)%
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Land (thousands of acres)
Total net land holdings 3,386 5,077 (33)%
Net undeveloped land holdings 2,800 3,545 (21)%
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Drilling Activity (gross)
Gas 180 114 58%
Oil 16 9 78%
Other - 1 -
D&A 15 11 36%
Total wells 211 135 56%
Success rate 93% 92% 1%
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/T/
Significant Events
- Creation of Paramount Energy Trust (the "Trust")
Paramount created the Trust and dividended the Trust units to the
Company's shareholders. The Company transferred effectively all
of its producing assets in Northeast Alberta to the Trust
providing shareholders with an income-generating investment, in
addition to an ongoing growth-focused exploration and production
company, Paramount Resources Ltd.
- Non-Core Disposition Program
Through the first half of 2003, Paramount executed a non-core
disposition program comprised of many of the smaller properties
which were part of the Summit Resources Limited ("Summit")
acquisition. This program generated proceeds of $71 million which
were used to reduce the Company's debt.
- Disposition of the Sturgeon Lake property
On October 1, 2003, Paramount sold its interest in the Sturgeon
Lake property for total consideration of $54.0 million, resulting
in a $18.7 million pretax gain. Production from the Sturgeon Lake
assets averaged 1,640 Bbl/d of oil and natural gas liquids and
3.0 MMcf/d of natural gas for the nine months ended September 30,
2003.
- Issuance of US$175 million of medium-term senior notes
On October 27, 2003, the Company issued US$175 million senior
unsecured notes that bear interest at 7 7/8 percent and mature on
October 27, 2010. The notes diversified Paramount's sources of
financing and expanded its financial flexibility.
- Discovery of Nogha Pool at Colville Lake
Two discovery wells, Nogha C-49 and M-17, were drilled during the
winter of 2003. Based on the success of this drilling, Paramount
has drilled three additional wells in the Colville Lake area in
the winter of 2004 and is evaluating options for bringing these
reserves into production.
Financial
Natural gas production volumes averaged 153 MMcf/d in 2003, a 37
percent decrease from the 241 MMcf/d produced in 2002, primarily
as a result of the disposition of Northeast Alberta assets to the
Trust (the "Trust assets") in the first quarter of 2003, as well
as other property dispositions during the year. Production from
the Trust assets averaged 97 MMcf/d in 2002. Stronger natural gas
demand resulted in a 70 percent increase in Paramount's average
natural gas sales price before hedging to $5.99/Mcf as compared
to $3.53/Mcf in 2002. Higher natural gas prices were offset by
$53 million of commodity hedging losses incurred during 2003,
attributed primarily to natural gas hedges. Paramount's average
natural gas price after hedging was $5.16/Mcf as compared to
$4.08/Mcf in 2002.
Oil and natural gas liquids ("NGLs") prices before hedging
averaged $38.27/Bbl in 2003, as compared to $35.20/Bbl in 2002.
Oil and NGLs production increased 27 percent to average 7,169
Bbl/d in 2003 from 5,663 Bbl/d in 2002. This increase is
attributable to a full year of production from the assets
obtained through the acquisition of Summit.
Paramount's 2003 production profile continues to be significantly
weighted to natural gas, despite the acquisition of Summit in
2002. Summit production was approximately 60 percent gas and 40
percent oil and NGLs at the time of acquisition. In 2003 natural
gas production contributed 78 percent of Paramount's total
production compared to 88 percent in 2002. With the disposition
of the Sturgeon Lake property in the fourth quarter of 2003, the
Company expects 2004 production to continue to be strongly
weighted toward natural gas.
Natural gas production volumes averaged 141 MMcf/d during the
fourth quarter, a decrease of 46 percent from 263 MMcf/d for the
comparable quarter in 2002. The lower natural gas production is a
result of the disposition of the Trust assets, the completion of
a successful disposition program of non-core, non-operated
natural gas properties, and the sale of the Sturgeon Lake area.
Oil and NGLs sales averaged 5,877 Bbl/d in the fourth quarter of
2003 as compared to 8,552 Bbl/d for the comparable quarter in
2002 primarily due to the sale of Sturgeon Lake and other minor
oil properties in the current year.
Paramount's cash flow from operations decreased 36 percent to
$167.3 million from $259.9 million in 2002. Lower cash flows were
primarily a result of $53 million in commodity hedging losses in
2003 as opposed to $47 million in commodity hedging gains in
2002, partially offset by a $50 million increase in petroleum and
natural gas revenues due to higher commodity prices. A $40
million gain on sale of the investment in Peyto Exploration was
also included in 2002 cash flows.
Fourth-quarter cash flow totalled $43.2 million, a decrease of 30
percent from $62.1 million during the same period in 2002. The
decrease in cash flow is a result of lower production levels as
compared to the fourth quarter of 2002.
The Company recorded net earnings of $2.6 million, as compared to
net earnings of $10.3 million in 2002. The lower earnings in 2003
are primarily due to lower cash flows as well the inclusion of
$37 million Surmont compensation in 2002 net earnings.
Core Producing Areas
Kaybob
Paramount participated in 43 (20.8 net) wells in the fourth
quarter bringing the 2003 total to 74 (43.9 net) wells for the
year, resulting in 64 (35.9 net) gas wells, 8 (8.0 net) oil wells
and 2 (0 net) dry holes. This activity level is up 100 percent
from 2002, when Paramount participated in the drilling of 37
(29.76 net) wells at Kaybob. Total capital expenditures in the
Kaybob area in 2003, including facility additions and
optimization projects, were $65 million, up from approximately
$45 million in 2002.
Gas production in the Kaybob Core Area averaged 79.5 MMcf/d, and
oil and natural gas liquids production averaged 2,451 Bbl/d for
2003. Production declines in the first half of the year were a
reflection of the limited capital spending in the latter part of
2002 and in the first half of 2003 ($21 million) as cash flow was
directed to debt reduction. The increase in third and fourth
quarter spending ($44 million) resulted in the production
increases in the fourth quarter of 2003 and first quarter of
2004. Year-end exit rates for Kaybob were 90 MMcf/d and 2,400
Bbl/d; production rates are expected to increase further in 2004
to 97 MMcf/d and 2,590 Bbl/d for the year.
Paramount continued to take advantage of its existing production
and land base in the Kaybob area by exploiting new reserves in
existing fields. Most activity through the second half of 2003
and all of 2004 will be concentrated on the execution of the
downspacing program. Most of the wells drilled in this area are
within easy access to existing pipelines and gas plants, thereby
reducing finding and development costs. Proved plus probable
reserve additions in the Kaybob Core Area under NI 51-101
guidelines were 35.4 Bcf and 834 MBbl (6.73 MMBoe), more than
replacing 2003 production of 29 Bcf and 895 MBbl (5.74 MMBoe).
Costs of finding and development for the proved plus probable
reserve additions for the Kaybob area were $9.66/Boe in 2003.
Paramount will continue to increase control of its production by
operating wells and production facilities that process the
natural gas and liquids. There are currently four
Company-operated gas plants in the area that process 64 percent
of Paramount's natural gas production. Operations are underway to
consolidate two of the Paramount operated gas plants, which
should reduce operating costs without sacrificing any processing
capacity. The Kaybob North oil battery was completed in 2003;
this facility will reduce operating and processing costs related
to oil and condensate in the Kaybob area. Plans are currently
being evaluated to use this new battery as a heavy oil blending
facility, which would generate additional revenue for Paramount.
Regulatory approvals are being sought to expand the Kaybob North
oil battery to include water disposal, which will further lower
operating costs. Additional inlet compression was installed at
the Clover plant, adding 5 MMcf/d of additional processing
capacity to the plant. Sour gas field compression was added in
the Pine Creek area to allow for the production of currently
shut-in sour gas.
Grande Prairie
This operating area was previously described as the Sturgeon Lake
Core Area. Assets related to Sturgeon Lake were sold on October
1, 2003 for $54.0 million. This was a high operating cost, very
mature property with proved reserves of 2.7 MMBbl of liquids and
4.2 Bcf gas. Paramount originally purchased the Sturgeon Lake
asset in two transactions for approximately $34 million during
2001 and 2002 and estimates that it has recovered virtually all
of this in cash flow from the asset. The subsequent sale for $54
million represents an excellent return to Paramount on this
investment.
For 2003, production averaged 12.4 MMcf/d and 1,767 Bbl/d of
liquids. Despite the sale of Sturgeon Lake which reduced
production by 3.0 MMcf/d and 1,640 Bbl/d of liquids, the exit
rates were 22.4 MMcf/d and 772 Bbl/d. Production rates for gas
increased because of the successful capital program, primarily in
the Mirage and Saddle Hills fields. In 2003 Paramount drilled 45
gross wells (29.9 net) in the Grande Prairie Core Area. Also in
2003, infrastructure and limited production was added in the
Goose, Shadow and Valhalla fields that Paramount plans to exploit
with the 2004 capital program.
In Mirage, 17.3 net wells were drilled on this new Dunvegan play.
At the end of the year 7.6 MMcf/d was on production from 7.4 net
wells with an additional 1.6 wells to be tied in, 0.3 wells to
complete and the balance being evaluated. Up to 40 wells are
planned in 2004 to follow up and expand upon this play. The
successful Saddle Hills Wabamun well was producing at 9 MMcf/d at
year-end. Paramount plans to follow up with up to six more
similar deep wells in 2004.
In 2004 the new Berry Lake field in Northeast Alberta came
onstream March at 5 MMcf/d net to Paramount. Production rates may
increase if capacity in the third-party gas plant is available.
Northwest Alberta
The Northwest Alberta Core Area covers the extreme northwest
corner of Alberta, extending into the Cameron Hills in the
Northwest Territories. Two significant events for Northwest
Alberta Core Area in 2003 were the completion of the Cameron
Hills oil gathering system, battery, and liquid transportation
line situated between the Paramount operated Bistcho Lake
facility and the Zama terminal, and the discovery and tie-in of
Pekisko gas at Haro.
Paramount participated in the drilling of 23 wells (21.2 net) in
the Northwest Alberta area during the 2003 calendar year. The
vast majority of field activities relating to seismic
acquisition, drilling, and construction occurred in the first
quarter due to restricted seasonal access of the area. Annualized
2003 net average production for the region is as follows: natural
gas sales 22.3 MMcf/d, crude oil and natural gas liquids 448
Bbl/d. Divestiture of the Pedigree and West Negus properties
reduced annual gas production for the region by approximately 5
MMcf/d. An oil gathering line failure in conjunction with a wax
blockage in another pipeline resulted in Paramount realizing only
about half of the crude oil production capability of Cameron
Hills in 2003.
Focus of activity for the Northwest Alberta group in 2004 will be
at the Cameron Hills and Haro properties, with virtually all
occurring in the first quarter due to the winter-only access
nature of the area. Paramount will participate at Haro in the
drilling of 12 gas wells (7.5 net), expansion of the existing gas
handling capacity from 6 MMcf/d (1.4 MMcf/d net) to 12 MMcf/d
(5.9 MMcf/d net). The Cameron Hills oil project is being expanded
with the addition of 4 oil wells (3.5 net) and the facilities
necessary to bring those wells on production in 2004. One net gas
well will also be drilled at Cameron Hills in the first quarter.
The total number of wells in which Paramount will be
participating in the Northwest Alberta Core Area in 2004 is
expected to be 23 (15.5 net).
Liard Basin - Northeast British Columbia / Northwest Territories
Production from this operating unit averaged 11.6 MMcf/d in 2003.
At Maxhamish, the b-83-K/94-O-14 well was tied in and existing
producing wells were worked over to maximize performance. At the
Chevron-operated Liard pool, the 2K-29 location was drilled,
completed and placed on production in early May. At Clarke Lake,
two locations were drilled with one well at b-57-I/94-J-10 tied
in during December.
Exploration activity was dominated by nine locations farmed out
to Anadarko at Liard and Arrowhead, NWT. The multi-well program
included the drilling of seven Devonian and two Chinkeh locations
during the winter of 2003. Two of the Devonian locations did not
reach total depth and will finish drilling in 2004. Hydrocarbons
discovered as a result of this program have allowed Anadarko to
apply to the NEB for six significant discovery licenses to hold
expiring lands. Paramount also drilled one unsuccessful Mattson
test at K-36 located northeast of Fort Liard.
Looking forward to 2004, development activity will include
further drilling at Chevron Liard and at Clarke Lake as well as
recompletion work at Liard/Maxhamish. Exploration will expand
into other areas of Northeast British Columbia with the drilling
of various Cretaceous and Triassic plays as well as deeper
Mississippian and Devonian prospects.
Southern
The Southern Core Area is the most geographically extensive unit
of Paramount Resources, with oil and gas producing in southern
Alberta, Saskatchewan, Montana and North Dakota. The Southern
Core Area completed the consolidation and focus process in late
2003. This process has seen the area divest of smaller interest
and non-operated/non-core properties to pursue the growth of
fewer, higher interest core properties. The average production
for the year was 9.5 MMcf/d of gas, with 2,457 Bbl/d of oil and
NGLs, totalling 4,048 Boe/d. At the end of the year, the Southern
area was producing 9.8 MMcf/d of gas, with 2,018 Bbl/d of oil and
NGLs, giving a total rate of 3,643 Boe/d.
The main activities for 2003 centered in the Chain/Craigmyle
area, where 7 wells were drilled, 15 recompletions were
performed, several compressors were modified and one added,
resulting in a 30 percent increase in production for the area.
This area will also be the focus of activities for the coming
year with 17 shallow gas wells planned, and continued
modifications to the production systems.
New and reactivated production was also added in Alder Flats (56
percent increase), Enchant (5 percent increase), and Long Coulee
(100 percent increase). Late in 2003, two new wells were added at
Retlaw, which will result in production increases in the coming
year. Enchant, Long Coulee, Sylvan Lake and Retlaw will also see
further development in 2004. At Paramount-operated oil pools in
Rabbit Hills, Montana, and Lougheed, Saskatchewan, new or
enhanced waterfloods resulted in production increases of up to 20
percent. Further work is planned in both the Southeast
Saskatchewan and North Dakota oil properties in 2004.
Long Term Projects
Paramount has continued to advance its long-term projects at
Colville Lake in the Central Mackenzie Valley of the Northwest
Territories. At Colville Lake, two successful gas wells were
drilled and tested on the Nogha structure in 2003 with results
that exceeded the Company's expectations. A further well was
drilled on the Nogha prospect during the 2004 winter that has
been successfully drilled and cased. Two additional prospects
were tested during the 2004 winter drilling season with one
exploration well further north at Manoir Ridge and one
exploration well further west at West Nogha; both were
successfully drilled and cased as potential gas wells. At the
time of writing, all of the wells drilled during the winter of
2004 are undergoing completion operations. Success to date from
exploration drilling at Colville Lake is now leading to the
evaluation of several development scenarios including
participation in the Mackenzie Valley Pipeline or possibly the
construction of a 500-mile long dedicated pipeline from Norman
Wells south into Alberta to tie in to the existing pipeline
infrastructure.
Another new project for Paramount will be to test the feasibility
and potential bitumen reserves of its SAG-D projects in Northeast
Alberta. The Company executed its first drilling program to
commence the delineation of our bitumen prospects in northeast
Alberta. A total of 12 wells were drilled in the 2004 winter
program to delineate the bitumen reserves: 7 wells were drilled
at the Leismer prospect and 5 wells at the Company's Surmont
prospect.
Reserves
Paramount's reserves for the year ended December 31, 2003, were
evaluated by McDaniel and Associates ("McDaniel") who has
evaluated Paramount's reserves for the entire 25-year existence
of the Company. Commencing with the most recent year ended
December 31, 2003, Paramount's reserves have been calculated in
compliance with the new National Instrument 51-101. The new
reserve disclosure standards related to NI 51-101 require a
higher standard of confidence in reserve volumes within the
individual reserve reporting categories. In particular, proved
reserves are now defined as having a 90 percent probability that
these reserves will be recovered and probable reserves are now
defined as having at a 50 percent probability that these reserves
will be recovered. Paramount estimates that the effects of the
proved reserves revisions associated with NI 51-101 to be 5
percent of total proved reserves at the beginning of the year,
excluding the Trust.
The following table summarizes the reserves evaluated as at
December 31, 2003, using McDaniel's forecast prices and cost.
/T/
Proved and Probable Reserves
Light
and
Medium Natural
Natural Crude Gas
Reserve Category Gas Oil Liquids Boe
(Bcf) (MBbl) (MBbl) (MBoe)
Canada
Proved
Developed Producing 174.9 3,755 3,269 36,174
Developed Non-Producing 47.6 529 543 9,004
Undeveloped 18.6 437 111 3,648
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Total Proved 241.1 4,721 3,923 48,827
Probable 87.7 1,271 479 16,367
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Total Proved Plus Probable Canada 328.8 5,992 4,402 65,194
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United States
Proved
Developed Producing 0.5 1,971 2 2,056
Developed Non-Producing - - - -
Undeveloped - - - -
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Total Proved 0.5 1,971 2 2,056
Probable 0.1 143 3 163
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Total Proved Plus Probable US 0.6 2,114 5 2,219
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Total Company
Total Proved 241.7 6,692 3,925 50,883
Total Probable 87.7 1,414 482 16,530
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Total Reserves 329.4 8,106 4,407 67,413
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Before Tax Net Present Value
($ millions)
Reserve Category Discount Rate
0% 5% 10%
Canada
Proved
Developed Producing 636.9 545.8 483.0
Developed Non-Producing 140.1 101.7 79.9
Undeveloped 59.2 34.7 22.6
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Total Proved 836.2 682.2 585.5
Probable 267.9 184.9 135.2
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Total Proved Plus Probable Canada 1,104.1 867.1 720.7
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United States
Proved
Developed Producing 15.7 13.7 12.2
Developed Non-Producing (0.3) (0.3) (0.3)
Undeveloped - - -
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Total Proved 15.4 13.4 11.9
Probable 1.6 1.3 1.0
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Total Proved Plus Probable US 17.0 14.7 12.9
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Total Company
Total Proved 851.6 695.6 597.4
Total Probable 269.5 186.2 136.2
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Total Reserves 1,121.1 881.8 733.6
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(Columns may not add due to rounding)
/T/
Reserve Reconciliation for Year-end 2003
Paramount's reserves reflected the dispositions of virtually all
of Paramount's assets in northeast Alberta to the Trust, the
Sturgeon Lake assets and additional minor non-core assets, all of
which occurred during 2003. As well, Paramount's reserve
disclosure for the year ended 2003 is now evaluated using the
newly implemented standards of disclosure defined by NI 51-101.
Total proved reserves at year end 2003 stood approximately 242
Bcf and 10.6 MMBbl or 51 MMBoe and proved plus probable reserves
were 329 Bcf and 12.5 MMBbl or 67.4 MMBoe.
The following table sets forth the reconciliation of Paramount's
gross reserves for the year ended December 31, 2003, as evaluated
by McDaniel using forecast prices. We have reconciled our
reserves to January 1, 2003, proved plus 50 percent of probable
reserves (Established reserves). Gross reserves include working
interest reserves before royalties.
/T/
Reserves (Company share before royalty)
Proved Reserves Probable Reserves
Oil Oil
& &
Gas NGL Boe Gas NGL Boe
Bcf MBbl MBoe Bcf MBbl MBoe
Paramount Resources
Ltd. January 1, 2003
(excl Trust) 282.3 17,545 64,595 66.4 2,650 13,717
Paramount Energy
Trust, Jan. 1, 2003 164.3 - 27,367 19.7 - 3,283
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Total Reserves Jan
1, 2003(1) 446.5 17,545 91,961 86.1 2,650 17,000
Divestments
Paramount Energy Trust 158.4 - 26,400 19.7 - 3,283
Sturgeon Lake 3.4 2,147 2,714 0.6 347 447
Minor Divestments 12.8 2,462 4,595 2.0 225 558
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Total 2003
Divestments(2) (174.6) (4,609) (33,709) (22.3) (572) (4,288)
Total 2003
Acquisitions 1.6 - 267 0.1 - 17
2003 Capital Program
Additions 52.3 1,428 10,145 11.2 251 2,118
Total 2003 Production (55.8) (2,617) (11,917) - - -
Technical Revisions(3) (10.4) (937) (2,670) 12.6 (433) 1,667
Revisions due to NI
51-101(4) (17.9) (193) (3,176) - - -
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Total Revisions (28.3) (1,130) (5,847) 12.6 (433) 1,667
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Total Reserves Jan.
1, 2004 241.7 10,617 50,900 87.7 1,896 16,513
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Reserves (Company share before royalty)
Proved + Probable Reserves
Oil
&
Gas NGL Boe
Bcf MBbl MBoe
Paramount Resources Ltd. January 1, 2003
(excl Trust) 348.7 20,195 78,312
Paramount Energy Trust, Jan. 1, 2003 183.9 - 30,650
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Total Reserves Jan 1, 2003(1) 532.6 20,195 108,962
Divestments
Paramount Energy Trust 178.1 - 29,683
Sturgeon Lake 4.0 2,494 3,161
Minor Divestments 14.8 2,687 5,153
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Total 2003 Divestments(2) (196.9) (5,181) (37,997)
Total 2003 Acquisitions 1.7 - 284
2003 Capital Program Additions 63.5 1,679 12,263
Total 2003 Production (55.8) (2,617) (11,917)
Technical Revisions(3) 2.2 (1,370) (1,003)
Revisions due to NI 51-101(4) (17.9) (193) (3,176)
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Total Revisions (15.7) (1,563) (4,180)
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Total Reserves Jan. 1, 2004 329.4 12,513 67,413
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(Columns may not add due to rounding)
(1) January 1, 2003 reserves are proved plus half probable
(2) Total 2003 divestitures net of reported production in 2003
(3) Paramount estimates of conventional technical revisions
(4) Paramount estimates of revisions due to NI 51-101
/T/
Finding and Development Costs
Paramount has calculated the capital associated with the 2003
reserve additions and as such has excluded two separate
expenditures. The first is the $23.3 million of expenditure
associated with properties which were disposed during the year.
Capital expenditures in this category were almost entirely
related to the Ells property and the Sturgeon Lake property,
which were both sold during the year. The other capital excluded
from the finding and development cost calculation was the $5.8
million associated with the exploration at Colville Lake. This
capital will be included in the finding and development
calculation during the year in which reserves are first booked
for Colville Lake by the Company. In addition, capital was
reduced by $5.0 million to reflect the net increase in the value
of our undeveloped acreage inventory. Future capital of $2.4
million to fully develop the booked proved reserves, and $3.3
million to fully develop the booked proved and probable reserves,
were included in the finding and development calculation.
Paramount's finding and development costs for new reserve
additions were calculated to be $18.93/Boe for proved reserves
and $15.73/Boe for proved plus probable reserves. Finding and
development costs at Kaybob in 2003 of $9.66/Boe were in line
with expectations. Paramount has allocated approximately 50
percent of its 2004 capital budget to a continuation of the
downspacing program in the Kaybob area and will positively
influence Paramount's 2004 finding and development costs.
/T/
Proved + Proved + Proved +
Proved Proved Proved Probable Probable Probable
Capital Reserves F&D Capital Reserves F&D
($MM) MBoe $/Boe ($MM) Mboe $/Boe
---------------------------------------------------------------------
Finding and
Development
Costs
------------
Extensions
and
discoveries $192.0 10,145 $18.93 $192.9 12,262 $15.73
---------------------------------------------------------------------
/T/
Outlook
Paramount has budgeted a total of $240 million for capital
expenditures for 2004 with the expectation that this will allow
us to increase production from Q3 2003 exit levels of 130 MMcf/d
and 6,000 Bbl/d (28,000 Boe/d) to average 160 MMcf/d and 6,000
Bbl/d (32,500 Boe/d) in 2004 with an anticipated 2004 exit rate
higher than the annual average. Cash flow in 2004 is forecast to
be about $240 million or approximately $4.00/share, which is
essentially equal to the capital expenditure budget. New
short-term additions in production will be principally in the
Kaybob and Grande Prairie core areas. The Kaybob downspacing
program will continue with $100 million budgeted to drill 70
wells throughout 2004. Grande Prairie has a budget of $50 million
to drill 65 wells predominantly targeting the repetition of the
successful shallow Dunvegan gas play as well as six new deep
Wabamun prospects that have been identified. The capital activity
at the Liard, Southern, and Northwest Core Areas is expected to
be sufficient to replace declines through the year. With visible
short-term growth, principally at Kaybob and Grande Prairie,
combined with an exciting portfolio of long-term prospects,
Paramount considers its value creation potential for shareholders
to be unparalleled.
Advisory Regarding Reserves Data and Other Oil and Gas
Information
In this news release, certain natural gas volumes have been
converted to Boe on the basis of six thousand cubic feet (Mcf) to
one barrel (Bbl). Boe may be misleading, particularly if used in
isolation. A Boe conversion ration of 6 Mcf:1 Bbl is based on an
energy equivalency conversion method primarily applicable at the
burner tip and doers not represent equivalency at the well head.
The aggregate of the exploration and development costs incurred
in the most recent financial year and the change during that year
in estimated future development costs generally will not reflect
total finding and development costs related to reserves additions
for that year.
Advisory Regarding Forward-Looking Statements
This news release contains forward-looking statements within the
meaning of applicable securities laws. Forward-looking statements
include estimates, plans, expectations, opinions, forecasts,
projections, guidance or other statements that are not statements
of fact. The forward-looking statements in this news release
include statements with respect to future production, capital
expenditures, drilling, operating costs, cash flow, and the
magnitude of oil and natural gas reserves. Although the Company
believes that the expectations reflected in such forward-looking
statements are reasonable, undue reliance should not be placed on
them because we can give no assurance that such expectations will
prove to have been correct. Factors that could cause actual
results to differ materially from those set forward in the
forward looking statements include general economic business and
market conditions, fluctuations in interest rates, production
estimates, our future costs, future crude oil and natural gas
prices, and our reserve estimates. The Company's forward-looking
statements are expressly qualified in their entirety by this
cautionary statement. We undertake no obligation to update our
forward-looking statements except as required by law.
A conference call will be held with the senior management of
Paramount Resources Ltd. to answer questions with respect to the
year-end results at 9:00 a.m. MST on Thursday, March 25, 2004. To
participate please call 1- 877-211-7911 or 1-416-405-9310
approximately 15 minutes before the call is to begin.
The conference call will be live webcast from
www.paramountres.com or www.companyboardroom.com.
A replay of the conference call will be available within an hour
of the call for seven days: until April 1, 2004. The number for
the replay is 1-800-408-3053 or 1-416-695-5800 with passcode
number 3027074.
The conference call will be available for replay on the Company
website, www.paramountres.com within two hours of the webcast.
Paramount is a Canadian oil and natural gas exploration,
development and production company with operations focused in
Western Canada. Paramount's common shares are listed on the
Toronto Stock Exchange under the symbol "POU".
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD & A")
Paramount Resources Ltd. ("Paramount" or the "Company") is
pleased to report its financial and operating results for the
year ended December 31, 2003.
The following discussion of financial position and results of
operations should be read in conjunction with the consolidated
financial statements and related notes for the year ended
December 31, 2003. The consolidated financial statements have
been prepared in Canadian dollars and in accordance with Canadian
generally accepted accounting principles ("GAAP"). A
reconciliation to United States GAAP is included in Note 18 to
the consolidated financial statements.
This MD&A contains forward-looking statements within the meaning
of applicable securities laws. Forward-looking statements include
estimates, plans, expectations, opinions, forecasts, projections,
guidance or other statements that are not statements of fact. The
forward-looking statements in this MD&A include statements with
respect to, among other things: Paramount's business strategy,
Paramount's intent to control marketing and transportation
activities, the weighting of Paramount's production toward
natural gas, reserve estimates, production estimates, hedging
policies, site restoration costs, the size of available income
tax pools, the renewal of the Company's credit facility, the
funding sources for the Company's capital expenditure program,
cash flow estimates, environmental risks faced by the Company and
compliance with environmental regulations, commodity prices, and
the impact of the adoption of various Canadian Institute of
Chartered Accountants Handbook Sections and Accounting
Guidelines.
Although Paramount believes that the expectations reflected in
such forward-looking statements are reasonable, undue reliance
should not be placed on them because the Company can give no
assurance that such expectations will prove to have been correct.
There are many factors that could cause forward-looking
statements not to be correct, including known and unknown risks
and uncertainties inherent in the Company's business. These risks
include, but are not limited to: crude oil and natural gas price
volatility, exchange rate and interest rate fluctuations,
availability of services and supplies, market competition,
uncertainties in the estimates of reserves, the timing of
development expenditures, production levels and the timing of
achieving such levels, the Company's ability to replace and
expand oil and gas reserves, the sources and adequacy of funding
for capital investments, future growth prospects and current and
expected financial requirements of the Company, the cost of
future dismantlement and site restoration, the Company's ability
to enter into or renew leases, the Company's ability to secure
adequate product transportation, changes in environmental and
other regulations, the Company's ability to extend its debt on an
ongoing basis, and general economic conditions. The Company's
forward-looking statements are expressly qualified in their
entirety by this cautionary statement. We undertake no obligation
to update our forward-looking statements except as required by
law.
In this MD&A, certain natural gas volumes have been converted to
barrels of oil equivalent (Boe) on the basis of six thousand
cubic feet (Mcf) to one barrel (Bbl). Boe may be misleading,
particularly if used in isolation. A Boe conversion ratio of 6
Mcf=1 Bbl is based on an energy equivalency conversion method,
primarily applicable at the burner tip and does not represent
equivalency at the well head.
The date of this MD&A is March 12, 2004.
Additional information on the Company, including the Annual
Information Form, can be found on the SEDAR website at
www.sedar.com.
Paramount is an exploration, development and production company
with established operations in Alberta, British Columbia,
Saskatchewan, the Northwest Territories, Montana, North Dakota
and California. Management's strategy is to maintain a balanced
portfolio of opportunities, to grow reserves and production in
the Company's core areas while maintaining a large inventory of
undeveloped acreage, to focus on natural gas as a commodity, and
to selectively enter into joint venture agreements for high
risk/high return prospects.
SIGNIFICANT EVENTS
- Creation of Paramount Energy Trust (the "Trust")
In 2002, the Company announced its intention to create an
independent energy trust, providing shareholders with an
investment which would complement Paramount's historical
exploration and development strategy.
1. On February 3, 2003, Paramount transferred to the Trust assets
in the Legend area of Northeast Alberta for net proceeds of $28
million, which was paid to Paramount on March 11, 2003, and
9,907,767 units of the Trust.
2. On February 3, 2003, Paramount declared a dividend-in-kind of
an aggregate of 9,907,767 units of the Trust. The dividend was
paid to holders of Paramount common shares of record on the close
of business on February 11, 2003. The dividend was declared after
the Trust received all regulatory clearances with respect to its
final prospectus in Canada and its registration statement in the
United States. The final prospectus and registration statement
qualified and registered (i) the dividend trust units, (ii)
rights to purchase further trust units, which rights were issued
to unitholders after the payment of the dividend, and (iii) the
trust units issuable upon the exercise of the rights.
3. On March 11, 2003, in conjunction with the closing of a rights
offering by the Trust, Paramount disposed of additional assets in
Northeast Alberta to Paramount Operating Trust for consideration
of $167 million, including adjustments to the purchase price. The
combined production of natural gas including the assets in the
Legend area averaged 97 MMcf/d during 2002.
The closing of the above transactions in the first quarter of
2003 represent the completion of the formation and structuring of
Paramount Energy Trust.
- Disposition of the Sturgeon Lake property
On October 1, 2003, Paramount sold its interest in the Sturgeon
Lake property, including the associated oil batteries and gas
plants, for total consideration of $54.0 million. Production from
the Sturgeon Lake assets averaged 1,640 Bbl/d of oil and natural
gas liquids and 2,965 Mcf/d of natural gas for the nine months
ended September 30, 2003. A pre-tax gain on sale of property and
equipment of $18.7 million was recorded on the disposition.
- Issuance of US$175 million of medium-term senior notes
On October 27, 2003, the Company closed an offering of US$175
million in senior unsecured notes. The notes bear interest at 7
7/8 percent, and mature on October 27, 2010. The offering allowed
Paramount to diversify its sources of financing and expand its
financial flexibility.
- Sale of non-core properties
During 2003, the Company successfully executed a disposition
program consisting of minor, non-core producing and non-producing
properties for total consideration of $71.2 million.
/T/
REVENUE & PRODUCTION
---------------------------------------------------------------------
Revenue (thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Natural gas $ 333,924 $ 311,438 $ 481,436
Oil and natural gas liquids 100,135 72,750 28,442
---------------------------------------------------------------------
Petroleum and natural gas revenue 434,059 384,188 509,878
Commodity hedging gain (loss) (53,204) 46,813 15,808
Gain (loss) on investments (1,020) 40,830 2,982
Other 2,012 2,111 (295)
---------------------------------------------------------------------
Gross revenue $ 381,847 $ 473,942 $ 528,373
---------------------------------------------------------------------
/T/
Petroleum and natural gas revenue totaled $434.1 million in 2003,
as compared to $384.2 million in 2002 (2001 - $509.9 million).
The increase in revenue is due to higher commodity prices,
mitigated partially by lower natural gas production volumes as
compared to the prior year. Natural gas production volumes
averaged 153 MMcf/d in 2003, a 37 percent decrease from the 241
MMcf/d produced in 2002 (2001 - 225 MMcf/d), primarily as a
result of the disposition of Northeast Alberta assets to the
Trust (the "Trust assets") in the first quarter of 2003, as well
as other property dispositions closed during the year. Production
from the Trust assets averaged 97 MMcf/d in 2002. Stronger
natural gas demand resulted in an increase of 70 percent in
Paramount's average natural gas sales price before hedging to
$5.99/Mcf as compared to $3.53/Mcf in 2002 (2001 - $5.93/Mcf).
Paramount's average natural gas price after hedging was $5.16/Mcf
as compared to $4.08/Mcf in 2002 (2001 - $6.12/Mcf).
Oil and natural gas liquids ("NGL") prices before hedging
averaged $38.27/Bbl in 2003, as compared to $35.20/Bbl in 2002
(2001 - $35.48/Bbl). Oil and NGL production increased 27 percent
to average 7,169 Bbl/d in 2003 as compared to 5,663 Bbl/d in 2002
(2001 - 2,165 Bbl/d). This increase is attributable to the
inclusion in 2003 results of a full year of production from the
assets obtained through the acquisition of Summit Resources
Limited ("Summit").
Paramount's 2003 production profile continues to be significantly
weighted to natural gas, despite the acquisition of Summit in
2002. Summit production was approximately 60 percent natural gas
and 40 percent oil and NGL at the time of acquisition. In 2003
natural gas production contributed 78 percent of Paramount's
total production compared to 88 percent in 2002 (2001 - 95
percent). With the disposition of the Sturgeon Lake property in
the fourth quarter of 2003, the Company expects 2004 production
to continue to be strongly weighted towards natural gas.
Fourth quarter petroleum and natural gas revenue before hedging
totaled $86.1 million as compared to $135.0 million for the
comparable quarter in 2002 (2001 - $65.1 million). The decrease
in revenue is due to lower production volumes, mitigated
partially by higher commodity prices before hedging. Natural gas
production volumes averaged 141 MMcf/d during the fourth quarter,
a decrease of 46 percent as compared to 263 MMcf/d for the
comparable quarter in 2002 (2001 - 218 MMcf/d). Lower natural gas
production is a result of the disposition of the Trust assets,
the completion of a successful disposition program of non-core,
non-operated natural gas properties, and lower production levels
in the Kaybob area in comparison to the fourth quarter of 2002.
Oil and NGL sales averaged 5,877 Bbl/d in the fourth quarter of
2003 as compared to 8,552 Bbl/d for the comparable quarter in
2002 ( 2001 - 2,002 Bbl/d). Decreased oil and NGL production is
primarily due to the sale of Sturgeon Lake and other minor oil
properties in the current year, partially offset by new oil
production at Cameron Hills.
The Alberta Securities Commission released National Instrument
51-101 (the "Instrument") in 2003, with an effective date of
September 30, 2003. The Instrument requires all reported
petroleum and natural gas production to be measured in marketable
quantities, with adjustments for heat content included in the
commodity price reported. The Company has adopted the Instrument
prospectively. As such, fourth quarter natural gas production
volumes are measured in marketable quantities, with adjustments
for heat content and transportation reflected in the reported
natural gas price.
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 would not exceed 50 percent of Paramount's
current production volumes.
At December 31, 2003, Paramount had the following commodity price
hedges in place:
/T/
---------------------------------------------------------------------
AECO Price Term
---------------------------------------------------------------------
10,000 GJ/d $7.35 January 2004 - March 2004
10,000 GJ/d $6.26 January 2004 - March 2004
10,000 GJ/d $6.14 January 2004 - March 2004
20,000 GJ/d $6.51 January 2004 - March 2004
10,000 GJ/d $5.55 April 2004 - October 2004
10,000 GJ/d $5.51 April 2004 - October 2004
---------------------------------------------------------------------
WTI
---------------------------------------------------------------------
1,000 Bbl/d US$24.07 May 2002 - April 2004
1,000 Bbl/d US$25.00 - $30.25 collar January 2004 - December 2004
---------------------------------------------------------------------
/T/
Had these financial contracts been settled on December 31, 2003,
using prices in effect at that time, the mark to market before
tax loss would have totaled $1.6 million.
Subsequent to year end, the Company entered into the following
hedging arrangements:
/T/
---------------------------------------------------------------------
AECO Price Term
---------------------------------------------------------------------
20,000 GJ/d $5.80 April 2004 - October 2004
10,000 GJ/d $5.81 April 2004 - October 2004
10,000 GJ/d $5.86 April 2004 - October 2004
10,000 GJ/d $5.25 - $6.80 collar April 2004 - October 2004
10,000 GJ/d $5.25 - $6.75 collar April 2004 - October 2004
---------------------------------------------------------------------
/T/
Commodity hedging gains and losses are recorded based on monthly
cash settlements with counterparties. Where hedging contracts are
terminated before the end of the contract, the resulting payment
or cash receipt is recorded as deferred revenue or deferred
hedging loss on the Company's balance sheet and amortized into
income over the initial life of the contract.
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 also has in place foreign exchange hedges, which have
fixed the exchange rate on US $24.4 million for CDN $34.9 million
over the next two years at CDN $1.4335. For the year ended
December 31, 2003, gross revenue included gains from foreign
currency hedging activity of $0.5 million (2002 - $3.4 million
loss and 2001 - $1.7 million loss). At December 31, 2003, the
estimated fair value of these hedges based on the Company's
assessment of available market information was $3.3 million.
During 2003, approximately 75 percent of Paramount's natural gas
sales were under long-term contracts to gas aggregators and
direct-sales purchasers as compared to 43 percent and 42 percent
for 2002 and 2001, respectively. The increase in the percentage
is due to the lower production volumes as a result of the
transfer of the Trust assets in early 2003. Despite transferring
approximately 97 MMcf/d of natural gas production to the Trust,
Paramount kept the majority of the long-term contracts for
natural gas sales.
/T/
NETBACKS
---------------------------------------------------------------------
Netbacks ($/Boe) 2003 2002 2001
---------------------------------------------------------------------
Gross revenue before hedging $ 36.53 $ 25.50 $ 35.40
Royalties 6.93 4.44 6.89
Operating costs 6.82 5.14 4.22
---------------------------------------------------------------------
Operating netback 22.78 15.92 24.29
---------------------------------------------------------------------
Commodity hedging loss (gain) 4.47 (2.79) (1.09)
General and administrative(1) 1.57 0.95 0.85
Bad debt expense 0.50 - -
Lease rentals 0.30 0.27 0.30
Interest on long-term debt(2) 1.66 1.43 1.33
Current and Large Corporations
tax 0.24 0.55 1.92
---------------------------------------------------------------------
Cash flow netback $ 14.04 $ 15.51 $ 20.98
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Net of non-cash general and administrative expenses.
(2) Net of non-cash interest expense.
/T/
GAIN (LOSS) ON SHORT-TERM INVESTMENTS
In 2003 Paramount experienced a loss on short-term investments of
$1.0 million, as compared to a gain of $40.8 million in 2002. In
the second quarter of 2003, Paramount wrote off its investment in
Jurassic Oil and Gas Ltd, a private exploration company based in
Calgary. 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.
/T/
ROYALTIES
---------------------------------------------------------------------
Royalties (thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Crown royalties $ 79,496 $ 71,535 $ 94,253
Other royalties 3,516 3,658 5,953
---------------------------------------------------------------------
83,012 75,193 100,206
Alberta Royalty Tax Credit (500) (749) (500)
---------------------------------------------------------------------
Net royalties $ 82,512 $ 74,444 $ 99,706
---------------------------------------------------------------------
---------------------------------------------------------------------
Average corporate royalty rate as a
percentage of petroleum and natural
gas revenue before hedging 19.0% 19.4% 19.6%
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
For 2003, net royalties increased to $82.5 million from $74.4
million in 2002 (2001 - $99.7 million) due to higher natural gas
prices. As a percentage of revenue, Paramount's corporate royalty
rate is substantially unchanged from the prior year, at 19.0
percent compared to 19.4 percent in 2002.
Fourth quarter royalties totaled $10.7 million as compared to
$28.2 million for the fourth quarter in 2002 (2001 - $12.4
million). The decrease in royalty costs reflects the decrease in
production volumes offset partially by higher commodity prices.
/T/
OPERATING EXPENSES
---------------------------------------------------------------------
Operating Expenses (thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Operating expenses $81,193 $86,067 $61,045
---------------------------------------------------------------------
---------------------------------------------------------------------
Net operating expenses per Boe $ 6.82 $ 5.14 $ 4.22
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Paramount's 2003 operating expenses decreased 6 percent to $81.2
million from $86.1 million in 2002 (2001 - $61.0 million). On a
units-of-production basis, operating costs increased to $6.82/Boe
from $5.14/Boe in 2002 (2001 - $4.22/Boe). The Company
experienced a general increase in the costs of goods and services
including higher labour and energy costs. These increases,
combined with a decrease in production, resulted in the Company
having higher than expected unit operating expenses. Paramount
constructs and operates plant facilities and gathering systems as
a corporate strategy in order to control the flow of its natural
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.
Fourth quarter operating costs decreased to $22.3 million as
compared to $23.5 million a year earlier, primarily due to the
decreased well and production base resulting from the sale of the
Trust assets and other assets earlier in 2003. Fourth quarter
operating costs increased on a units-of-production basis to
$8.25/Boe from $4.88/Boe for the comparable quarter in 2002. The
increase in unit operating costs is primarily a result of charges
stemming from the settlement of a dispute with a facility
operator, as well as post-closing adjustments related to the
Sturgeon Lake property sale incurred during the quarter.
/T/
GENERAL AND ADMINISTRATIVE EXPENSES
---------------------------------------------------------------------
General and Administrative Expenses
(thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Gross general and administrative
expenses $ 31,539 $ 30,868 $ 26,374
Operating recoveries (12,855) (15,238) (15,766)
---------------------------------------------------------------------
General and administrative expenses
before stock-based compensation 18,684 15,630 10,608
Stock-based compensation expenses 1,214 582 1,738
---------------------------------------------------------------------
Net general and administrative
expenses $ 19,898 $ 16,212 $ 12,346
---------------------------------------------------------------------
---------------------------------------------------------------------
Net general and administrative
expenses per Boe $ 1.67 $ 0.97 $ 0.85
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
General and administrative expenses, net of operating recoveries
and before stock-based compensation expenses, increased to $18.7
million in 2003 as compared to $15.6 million in 2002 (2001 -
$10.6 million). General and administrative costs,
post-disposition of Trust assets, did not decrease, as Paramount
has increased its head office staffing levels in order to enable
the Company to identify and develop new core areas and build its
production portfolio. This initiative has resulted in Paramount
advancing its long-term projects such as Colville Lake, Northeast
Alberta bitumen and coal bed methane, and developing successful
new fields in existing core areas within Grande Prairie and
Northwest Alberta. The Company has also increased administrative
staff levels to ensure compliance with new corporate and
reporting obligations in Canada and the United States; certain of
these are a result of the US debt offering closed in 2003.
Operating recoveries are lower in 2003 by comparison to the prior
year due to a lower well count and reduced field staff, as a
result of the disposition of the Trust assets and other assets in
2003. Paramount does not capitalize any general and
administrative expenses.
In 2003, Paramount adopted the new recommendation of the Canadian
Institute of Chartered Accountants ("CICA") related to
stock-based compensation. The recommendation has been adopted
prospectively, with no restatement of prior periods. As a result,
the Company recorded a non-cash provision of $1.2 million in the
fourth quarter in respect of stock options granted during 2003.
Stock-based compensation expenses incurred in prior years were in
respect of the Company's Share Appreciation Rights Plan, which
was cancelled in February 2003.
/T/
INTEREST EXPENSE
---------------------------------------------------------------------
Interest Expense (thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Interest expense $ 19,917 $ 23,943 $ 19,291
Total debt, December 31 $298,561 $539,270 $316,600
Average debt outstanding for the period $340,919 $448,951 $295,456
---------------------------------------------------------------------
/T/
Interest expense decreased to $19.9 million in 2003 from $23.9
million in 2002 (2001 - $19.3 million). The decrease reflects
lower average debt levels for the Company in 2003 as a result of
the disposition of the Trust assets, offset somewhat by the
higher cost of borrowing of the US$ notes in the current year.
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. Other exploration costs, including geological and
geophysical costs and annual lease rentals, are charged to
exploration expense as incurred. For 2003, dry hole costs
amounted to $36.6 million as compared to $120.1 million in 2002
(2001 - $8.9 million). The 2003 provision includes $6.1 million
of costs associated with wells drilled in the current year and
$30.5 million associated with exploratory wells drilled in Canada
and the United States in previous years, which the Company has
determined will not be capable of production in economic
quantities.
Geological and geophysical expenses decreased during 2003 to $8.5
million from $9.3 million in the previous year (2001 - $10.6
million).
DEPLETION, DEPRECIATION AND AMORTIZATION
The current year provision for depletion and depreciation expense
totaled $163.4 million as compared to $169.4 million in 2002
(2001 - $105.4 million). Depletion and depreciation expense
includes expired lease costs of $10.2 million. On a
units-of-production basis, depletion and depreciation costs
averaged $13.72/Boe as compared to $10.11/Boe in 2002 (2001 -
$7.28/Boe). Depletion rates in 2003 were affected by the Summit
acquisition and the addition of capital costs previously excluded
from the depletable base.
Capital costs associated with undeveloped land of $147 million
and non-producing petroleum and natural gas properties of $62
million totaling $209 million are excluded from capital costs
subject to depletion in 2003 (2002 - $367 million).
FUTURE SITE RESTORATION AND ABANDONMENT COSTS
On an annual basis the Company reviews the liability for future
site restoration and abandonment costs. For 2003 the provision
totaled $4.5 million as compared to $3.4 million in 2002. At
December 31, 2003, the Company's estimates for site restoration
of its petroleum and natural gas properties totaled approximately
$57 million (2002 - $58 million), of which $21.1 million is
currently reflected as an accumulated provision in the financial
statements (2002 - $23.0 million).
WRITE-DOWN OF PETROLEUM AND NATURAL GAS PROPERTIES
The Company has recorded a provision of $10.4 million in 2003
(2002 - $31.3 million) in respect of impairment in certain
non-core properties in Alberta, Saskatchewan and Montana.
INCOME TAXES
In 2003, Paramount recorded Large Corporations and other tax
expense of $2.9 million as compared to $9.2 million in 2002. The
2002 tax expense includes approximately $5.7 million in respect
of prior year tax assessments.
In 2003, the Alberta provincial and Canadian federal governments
introduced legislation to reduce corporate income taxes. The
changes are considered substantively enacted for the purposes of
Canadian GAAP and, accordingly, the Company has recorded a future
income tax benefit of $30.3 million in the current year.
The future income tax recovery recorded for 2003 totaled $62.2
million, as compared to $46.9 million in 2002.
/T/
---------------------------------------------------------------------
Estimated Income Tax Pools (millions of dollars) December 31, 2003
---------------------------------------------------------------------
Undepreciated capital costs (UCC) $ 215
Canadian oil and gas property expenses (COGPE) 25
Canadian exploration expenses (CEE) 68
Canadian development expenses (CDE) 166
Other 21
---------------------------------------------------------------------
Total estimated income tax pools $ 495
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Paramount has available approximately $495 million of unutilized
tax pools at December 31, 2003. These tax pools will be available
for deduction in 2004 in accordance with Canadian income tax
regulations at varying rates of amortization.
/T/
CASH FLOW AND EARNINGS
---------------------------------------------------------------------
(thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Cash flow from operations $ 167,276 $ 259,916 $ 303,937
Cash flow from operations per share
- basic $ 2.78 $ 4.37 $ 5.11
- diluted $ 2.77 $ 4.36 $ 5.11
---------------------------------------------------------------------
Net earnings $ 2,633 $ 10,307 $ 118,902
Earnings per share - basic $ 0.04 $ 0.17 $ 2.00
- diluted $ 0.04 $ 0.16 $ 2.00
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Paramount's cash flow from operations decreased 36 percent to
$167.3 million from $259.9 million in 2002. Lower cash flows were
primarily a result of $53 million in commodity hedging losses in
2003 as opposed to $47 million in commodity hedging gains in
2002, partially offset by a $50 million increase in petroleum and
natural gas revenues due to higher commodity prices. A $40
million gain on sale of the investment in Peyto Exploration was
also included in 2002 cash flows.
Fourth quarter cash flow totaled $43.2 million, a decrease of 30
percent from $62.1 million during the same period in 2002 (2001 -
$47.7 million). The decrease in cash flow is a result of lower
production levels as compared to the fourth quarter of 2002.
The Company recorded net earnings of $2.6 million, as compared to
net earnings of $10.3 million in 2002. The lower earnings in 2003
are primarily due to lower cash flows, as well as the inclusion
of $37 million Surmont compensation in 2002 net earnings.
QUARTERLY INFORMATION
Historical quarterly information, prepared by the Company in
Canadian dollars and in accordance with GAAP, is as follows:
/T/
Fiscal 2003 Three Months Ended
(thousands of dollars,
except per share amounts) Dec 31 Sep 30 Jun 30 Mar 31
---------------------------------------------------------------------
Net revenues $ 77,697 $ 66,004 $ 65,127 $ 90,507
Net earnings (loss) $ 11,296 $ (7,851) $ (1,436) $ 624
Net earnings (loss)
per common share - basic $ 0.18 $ (0.13) $ (0.02) $ 0.01
- diluted $ 0.18 $ (0.13) $ (0.02) $ 0.01
---------------------------------------------------------------------
Fiscal 2002 Three Months Ended
(thousands of dollars,
except per share amounts) Dec 31 Sep 30 Jun 30 Mar 31
---------------------------------------------------------------------
Net revenues $110,180 $ 95,780 $ 110,206 $ 83,332
Net earnings (loss) $(41,399) $ 6,180 $ 26,614 $ 18,912
Net earnings (loss)
per common share - basic $ (0.70) $ 0.10 $ 0.45 $ 0.32
- diluted $ (0.70) $ 0.10 $ 0.44 $ 0.32
---------------------------------------------------------------------
/T/
Quarterly net revenues in 2003, as compared to the same periods
in 2002, reflect lower production volumes as a result of the
disposition of the Trust assets in the first quarter of 2003,
partially offset by higher commodity prices. Quarterly net
earnings are lower in 2003 as compared to 2002 primarily due to
reduced production levels, combined with commodity hedging losses
incurred during the current year.
The net loss of $41.4 million in the fourth quarter of 2002 is
primarily due to dry hole costs and impairment charges on
non-core properties recorded in the quarter.
/T/
CAPITAL EXPENDITURES
---------------------------------------------------------------------
Capital Expenditures
(thousands of dollars) 2003 2002 2001
---------------------------------------------------------------------
Land $ 22,288 $ 6,410 $ 39,166
Geological and geophysical 8,450 9,303 10,646
Drilling 123,455 124,076 127,736
Production equipment and facilities 69,560 77,407 94,775
---------------------------------------------------------------------
Exploration and development
expenditures 223,753 217,196 272,323
---------------------------------------------------------------------
Summit Resources Limited acquisition - 251,422 -
Property acquisitions 937 28,610 19,048
Proceeds received on property
dispositions (371,601) (5,042) (5,183)
Other 1,933 2,349 1,166
---------------------------------------------------------------------
Net capital expenditures $ (144,978) $ 494,535 $ 287,354
---------------------------------------------------------------------
Property, plant and equipment,
net, December 31 $1,006,205 $1,411,961 $1,058,337
---------------------------------------------------------------------
Total assets, December 31 $1,147,848 $1,526,786 $1,176,323
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
During 2003, expenditures for exploration and development
activities totaled $223.8 million as compared to $217.2 million
in 2002 (2001 - $272.3 million). A total of 211 gross (139 net)
wells were drilled during the year, including 67 gross (41 net)
wells in the fourth quarter, compared to 135 gross (99 net) wells
in 2002 (2001 - 196 gross, 159 net).
Net capital expenditures amounted to a recovery of $145.0 million
in 2003 as compared to expenditures of $494.5 million in 2002
(2001 - $287.4 million). The Company disposed of a number of
properties during 2003, including the Trust assets, resulting in
a net capital recovery for the year.
INVESTMENTS
Short-Term Investments
The Company has the following short-term investments:
/T/
Opening Closing
2003 Purchased 2003
Shares (Sold) Shares Investment
-----------------------------------------------------------------------
Investments
Fox Creek Petroleum Corp. 2,173,162 152,000 2,325,162 $2,538,000
Invertek(1) 7,500,000 11,531,250 19,031,250 1,525,192
Spearhead Resources Inc.(2) 5,990,000
Altius Energy Corp.(3) 4,398,197
Harvest Energy Trust 200,000 200,000 2,100,000
Jurassic Oil and Gas Ltd.(4) 850,000 - 850,000 -
-----------------------------------------------------------------------
$16,551,389
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1) Investment in Invertek is through Wilson Drilling Ltd.
(2) Spearhead Resources Inc. $5 million 8 percent and $990,000 10
percent secured convertible debentures due June 1, 2004.
(3) Altius Energy Corp. US $2.7 million 14 percent secured convertible
debenture due April 9, 2005 plus accrued interest.
(4) The Company wrote off its investment in Jurassic Oil and Gas Ltd.
in 2003.
/T/
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 Drilling Partnership
Paramount owns a 99 percent interest in Shetah-Wilson Drilling
Partnership, an entity established to operate 2 drilling rigs.
The rigs are leased from an unrelated third party.
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.
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.
DEFERRED REVENUE
During 2003, Paramount recognized in revenue $10.4 million (2002
- $39.4 million; 2001 - $1.2 million) of deferred revenue
primarily related to the settlement of natural gas commodity
hedging contracts that were previously put in place to mitigate
the Company's commodity price risk. Paramount's accounting policy
recognizes these gains in the accounting years of related
production. The deferred hedging gains of $4.0 million at
December 31, 2003 will be recognized in revenue in the first
quarter of 2004.
LIQUIDITY AND CAPITAL RESOURCES
Paramount's capital structure as at December 31, 2003, was as
follows:
/T/
(thousands of dollars,
except per share amounts) Amount % $/Share(1)
---------------------------------------------------------------------
Debt
US$ senior notes $ 226,887 28 $ 3.78
Credit facility 60,350 7 1.00
Working capital deficiency 9,143 1 0.15
Other 11,324 1 0.19
---------------------------------------------------------------------
Net debt 307,704 37 5.12
Shareholders' equity 501,642 63 8.35
---------------------------------------------------------------------
Total capitalization $ 809,346 100% $13.47
---------------------------------------------------------------------
---------------------------------------------------------------------
(1)At December 31, 2003- 60,094,600 basic common shares outstanding.
/T/
Debt
On October 27, 2003, the Company closed an offering of US$175
million of senior unsecured notes due 2010. Net proceeds were
used to reduce existing bank indebtedness. The Company also has a
committed revolving/non-revolving credit facility with a
syndicate of Canadian chartered banks. The revolving nature of
the facility expires on March 31, 2004. The Company has requested
for an extension of the revolving credit facility of up to 364
days, subject to the approval of the lenders. To facilitate the
documentation of this extension, the Company has agreed to amend
the expiry date of the existing facility to April 30, 2004. To
the extent that any lenders participating in the syndicate do not
approve the 364-day extension, the amount due to those lenders
will convert to a one-year non-revolving term loan with principal
due in full on March 31, 2005. The borrowing base under this
facility was $203 million at December 31, 2003. The borrowing
base is adjusted annually by the syndicate based on a review of
the Company's financial and reserve reports; it is expected that
this adjustment will be made early in 2004. The magnitude and
direction of the adjustment are not known at this time.
The Company's working capital deficiency at December 31, 2003,
excluding shareholder loan and bank loans, was $9.1 million (2002
- $16.0 million). Paramount will likely show a working capital
deficiency on its balance sheet, as receivables related to
petroleum and natural gas sales are collected in 30 days, whereas
joint venture partners and suppliers are typically paid on 60 day
terms.
Contractual Obligations
Future contractual obligations, as at December 31, 2003, are as
follows:
/T/
Expected Payment Date
---------------------------------------------
Less
Contractual Obligations than 2-3 4-5 After
(thousands of dollars) Total 1 year years years 5 years
---------------------------------------------------------------------
US$ senior notes due
2010 $226,887 - - - $226,887
Pipeline commitments 268,686 25,692 45,808 43,773 153,413
Operating leases 35,700 4,109 8,367 8,443 14,781
---------------------------------------------------------------------
Total $531,273 $29,801 $54,175 $52,216 $395,081
---------------------------------------------------------------------
/T/
Share Capital
As at December 31, 2003, the Company's issued share capital
consisted of 60,094,600 common shares (December 31, 2002 -
59,458,600 common shares). Changes in share capital during 2002
and 2003 are as follows:
/T/
---------------------------------------------------------------------
Consideration
Common shares Number (thousands of dollars)
---------------------------------------------------------------------
Balance December 31, 2001 59,453,600 $ 189,320
Stock options exercised 5,000 72
Expenses recognized in respect
of stock-based compensation 801
---------------------------------------------------------------------
Balance December 31, 2002 59,458,600 $ 190,193
---------------------------------------------------------------------
Stock options exercised 710,000 10,317
Shares repurchased (74,000) (236)
---------------------------------------------------------------------
Balance December 31, 2003 60,094,600 $ 200,274
---------------------------------------------------------------------
/T/
In February 2003, employees of the Company exercised 710,000
stock options for total consideration of $10.3 million.
Pursuant to its Normal Course Issuer Bid, Paramount repurchased
74,000 common shares for cancellation in 2003, at an average
price of $9.53 per share. From January 1 to March 12, 2004, the
Company has repurchased a total of 701,300 common shares at an
average price of $10.86 per share. Common shares outstanding at
March 12, 2004 are 59,393,300.
For 2004, the Company expects to fund its capital expenditure
program primarily through cash flow from operations, supplemented
by available amounts under its credit facility.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has a 99 percent interest in a drilling partnership,
which has a long-term operating lease on two drilling rigs
operating in western Canada. The Company entered into the
partnership in order to secure access to drilling rigs during
peak demand periods. Future payments in respect of the operating
lease are disclosed in Note 6 to the consolidated financial
statements.
The Company's share of net operating income from the partnership
amounted to $0.1 million in 2003 (2002 - loss of $0.8 million).
These amounts have been recorded in the Company's consolidated
statements of earnings.
RELATED PARTY TRANSACTIONS
Disposition of Assets to Paramount Energy Trust
In the first quarter of 2003, the Company transferred certain
natural gas assets in Northeast Alberta to the Trust, a related
party. The transaction, described under the heading "Significant
Events", was accounted for at the net book value of the assets as
recorded in Paramount.
Note Payable to Paramount Oil and Gas Ltd.
In 2002, in order to complement existing funding for the
acquisition of Summit, the Company secured a $33 million loan
from Paramount Oil and Gas Ltd., a related entity with a
significant ownership interest in the Company. The loan was
repaid on March 7, 2003.
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 the price received by
Paramount for its oil.
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 intends to control 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 intended 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 attempts to minimize 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 intends to ensure continued compliance with
environmental legislation.
2004 OUTLOOK 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 estimates as necessary to
reflect most current information. The following analysis assesses
the magnitude of these sensitivities on the Company's 2004 cash
flow using the following base assumptions:
/T/
a) 2004 Production
Natural gas 160 MMcf/d
Crude oil/liquids 6,000 Bbl/d
b) 2004 Average Prices
Natural gas $5.68/Mcf
Crude oil/liquids (W.T.I.) US$28.00/Bbl
c) 2004 Exchange Rate (C$/US$) $0.75
/T/
The following analysis assesses the estimated impact on cash flow
with variations in production, prices, interest and exchange
rates:
/T/
---------------------------------------------------------------------
Cash Flow Effect
Sensitivity (millions of dollars)
---------------------------------------------------------------------
Gas sales change of 10 MMcf/d $ 16.6
Gas price change of $0.10/Mcf $ 4.7
Oil and natural gas liquids sales change
of 100 Bbl/d $ 0.9
Oil and natural gas liquids price change
of $1.00/Bbl (W.T.I) $ 2.3
Sensitivity to Canada/US exchange rate
fluctuation of $0.01 CDN $ 0.5
Average interest rate change of 1% $ 0.6
---------------------------------------------------------------------
/T/
CRITICAL ACCOUNTING ESTIMATES
The MD&A is based on the Company's consolidated financial
statements, which have been prepared in Canadian dollars in
accordance with GAAP. The application of GAAP requires management
to make estimates, judgments and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities, if any, at the date of the
financial statements, and the reported amounts of revenues and
expenses during the reporting period. Paramount bases its
estimates on historical experience and various other assumptions
that are believed to be reasonable under the circumstances.
Actual results could differ from these estimates under different
assumptions or conditions.
The following is a discussion of the critical accounting
estimates that are inherent in the preparation of the Company's
consolidated financial statements and notes thereto.
Accounting for Petroleum and Natural Gas Operations
Under the successful efforts method of accounting, the Company
capitalizes only those costs that result directly in the
discovery of petroleum and natural gas reserves, including
acquisitions, successful exploratory wells, development costs and
the costs of support equipment and facilities. Exploration
expenditures, including geological and geophysical costs, lease
rentals, and exploratory dry holes are charged to earnings in the
period incurred. Certain costs of exploratory wells are
capitalized pending determination that proved reserves have been
found. Such determination is dependent upon, among other things,
the results of planned additional wells and the cost of required
capital expenditures to produce the reserves found.
The application of the successful efforts method of accounting
requires management's judgment to determine the proper
designation of wells as either developmental or exploratory,
which will ultimately determine the proper accounting treatment
of the costs incurred. The results of a drilling operation can
take considerable time to analyze, and the determination that
proved reserves have been discovered requires both judgment and
application of industry experience. The evaluation of petroleum
and natural gas leasehold acquisition costs requires management's
judgment to evaluate the fair value of exploratory costs related
to drilling activity in a given area.
Reserve Estimates
Estimates of the Company's reserves included in its consolidated
financial statements are prepared in accordance with guidelines
established by the Alberta Securities Commission. Reserve
engineering is a subjective process of estimating underground
accumulations of petroleum and natural gas that cannot be
measured in an exact manner. The process relies on
interpretations of available geological, geophysical, engineering
and production data. The accuracy of a reserve estimate is a
function of the quality and quantity of available data, the
interpretation of that data, the accuracy of various mandated
economic assumptions and the judgment of the persons preparing
the estimate.
Paramount's reserve information is based on estimates prepared by
its independent petroleum consultants. Estimates prepared by
others may be different than these estimates. Because these
estimates depend on many assumptions, all of which may differ
from actual results, reserve estimates may be different from the
quantities of petroleum and natural gas that are ultimately
recovered. In addition, the results of drilling, testing and
production after the date of an estimate may justify revisions to
the estimate.
The present value of future net revenues should not be assumed to
be the current market value of the Company's estimated reserves.
Actual future prices, costs and reserves may be materially higher
or lower than the prices, costs and reserves used for the future
net revenue calculations.
The estimates of reserves impact depletion, dry hole and site
restoration expenses. If reserve estimates decline, the rate at
which the Company records depletion and site restoration expenses
increases, reducing net earnings. In addition, changes in reserve
estimates may impact the outcome of Paramount's assessment of its
petroleum and natural gas properties for impairment.
Impairment of Petroleum and Natural Gas Properties
The Company reviews its proved properties for impairment annually
on a field basis. For each field, an impairment provision is
recorded whenever events or circumstances indicate that the
carrying value of those properties may not be recoverable. The
impairment provision is based on the excess of carrying value
over fair value. Fair value is defined as the present value of
the estimated future net revenues from production of total proved
and probable petroleum and natural gas reserves, as estimated by
the Company on the balance sheet date. Reserve estimates, as well
as estimates for petroleum and natural gas prices and production
costs may change, and there can be no assurance that impairment
provisions will not be required in the future.
Unproved leasehold costs and exploratory drilling in progress are
capitalized and reviewed periodically for impairment. Costs
related to impaired prospects or unsuccessful exploratory
drilling are charged to earnings. Acquisition costs for leases
that are not individually significant are charged to earnings as
the related leases expire. Further impairment expense could
result if petroleum and natural gas prices decline in the future
of if negative reserve revisions are recorded, as it may be no
longer economic to develop certain unproved properties.
Management's assessment of, among other things, the results of
exploration activities, commodity price outlooks and planned
future development and sales impacts the amount and timing of
impairment provisions.
Future Site Restoration and Abandonment Costs
The site restoration provision recorded in the consolidated
financial statements is based on an estimate for total costs for
future site restoration and abandonment of the Company's
petroleum and natural gas properties. This estimate is based on
management's analysis of production structure, reservoir
characteristics and depth, market demand for equipment, currently
available procedures and discussions with construction and
engineering consultants. Estimating these future costs requires
management to make estimates and judgments that are subject to
future revisions based on numerous factors, including changing
technology and political and regulatory environments. Beginning
in 2004, the Company will adopt the Canadian Institute of
Chartered Accountants ("CICA") Handbook section 3110 - Asset
Retirement Obligation, which will result in changes in accounting
for site restoration and abandonment costs. See "Recent
Accounting Pronouncements" section.
Income Taxes
The Company records future tax assets and liabilities to account
for the expected future tax consequences of events that have been
recorded in its consolidated financial statements and its tax
returns. These amounts are estimates; the actual tax consequences
may differ from the estimates due to changing tax rates and
regimes, as well as changing estimates of cash flows and capital
expenditures in current and future periods. We periodically
assess the realizability of our future tax assets. If we conclude
that it is more likely than not that some portion or all of the
deferred tax assets will not be realized under accounting
standards, the tax asset would be reduced by a valuation
allowance.
RECENT ACCOUNTING PRONOUNCEMENTS
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 Company
anticipates that adoption of this pronouncement will not have a
material effect on its consolidated financial statements.
Disposal of Long-Lived Assets and Discontinued Operations
The CICA recently issued Handbook Section 3475 - Disposal of
Long-Lived Assets and Discontinued Operations, which establishes
standards for the recognition, measurement, presentation and
disclosure of the disposal of long-lived assets by
profit-oriented enterprises. It also establishes standards for
the presentation and disclosure of discontinued operations.
Although earlier adoption is encouraged, Section 3475 applies to
disposal activities initiated by a company's commitment to a plan
on or after May 1, 2003. The Company anticipates that adoption of
this pronouncement will not have a material effect on its
consolidated financial statements.
Variable Interest Entities
The CICA recently issued Accounting Guideline 15 - Consolidation
of Variable Interest Entities. The guideline requires the
consolidation of entities in which an enterprise absorbs a
majority of the entity's expected losses, receives a majority of
the entity's expected residual returns, or both, as a result of
ownership, contractual or other financial interests in the
entity. Currently, entities are generally consolidated by an
enterprise when it has a controlling financial interest through
ownership of a majority voting interest in the entity. The
guideline applies to annual and interim periods beginning on or
after November 1, 2004, except for certain disclosure
requirements. Entities should provide disclosures about variable
interest entities in which they hold significant interests for
periods beginning on or after January 1, 2004. The Company does
not expect the implementation of this guideline to have a
material impact on its financial statements.
Asset Retirement Obligation
The CICA recently issued Handbook Section 3110 - Asset Retirement
Obligation which addresses statutory, regulatory, contractual and
other legal obligations associated with the retirement of a
long-lived asset that results from its acquisition, construction,
development or normal operation.
Under Section 3110, asset retirement obligations are initially
measured at fair value at the time the obligation is incurred
with a corresponding amount capitalized as part of the asset's
carrying value and depreciated over the asset's useful life using
a systematic and rational allocation method.
On initial recognition, the fair value of an asset retirement
obligation is determined based upon the expected present value of
future cash flows. In subsequent periods, the carrying amount of
the liability would be adjusted to reflect (a) the passage of
time, and (b) revisions to either the timing or the amount of the
original estimate of undiscounted cash flows.
The change in liability due to the passage of time is measured by
applying an interest method of allocation to the opening
liability and is recognized as an increase in the carrying value
of the liability and an expense. The expense must be recorded as
an operating item in the income statement, not as a component of
interest expense. A change in the liability resulting from
revisions to either the timing or the amount of the original
estimate of undiscounted cash flows is recognized as an increase
or decrease in the carrying amount of the liability with an
offsetting increase or decrease in the carrying amount of the
associated asset.
For the year ended December 31, 2003, property, plant and
equipment would increase by $16.2 million, site restoration
liability would increase by $38.2 million and retained earnings
would decrease by $22.0 million.
Stock-Based Compensation and Other Stock-Based Payments
In December 2001, the CICA issued Handbook Section 3870 -
Stock-Based Compensation and Other Stock-Based Payments, which
requires fair value accounting for all stock-based payments to
non-employees, and for employee awards that are direct awards of
stock, or call for settlement in cash or other assets, and for
stock appreciation rights. For all other employee awards, the
present standard allows disclosure of pro forma net income and
pro forma earnings per share in the income statement. In October
2003, the CICA amended Handbook Section 3870 to require
recognition of expense, based on the fair value method, for all
employee stock-based compensation transactions for fiscal years
beginning on or after January 1, 2004.
The recommendations of the Section should also be applied to the
following awards that were outstanding at the start of the first
fiscal year beginning on or after January 1, 2002 in which
adoption of this Section was initially applied:
(a) awards that call for settlement in cash or other assets;
(b) stock appreciation rights that call for settlement by the
issuance of equity instruments; and
(c) any other award that is modified so as to become an award
included in (a) or (b) above. The award should be accounted for
as a new award, and not using modification accounting.
The cumulative amount, applicable to (a) or (b) above, that would
have been recognized in prior years had this section been
applied, less any amount previously recognized, should be
recorded as the effect of a change in accounting policy and
charged to opening retained earnings for the fiscal year in which
this section is initially applied, without restatement of prior
periods.
The Company adopted the fair-value method of accounting for stock
options for fiscal 2003. The fair-value based method will be
applied prospectively, whereby compensation costs will be
recognized for all options granted on or after January 1, 2003.
Adoption of this accounting policy has resulted in an expense of
$1.2 million being recorded in the Company's financial statements
for the year ended December 31, 2003.
/T/
Consolidated Balance Sheets
----------------------------------------------------------------------
As at December 31 (thousands of dollars) 2003 2002
----------------------------------------------------------------------
ASSETS (note 7)
Current Assets
Short-term investments
(market value: 2003 - $17,265; 2002 - $14,168) $ 16,551 $ 14,168
Accounts receivable 84,183 91,042
Prepaid expenses 2,282 9,615
----------------------------------------------------------------------
103,016 114,825
----------------------------------------------------------------------
Property, Plant and Equipment (note 5)
Property, plant and equipment 1,420,540 1,961,369
Accumulated depletion and depreciation (414,335) (549,408)
----------------------------------------------------------------------
1,006,205 1,411,961
----------------------------------------------------------------------
Goodwill (note 2) 31,621 -
Other Assets (note 8) 7,006 -
----------------------------------------------------------------------
$1,147,848 $1,526,786
----------------------------------------------------------------------
----------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 112,159 $ 130,798
Shareholder loan (note 9) - 33,000
Bank loans (note 7) 1,450 498,097
----------------------------------------------------------------------
113,609 661,895
----------------------------------------------------------------------
Long-term debt (note 8) 297,111 8,173
Provision for future site restoration
and abandonment costs 21,114 22,954
Deferred revenue (note 12) 3,959 7,804
Future income taxes (note 11) 210,413 279,855
----------------------------------------------------------------------
532,597 318,786
----------------------------------------------------------------------
Commitments and contingencies (notes 6, 12 and 14)
Shareholders' Equity
Share capital (note 10)
Issued and outstanding
60,094,600 common shares (2002- 59,458,600
common shares) 200,274 190,193
Contributed surplus 746 -
Retained earnings 300,622 355,912
----------------------------------------------------------------------
501,642 546,105
----------------------------------------------------------------------
$1,147,848 $1,526,786
----------------------------------------------------------------------
----------------------------------------------------------------------
See accompanying notes to consolidated financial statements
On behalf of the Board of Directors
C. H. Riddell J.B. Roy
Director Director
Consolidated Statements of Earnings and Retained Earnings
Three Months ended Year ended
December 31 December 31
------------------------------------------------------------------------
Years ended December 31
(thousands of dollars except
for per share amounts) 2003 2002 2003 2002
------------------------------------------------------------------------
Revenue
Petroleum and natural
gas sales $ 86,068 $ 134,608 $ 434,059 $ 384,188
Commodity hedging (loss) gain 1,541 893 (53,204) 46,813
Royalties (net of ARTC) (10,664) (28,157) (82,512) (74,444)
(Loss) gain on investments
(note 16) - 725 (1,020) 40,830
Other income 752 2,111 2,012 2,111
------------------------------------------------------------------------
77,697 110,180 299,335 399,498
------------------------------------------------------------------------
Expenses
Operating 22,287 23,474 81,193 86,067
Interest 5,604 9,727 19,917 23,943
General and administrative 5,832 5,768 19,898 16,212
Bad debt expense - - 5,977 -
Lease rentals 1,027 1,585 3,574 4,552
Geological and geophysical 3,208 1,182 8,450 9,303
Dry hole costs (note 5) 5,750 75,909 36,600 120,058
Loss (gain) on sales of
property and equipment (15,821) 121 3,660 (12)
Provision for future site
restoration and abandonment
costs 1,419 1,619 4,462 3,437
Depletion and depreciation 47,055 61,106 163,413 169,433
Write-down of petroleum and
natural gas properties
(note 5) 10,418 31,254 10,418 31,254
Unrealized foreign exchange
gain on US debt (note 12) (1,566) - (1,566) -
Surmont compensation - net
(note 15) - - - (37,291)
------------------------------------------------------------------------
85,213 211,745 355,996 426,956
------------------------------------------------------------------------
Earnings (loss) before taxes (7,516) (101,565) (56,661) (27,458)
------------------------------------------------------------------------
Income and other taxes (note 11)
Large Corporations Tax
and other 1,165 7,866 2,875 9,150
Future income tax recovery (19,977) (68,032) (62,169) (46,915)
------------------------------------------------------------------------
(18,812) (60,166) (59,294) (37,765)
------------------------------------------------------------------------
Net earnings (loss) 11,296 (41,399) 2,633 10,307
Retained earnings, beginning
of period 294,861 397,311 355,912 346,064
Adjustment on disposition of
assets to a related party
(note 4) (5,535) (6,923) -
Dividends declared (note 4) - - (51,000) -
Adoption of new accounting
policies (note 3) - - - (459)
------------------------------------------------------------------------
Retained earnings, end
of year $ 300,622 $ 355,912 $ 300,622 $ 355,912
------------------------------------------------------------------------
------------------------------------------------------------------------
Net earnings per common share
(note 10)
- basic $ 0.18 $ (0.70) $ 0.04 $ 0.17
- diluted $ 0.18 $ (0.70) $ 0.04 $ 0.16
------------------------------------------------------------------------
Weighted average common
shares outstanding
(thousands) (note 10)
- basic 60,168 59,459 60,098 59,458
- diluted 60,340 59,616 60,472 59,567
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Cash Flows
Three Months ended Year ended
December 31 December 31
------------------------------------------------------------------------
(thousands of dollars) 2003 2002 2003 2002
------------------------------------------------------------------------
Operating activities
Net earnings (loss) $ 11,296 $ (41,399) $ 2,633 $ 10,307
Add (deduct) non-cash items
Depletion and depreciation 47,055 61,106 163,413 169,433
Write-down of petroleum and
natural gas properties 10,418 31,254 10,418 31,254
Loss (gain) on sales of
property and equipment (15,821) 121 3,660 (12)
Provision for future site
restoration and abandonment
costs 1,419 1,619 4,462 3,437
Future income tax recovery (19,977) (68,032) (62,169) (46,915)
Amortization of other assets 161 342 161 -
Non-cash general and
administrative expenses 1,214 - 1,214 342
Unrealized foreign exchange
gain on US debt (1,566) - (1,566) -
Write-down of Surmont assets - - - 9,136
Add items not related to
operating activities
Surmont compensation - - - (46,427)
Dry hole costs 5,750 75,909 36,600 120,058
Geological and geophysical
costs 3,208 1,182 8,450 9,303
------------------------------------------------------------------------
Cash flow from operations 43,157 62,102 167,276 259,916
Increase (decrease) in
deferred revenue 3,218 (10,360) (3,845) 6,073
Decrease in other assets (161) (161) -
Change in non-cash operating
working capital (note 13) (20,531) (26,453) (33,381) 40,145
------------------------------------------------------------------------
25,683 25,289 129,889 306,134
------------------------------------------------------------------------
Financing activities
Bank loans - draws 33,272 19,376 43,013 153,682
Bank loans - repayments (241,320) (25,302) (477,608) (38,525)
Shareholder loan (33,000) 33,000
Proceeds from US debt net
of issuance costs 221,447 - 221,447 -
Capital stock - issued (705) - 10,317 72
Capital stock - repurchased (705) -
------------------------------------------------------------------------
12,694 (5,926) (236,536) 148,229
------------------------------------------------------------------------
Cash flow provided by operating
and financing activities 38,377 19,363 (106,647) 454,363
------------------------------------------------------------------------
Investing activities
Property, plant and equipment
expenditures (83,225) (14,615) (217,295) (209,848)
Acquisition of Summit
Resources Ltd. (note 2) - - - (251,422)
Petroleum and natural gas
property acquisitions (228) 175 (228) (28,420)
Geological and geophysical (3,208) (1,182) (8,450) (9,303)
Proceeds on sale of property,
plant and equipment 45,937 (284) 317,792 4,423
Surmont compensation - - - 46,427
Change in non-cash investing
working capital (note 13) 2,347 (3,457) 14,828 (6,960)
------------------------------------------------------------------------
Cash flow used in investing
activities (38,377) (19,363) 106,647 (455,103)
------------------------------------------------------------------------
(Decrease) increase in cash - - - (740)
Cash, beginning of year - - - 740
------------------------------------------------------------------------
Cash, end of year $ - $ - $ - $ -
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts expressed in thousands of dollars)
/T/
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 (GAAP), which differ in some respects from
GAAP in the United States. These differences are quantified in
note 18.
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. In management's opinion, the financial
statements have 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 Resources U.S. LLC, 586319 Alberta Ltd., Summit
Resources Limited, 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 shares 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 consolidated financial statements
reflect only the Company's proportionate interest in such
activities.
(c) Revenue recognition
Revenues associated with the sale of natural gas, crude oil, and
natural gas liquids ("NGL's") owned by the Company are recognized
when title passes from the Company to its customer.
Revenues from oil and natural gas production from properties in
which the Company has an interest with other producers are
recognized on the basis of the Company's net working interest.
(d) 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.
(e) Property, plant and equipment
Cost
Property, plant and equipment are recorded at cost. 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
costs 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
Depletion of petroleum and natural gas properties including well
development expenditures is provided on the unit-of production
method based on estimated proven recoverable reserves of each
producing property or project. Depreciation of production
equipment, gas plants and gathering systems is provided on a
straight-line basis over their estimated useful life varying from
12 to 40 years. Depreciation of other equipment is provided on a
declining balance method at rates varying from 4 to 30 percent.
Impairment
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 consolidated 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) Goodwill
Goodwill, which represents the excess of purchase price over fair
value of net assets acquired, is not amortized and is assessed by
the Company for impairment at least annually. Impairment is
assessed based on a comparison of the fair value of the net
assets acquired to the carrying value of the net assets,
including goodwill. Any excess of the carrying value of goodwill
over and above its fair value is the impairment amount, and is
charged to earnings in the period identified.
(h) 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 US 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.
(i) Financial instruments
The Company utilizes derivative financial instrument contracts
such as forwards, futures, swaps and options to manage its
exposure to petroleum and natural gas prices, the Canadian/U.S.
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 consolidated 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, including the commodity price, exchange rate,
and interest rate basis of 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.
(j) Measurement uncertainty
The amounts recorded for depletion and depreciation and
impairment of petroleum and natural gas properties 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
consolidated financial statements of future periods could be
material.
(k) Income taxes
The Company follows the liability method of 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.
(l) Stock option plan
The Company has a stock-based compensation plan consisting of a
stock option plan that is described in note 10.
Options granted under the Company's employee stock option plan
are issued at current market value of the Company's stock. The
fair value of the options issued is estimated at the date of
grant and the compensation expense recognized over the expected
life of the option. Consideration paid to the Company on exercise
of the stock option is credited to share capital.
(m) Per common share amounts
The Company uses the treasury stock method to determine the
dilutive effect of stock options and other dilutive instruments.
This method assumes that proceeds received from the exercise of
in-the-money stock options and other dilutive instruments are
used to purchase common shares at the average market price during
the year.
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 would 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
$249.6 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 Company has finalized the purchase price equation for this
acquisition. The following table summarizes the fair value of the
assets acquired and liabilities assumed at the date of
acquisition:
/T/
Assets
Accounts receivable $ 13,997
Petroleum and natural gas properties 419,642
Goodwill 31,621
-------------------------------------------------------------
465,260
-------------------------------------------------------------
Liabilities
Accounts payable 21,947
Future income taxes 108,373
Debt 74,513
Other liabilities 10,865
-------------------------------------------------------------
215,698
-------------------------------------------------------------
Net assets acquired $ 249,562
-------------------------------------------------------------
-------------------------------------------------------------
/T/
3. CHANGE IN ACCOUNTING POLICY
Stock-Based Compensation and Other Stock-Based Payments
The Canadian Institute of Chartered Accountants issued Handbook
Section 3870, Stock-Based Compensation and Other Stock-Based
Payments, which requires fair value accounting for all
stock-based payments to non-employees, and for employees awards
that are direct awards of stock, or call for settlement in cash
or other assets, and for stock appreciation rights.
The Company adopted the fair-value method of accounting for stock
options issued to employees and directors for fiscal 2003. For
stock options, the fair-value based method has been applied
prospectively, whereby compensation costs are recognized for all
options granted or modified on or after January 1, 2003. Adoption
of this accounting policy has resulted in an expense of $1.2
million ($0.02 per share) being recorded in the Company's
consolidated financial statements for the year ended December 31,
2003. For share appreciation rights, the fair-value based method
was applied retroactively without restatement in 2002. There was
no impact on the 2003 consolidated financial statements (2002 -
$0.5 million).
4. DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST
During the first quarter of 2003, the Company completed the
formation and structuring of Paramount Energy Trust (the "Trust")
through the following transactions:
a) On February 3, 2003, Paramount transferred to the Trust
natural gas properties in the Legend area of Northeast Alberta
for net proceeds of $28 million and 9,907,767 units of the Trust.
b) On February 3, 2003, Paramount declared a dividend-in-kind of
$51 million, consisting of an aggregate of 9,907,767 units of the
Trust. The dividend was paid to shareholders of Paramount's
common shares of record on the close of business on February 11,
2003.
c) On March 11, 2003, in conjunction with the closing of a rights
offering by the Trust, Paramount disposed of additional natural
gas properties in Northeast Alberta to Paramount Operating Trust
for net proceeds of $167 million.
As the transfer of the Initial Assets and the Additional Assets
(collectively the "Trust Assets") represented a related party
transaction not in the normal course of operations involving two
companies under common control, the transaction has been
accounted for at the net book value of the Trust Assets as
recorded in the Company. Details are as follows:
/T/
Natural gas properties $ 244,433
Future income tax liability 4,070
Site restoration liability (5,900)
Costs of disposition 10,430
Adjustment to retained earnings (6,638)
---------------------------------------------------
Net proceeds on disposition $ 246,395
---------------------------------------------------
---------------------------------------------------
/T/
In connection with the creation and financing of the Trust and
the transfer of natural gas properties to the Trust, the Company
incurred costs of approximately $10.4 million. These costs have
been included as a cost of disposition.
During 2003, the Company disposed of a minor non-core property to
the Trust. The related party transaction was accounted for at the
net book value of the assets, with an adjustment to retained
earnings of $0.3 million.
5. PROPERTY PLANT AND EQUIPMENT
/T/
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Cost Accumulated Cost Accumulated
depletion depletion
and and
depreciation depreciation
--------------------------------------------------------------------
Petroleum and
natural gas
properties $ 961,248 $ 296,904 $ 1,263,544 $ 326,074
Gas plants,
gathering systems
and production
equipment 430,234 107,031 670,769 214,655
Building 8,542 445 8,481 146
Other 20,516 9,955 18,575 8,533
--------------------------------------------------------------------
$ 1,420,540 $ 414,335 $ 1,961,369 $ 549,408
--------------------------------------------------------------------
Net book value $ 1,006,205 $ 1,411,961
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
Capital costs associated with non-producing petroleum and natural
gas properties totaling approximately $209 million (2002 - $367
million) are currently not subject to depletion.
For the year ended December 31, 2003, the Company expensed $36.6
million in dry hole costs (2002- $120.1 million). 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.
For the year ended December 31, 2003, the Company recorded a
provision of $10.4 million (2002 - $31.3 million) in respect of
impairment of petroleum and natural gas properties.
For the year ended December 31, 2003, the Company recorded a
provision of $4.5 million (2002 - $3.4 million) in respect of
future site restoration and abandonment costs.
6. JOINT VENTURES
The consolidated financial statements include the Company's
proportionate share of the assets and liabilities of its joint
ventures as follows:
/T/
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Assets
Current assets $ 5,116 $ 1,278
Property, plant and equipment 5,811 8,520
--------------------------------------------------------------------
$ 10,927 $ 9,798
--------------------------------------------------------------------
--------------------------------------------------------------------
Liabilities and equity
Current liabilities $ 8,421 $ 9,239
Other liabilities 4,284 2,008
Deficit (1,778) (1,449)
--------------------------------------------------------------------
$ 10,927 $ 9,798
--------------------------------------------------------------------
Revenues $ 11,594 $ 2,591
Expenses $ 11,749 $ 2,396
Net earnings (loss) $ (155) $ 195
Cash flow provided by (used in)
Operating activities $ (1,564) $ 3,452
Financing activities $ 2,437 $ 1,063
Investing activities $ (873) $ (4,515)
--------------------------------------------------------------------
/T/
On November 13, 2003, Wilson Drilling Ltd. replaced its existing
term loan facility with a new $6.3 million credit facility with a
Canadian chartered bank. The credit facility is repayable in
equal monthly installments of $131,250 plus interest. As at
December 31, 2003, the facility had an effective interest rate of
4.67 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 percent. The
Company has provided a guarantee on the capital lease. Earnings
attributed to services provided to the Company have been
eliminated from the consolidated statements of earnings.
Shehtah-Wilson Drilling Partnership, a partnership in which the
Company has a 99 percent interest, has a 10 year operating lease
for two oilfield drilling rigs. The commitment associated with
this lease is as follows:
/T/
Year Lease Commitment
---------------------------------------------------
2004 $ 1,696
2005 1,696
2006 1,696
2007 1,696
2008 1,696
Thereafter 6,784
---------------------------------------------------
$ 15,264
---------------------------------------------------
7. BANK LOANS
As at December 31, bank loans were comprised of:
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Production/working capital
facility - (2002 - 7.5%) $ - $ 418,300
Drilling rig indebtedness -
current interest rate of 6.00%
(2002 - 6.82%) 1,138 3,071
Mortgage - current interest rate
of 6.15% 312 270
Bridge facility - (2002 - 13%) - 44,900
LIBOR advances - (2002 - 7.75%) - 31,556
--------------------------------------------------------------------
$ 1,450 $ 498,097
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
The Company has letters of credit totaling $10.3 million (2002 -
$13.3 million) outstanding with a Canadian Chartered Bank. These
letters of credit reduce the amount available under the Company's
working capital facility.
8. LONG-TERM DEBT
As at December 31, long term debt was comprised of:
/T/
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
U.S. Senior Notes - interest rate
of 7.875% $ 226,887 $ -
Credit facility - current interest
rate of 4.5% 60,350 -
Drilling rig indebtedness -
current interest rate of 6.00%
(2002 - 6.82%) 3,456 1,443
Mortgage - interest rate of 6.15% 6,418 6,730
--------------------------------------------------------------------
$ 297,111 $ 8,173
--------------------------------------------------------------------
/T/
The Company issued U.S. $175 million of 7 7/8 percent Senior
Notes due 2010 on October 27, 2003. Interest on the notes is
payable semi-annually, beginning in 2004. The Company may redeem
some or all of the notes at any time after November 1, 2007 at
redemption prices ranging from 100 percent to 103.938 percent of
the principal amount, plus accrued and unpaid interest to the
redemption date, depending on the year in which the notes are
redeemed. In addition, the Company may redeem up to 35 percent of
the notes prior to November 1, 2006 at 107.875 percent of the
principal amount, plus accrued interest to the redemption date,
using the proceeds of certain equity offerings. The notes are
unsecured and rank equally with all of the Company's existing and
future unsecured indebtedness.
The Company incurred $7.1 million of financing charges in 2003
related to the issuance of the senior notes. The financing
charges are capitalized to other assets and amortized evenly over
the term of the notes.
On October 27, 2003, the Company replaced its existing credit
facility with a new $203 million committed
revolving/non-revolving term facility with a syndicate of
Canadian chartered banks. Borrowings under the facility bear
interest at the bank's prime lending rate, bankers' acceptance or
LIBOR rates plus applicable margins, ranging from 50 to 300 basis
points, dependent on certain conditions. The revolving nature of
the new facility expires on March 31, 2004. The Company has
requested for an extension of the revolving credit facility of up
to 364 days, subject to the approval of the lenders. To
facilitate the documentation of this extension, the Company has
agreed to amend the expiry date of the existing facility to April
30, 2004. To the extent that any lenders participating in the
syndicate do not approve the 364 day extension, the amount due to
those lenders will convert to a one year non-revolving term loan
with principal due in full on March 31, 2005. Advances drawn on
the facility are secured by a first floating charge over all the
assets of the Company.
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.
9. RELATED PARTY TRANSACTIONS
Disposition of Assets to Paramount Energy Trust
In the first quarter of 2003, the Company transferred certain
natural gas assets in Northeast Alberta to the Trust, a related
party. The transaction (see note 4), was accounted for at the net
book value of the assets as recorded in the Company.
Note Payable to Paramount Oil and Gas Ltd.
In 2002, in order to complement existing funding for the
acquisition of Summit, the Company secured a $33 million loan,
with an effective interest rate during 2002 of 5.5 percent, from
Paramount Oil and Gas Ltd., a related entity with a significant
ownership interest in the Company. The loan was repaid on March
7, 2003.
10. 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.
Issued Capital
/T/
--------------------------------------------------------------------
Common Shares Number Consideration
--------------------------------------------------------------------
Balance December 31, 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
--------------------------------------------------------------------
Stock options exercised during the
year 710,000 10,317
Shares repurchased - at par (74,000) (236)
--------------------------------------------------------------------
Balance December 31, 2003 60,094,600 $ 200,274
--------------------------------------------------------------------
/T/
The Company instituted a Normal Course Issuer Bid to acquire a
maximum of 5 percent of its issued and outstanding shares
commencing May 15, 2003, and ending May 14, 2004. During 2003,
74,000 shares (2002 - nil) were purchased pursuant to the plan at
an average price of $9.53 per share.
Subsequent to year-end, the Company re-purchased 701,300 common
shares at an average price of $10.86 per share.
In February 2003, employees of the Company exercised 710,000
stock options for total consideration of $10.3 million.
Stock Option Plan
The Company has an Employee Incentive Stock Option plan (the
"plan"). Under the plan, stock options are granted at the current
market price on the date of issuance. Participants in the plan,
upon exercising their stock options, may request to receive
either a cash payment equal to the difference between the
exercise price and the market price of the Company's common
shares or common shares issued from Treasury. Irrespective of the
participant's request, the Company may choose to only issue
common shares. Cash payments made in respect of the plan are
charged to general and administrative expenses when incurred.
Options granted vest over four years and have a four and a half
year contractual life.
As at December 31, 2003, 5.9 million shares were reserved for
issuance under the Company's Employee Incentive Stock Option
Plan, of which 3.6 million options are outstanding, exercisable
to September 30, 2008, at prices ranging from $8.91 to $12.02 per
share.
The formation of the Trust (note 4) resulted in the Company
re-pricing stock options. 941,500 stock options issued in 2001,
the majority of which were at exercise prices of $14.50 and
$13.35 per option, were re-priced to exercise prices of $10.22
and $9.07 per option, respectively.
/T/
--------------------------------------------------------------------
Stock options 2003 2002
--------------------------------------------------------------------
Average Average
grant price Options grant price Options
--------------------------------------------------------------------
Balance, beginning
of year $14.25 1,949,500 $14.08 2,173,500
Granted 9.66 2,998,000 15.90 80,000
Exercised 14.29 (791,000) 12.98 (195,000)
Cancelled 10.30 (524,500) 14.23 (109,000)
--------------------------------------------------------------------
Balance, end of
year $ 9.64 3,632,000 $14.25 1,949,500
--------------------------------------------------------------------
Options exercisable,
end of year $10.72 1,087,875 $14.35 738,500
--------------------------------------------------------------------
--------------------------------------------------------------------
The following summarizes information about stock options outstanding
at December 31, 2003:
Outstanding Exercisable
Weighted Weighted Weighted
Average Average Average
Exercise Contractual Exercise Exercisable Exercise
Prices Number Life Price Number Price
---------------------------------------------------------------------
$ 8.91-9.80 2,506,000 4 $ 9.02 309,375 $ 9.00
$ 10.01-12.02 1,126,000 2 $ 11.04 778,500 $ 11.40
---------------------------------------------------------------------
Total 3,632,000 3 $ 9.64 1,087,875 $ 10.72
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Fair Values
The fair values of all common share options granted are estimated
as at the grant date using the Black-Scholes option-pricing
model. The weighted average fair values of the options granted
during the year and the weighted average assumptions used in
their determination are as noted below:
/T/
2003 2002
----------------------------------------------------------
Risk-free interest rate 5.8% 5.8%
Expected life 4 years 4 years
Expected volatility 39% 39%
Fair value per option $3.42 $6.38
----------------------------------------------------------
----------------------------------------------------------
/T/
The Company recognized compensation costs related to stock
options granted to employees of $1.2 million. The Company
recognized no compensation costs related to stock options granted
to employees in 2002. Had compensation costs for stock options
granted to employees in 2002 been determined based on the fair
value at the grant date of the awards, $49,000 would have been
charged to earnings in 2002, for which there was no impact on
earnings per share. Options granted prior to 2003 continue to be
accounted for through pro-forma disclosure.
Per Share Information
Basic earnings per share are calculated based on a weighted
average number of common shares of 60,098,447 (2002 -
59,457,737). There are no anti-dilutive options at December 31,
2003.
11. INCOME TAXES
The income tax provision differs from the expected income taxes
obtained by applying the Canadian corporate tax rate to loss
before taxes as follows:
/T/
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Corporate tax rate 40.67% 42.14%
Calculated income tax recovery $ (23,044) $ (11,571)
Increase (decrease) resulting
from:
Non-deductible Crown charges, net
of Alberta Royalty Tax Credit 21,991 10,449
Federal resource allowance (17,124) (29,958)
Federal and provincial income tax
rate adjustment (30,257) (2,758)
Attributed Canadian Royalty Income
recognized (5,228) -
Large corporations tax and other 2,875 9,150
Non-taxable portion of gain on
sale of investments - (8,603)
Recognition of tax pools not
previously recognized (3,343) -
Other (5,164) (4,474)
--------------------------------------------------------------------
Income tax recovery expense $ (59,294) $ (37,765)
--------------------------------------------------------------------
--------------------------------------------------------------------
Components Of Future Income Taxes
--------------------------------------------------------------------
The net future tax liability
comprises: 2003 2002
--------------------------------------------------------------------
Differences between tax base and
reported amounts of depreciable
assets $ 215,250 $ 285,201
Provision for future site
restoration (7,310) (7,255)
Other 2,473 1,909
--------------------------------------------------------------------
$ 210,413 $ 279,855
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
12. FINANCIAL INSTRUMENTS
The Company's financial instruments included in the consolidated
balance sheet are comprised of short-term investments, accounts
receivable, accounts payable, shareholder loan, bank loans,
long-term debt and deferred revenue.
(a) FOREIGN EXCHANGE HEDGES
The Company has entered into the following currency index swap
transactions, fixing the exchange rate on receipts of US $24.4
million for CDN $34.9 million over the next two years at CDN
$1.4335. The US$/CDN$ closing exchange rate was 1.2965 as at
December 31, 2003 (December 31, 2002 - 1.5776).
/T/
-----------------------------------------------------------
Weighted average
Year of settlement U.S. dollars exchange rate
-----------------------------------------------------------
2004 $ 12,360 1.4333
2005 12,000 1.4337
-----------------------------------------------------------
$ 24,360 1.4335
-----------------------------------------------------------
-----------------------------------------------------------
/T/
At December 31, 2003 the estimated fair value of these hedges
based on the Company's assessment of available market information
was a gain of $3.3 million (2002 - loss of $6.0 million).
(b) COMMODITY PRICE HEDGES
At December 31, 2003, the Company has entered into financial
forward sales arrangements as follows:
/T/
---------------------------------------------------------------------
AECO Price Term
---------------------------------------------------------------------
10,000 GJ/d $7.35 January 2004 - March 2004
10,000 GJ/d $6.26 January 2004 - March 2004
10,000 GJ/d $6.14 January 2004 - March 2004
20,000 GJ/d $6.51 January 2004 - March 2004
10,000 GJ/d $5.55 April 2004 - October 2004
10,000 GJ/d $5.51 April 2004 - October 2004
---------------------------------------------------------------------
WTI
---------------------------------------------------------------------
1,000 Bbl/d US$24.07 May 2002 - April 2004
1,000 Bbl/d (collar) US$25.00-$30.25 January 2004 - December 2004
---------------------------------------------------------------------
/T/
Had these financial contracts been settled on December 31, 2003,
using prices in effect at that time, the mark to market before
tax loss would have totaled $1.6 million (2002 - $28.7 million).
Subsequent to December 31, 2003, the Company entered into
financial agreements as follows:
/T/
---------------------------------------------------------------------
AECO Price Term
---------------------------------------------------------------------
10,000 GJ/d $5.81 April 2004 - October 2004
10,000 GJ/d $5.86 April 2004 - October 2004
20,000 GJ/d $5.80 April 2004 - October 2004
10,000 GJ/d (collar) $5.25-$6.80 April 2004 - October 2004
10,000 GJ/d (collar) $5.25-$6.75 April 2004 - October 2004
---------------------------------------------------------------------
/T/
(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
accounts receivable, accounts payable, shareholder loan, bank
loans and deferred revenue, 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.
The fair value of the U.S. Senior Notes approximate their
carrying values, as the debt has been translated into Canadian
dollars at exchange rates in effect at the balance sheet date,
and 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.
(e) INTEREST RATE RISK
The Company is exposed to interest rate risk to the extent that
changes in market interest rates will impact the Company's debts
that have a floating interest rate. The Company had no interest
rate swaps or hedges at December 31, 2003.
13. CHANGE IN NON-CASH WORKING CAPITAL
/T/
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Change in non-cash working
capital:
Short-term investments $ (283) $ (236)
Accounts receivable 6,859 (18,686)
Prepaid expenses 1,829 (5,893)
Deferred hedging loss - 17,638
Accounts payable and accrued
liabilities (26,958) 48,312
Less working capital deficiency
acquired (note 2) - (7,950)
--------------------------------------------------------------------
$ (18,553) $ 33,185
--------------------------------------------------------------------
Operating activities (33,381) 40,145
Investing activities 14,828 (6,960)
--------------------------------------------------------------------
$ (18,553) $ 33,185
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
Certain changes in non-cash working capital which were incurred
as a result of asset dispositions during the year have been
excluded from the above amounts.
Amounts paid during the year related to interest and large
corporations and other taxes were as follows:
/T/
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Interest paid $ 17,497 $ 23,278
--------------------------------------------------------------------
Large corporations and other taxes paid $ 2,395 $ 20,447
--------------------------------------------------------------------
/T/
14. CONTINGENCIES AND COMMITMENTS
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.
The Company indemnifies its directors and officers against any
and all claims or losses reasonably incurred in the performance
of their service to the Company to the extent permitted by law.
The Company has acquired and maintains liability insurance for
its directors and officers.
Commitments
As at December 31, 2003, the Company has the following
commitments related to the operating lease for the building and
pipeline commitments.
/T/
Year Commitment
--------------------- --------------------------
2004 $ 25,695
2005 23,925
2006 21,889
2007 21,889
2008 21,889
Thereafter 153,421
---------------------------------------------------
$ 268,708
---------------------------------------------------
/T/
15. 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% gross overriding royalty
encompassing certain wells, land and leases affected by the
shut-in order of May 1, 2000.
In 2002, the company received approximately $46.4 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 2002.
16. GAIN ON SALE OF INVESTMENTS
During 2002, the Company recorded gains on disposal of its
investments in Peyto Exploration and Development Corp. and other
short-term investments of $40.8 million.
17. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform
with the current year's financial statement presentation.
18. RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES
GENERALLY ACCEPTED PRINCIPLES
The consolidated financial statements have been prepared in
accordance with Canadian generally accepted accounting principles
("Canadian GAAP"). Any differences in accounting principles as
they pertain to the accompanying financial statements are not
material except as described below. The application of United
States generally accepted accounting principles ("U.S. GAAP")
would have the following effects on the Company's historical net
earnings (loss) as reported:
/T/
Year ended Year ended
December 31, December 31,
2003 2002
--------------------------------------------------------------------
Net earnings for the year as reported $ 2,633 $ 10,307
Adjustments, net of tax
Forward foreign exchange contracts
and other financial instruments(a) 3,411 (25,267)
Impairments and related change in
depletion(c) 6,762 (15,138)
Depletion and depreciation(d) (1,734)
General and administrative(d) 141 -
Short-term investments(f) 428
----------- -----------
Net earnings (loss) for the year
before changes in accounting
policies - U.S. GAAP(e) $ 11,641 $ (30,098)
Change in accounting policy -
Asset Retirement Obligation(d) - (15,633)
----------- -----------
Net earnings (loss) for the year -
U.S. GAAP $ 11,641 $ (45,731)
----------- -----------
----------- -----------
Net earnings (loss) per common
share before change in accounting
policy - U.S. GAAP(e)
Basic $ 0.19 $ (0.51)
Diluted $ 0.19 $ (0.51)
----------- -----------
----------- -----------
Net earnings (loss) per common
share - U.S. GAAP(e)
Basic $ 0.19 $ (0.77)
Diluted $ 0.19 $ (0.77)
----------- -----------
The application of U.S. GAAP would have the following effect on the
balance sheet at December 31:
2003 2002
----------------------- ------------------------
As As
reported U.S. GAAP reported U.S. GAAP
--------------------------------------------------------------------
Assets
Short-term
investments(f) $ 16,551 $ 17,265 $ 14,168 $ 14,168
Assets held for
sale(e) - - - 193,899
Property, plant
and
equipment(c)(d)(e) 1,006,205 1,022,366 1,411,961 1,225,138
Liabilities
Deferred hedging
loss (gain)(a) $ - $ 1,726 $ - $ 43,667
Provision for
future site
restoration and
abandonment
costs(d) 21,114 59,301 22,954 56,575
Deferred
Revenue(a) 3,959 -
Future income
taxes(a)(b)(c)(d)(f) 210,413 222,163 279,855 253,971
Shareholders'
equity
Retained earnings $ 300,622 $ 273,245 $ 355,912 $ 311,584
/T/
(a) Forward foreign exchange contracts and other financial
instruments-The Company has designated, for Canadian GAAP
purposes, its derivative financial instruments as hedges of
anticipated revenue and expenses. In accordance with Canadian
GAAP, payments or receipts on these contracts are recognized in
income concurrently with the hedged transaction. The fair values
of the contracts deemed to be hedges are not reflected in the
financial statements.
For U.S. purposes, the Company has adopted Statement of Financial
Accounting Standards ("SFAS") No. 133, as amended, Accounting for
Derivative Instruments and Hedging Activities. With the adoption
of this standard all derivative instruments are recognized on the
balance sheet at fair value. The statement requires that changes
in the derivative instrument's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met.
Management has not designated any of the currently held financial
instruments as hedges for U.S. GAAP purposes and accordingly
these derivatives have been recognized on the balance sheet at
fair value with the change in their fair value recognized in
earnings.
Under U.S. GAAP for the year ended December 31, 2003 additional
income of $5.7 million (net of tax - $3.4 million) and for the
year ended December 31, 2002 additional expense of $43.7 million
(net of tax - $25.3 million) would have been recorded.
(b) Deferred Income Taxes-The Canadian liability method of
accounting for income taxes is similar to the United States
Statement of Financial Accounting Standard No. 109 "Accounting
for Income Taxes", which requires the recognition of deferred tax
assets and liabilities for the expected future tax consequences
of events that have been recognized in the Company's financial
statements or tax returns. Pursuant to U.S. GAAP, enacted tax
rates are used to calculate future taxes, whereas Canadian GAAP
uses substantively enacted rates. For the years ended December
31, 2003 and 2002 this difference did not impact the Company's
financial position or results of operations.
(c) Impairments-Under both U.S. and Canadian GAAP, property,
plant and equipment must be assessed for potential impairments.
Under U.S. GAAP, if the sum of the expected future cash flows
(undiscounted and without interest charges) is less than the
carrying amount of the asset, then an impairment loss (the amount
by which the carrying amount of the asset exceeds the fair value
of the asset) should be recognized. Fair value is calculated as
the present value of estimated expected future cash flows. As
disclosed in note 1, under Canadian GAAP, the impairment loss is
the difference between the carrying value of the asset and its
net recoverable amount (discounted). For the year ended December
31, 2003, no impairment charge would be recorded and a reduction
in depletion expense of $11.3 million (net of tax - $6.8 million)
would be recorded due to impairment charges recorded in fiscal
2002 under U.S. GAAP. For the year ended December 31, 2002, an
additional impairment charge of $49.0 million (net of tax - $28.3
million), and a reduction in depletion expense of $23.0 million
(net of tax - $13.1 million) would have been recorded under U.S.
GAAP. The resulting differences in recorded carrying values of
impaired assets result in further differences in depreciation,
depletion and amortization expense in subsequent years.
The Canadian Institute of Chartered Accountants (the "CICA") has
adopted a new standard that will eliminate this U.S./Canadian
GAAP difference going forward.
(d) Asset Retirement Obligations - For U.S. purposes, the Company
has adopted Statement of Financial Accounting Standards ("SFAS")
No. 143, Accounting for Asset Retirement Obligations. Under U.S.
GAAP, legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction,
development and/or the normal operation of long-lived assets must
be recognized at fair value in the period in which the liability
is incurred. The fair value is added to the carrying amount of
the associated asset. The liability is accreted at the end of
each period through charges to operating expenses.
For the year ended December 31, 2003, the change results in an
additional reduction to site restoration expense of $0.2 million
(net of tax - $0.1 million) and an additional charge to depletion
and depreciation of $2.9 million (net of tax - $1.7 million). The
effect on the Consolidated Balance Sheet is an increase in
property, plant and equipment of $16.2 million and an increase of
$38.2 million to the provision for future site restoration and
abandonment costs.
For the year ended December 31, 2002, the cumulative impact
results in an additional charge due to a change in accounting
policy of $20.1 million (net of tax of $15.6 million). The
cumulative effect on the Consolidated Balance Sheet is an
increase in property, plant and equipment of $36.4 million, an
increase to site restoration liability of $33.6 million.
(e) Discontinued Operations-Under U.S. GAAP, the transaction
resulting in the disposal of the Trust Assets to the Trust as
described in note 4 would be accounted for as discontinued
operations as the applicable criteria set out in SFAS 144,
"Accounting for Impairment or Disposal of Long-Lived Assets" had
been met. Accordingly, the carrying value of the Trust Assets are
separately presented in the consolidated balance sheet. Net
income from discontinued operations for the year ended December
31, 2003 would have been $11.6 million (2002 - net loss - $5.7
million), or $0.19 per basic and diluted common share (2002 -
loss of $0.10 per basic and diluted common share).
(f) Short-Term Investments - Under U.S. GAAP, equity securities
that are bought and sold in the short term are classified as
trading securities. Unrealized holding gains and losses related
to trading securities are included in earnings as incurred. Under
Canadian GAAP, these gains and losses are not recognized in
earnings until the security is sold. As at December 31, 2003 the
Company had unrealized holding gains of $0.7 million (net of tax
- $0.4 million).
(g) Other Comprehensive Income-Under U.S. GAAP, certain items
such as the unrealized gain or loss on derivative instrument
contracts designated and effective as cash flow hedges are
included in other comprehensive income. In these financial
statements, there are no comprehensive income items other than
net earnings.
(h) Statements of Cash Flow-The application of U.S. GAAP would
not change the amounts as reported under Canadian GAAP for cash
flows provided by (used in) operating, investing or financing
activities, except that the consolidated statements of cash flow
include, under investing activities, changes in working capital
for items not affecting cash, such as accounts payable related to
the non-cash elements of property and equipment reductions of
$14,828 (2002 - additions of $6,960). This disclosure has been
provided in order to disclose the aggregate costs related to such
activities and to arrive at the cash amounts. This presentation
is not permitted under U.S. GAAP.
/T/
Paramount Resources Limited
Pro-forma Supplemental Oil and Gas Operating Statistics - unaudited
For the Period Ended December 31, 2003
(Note 1)
Sales Volumes 2003
-----------------------------------------------------------------------
Q4 Q3 Q2 Q1
-----------------------------------------------------------------------
Gas (MMcf/d) 141 136 142 143
Oil and Natural Gas Liquids (Bbl/d) 5,877 7,461 7,465 7,892
-----------------------------------------------------------------------
Total Sales Volumes (Boe/d) (6:1) 29,353 30,098 31,129 31,711
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Per-unit Results 2003
-----------------------------------------------------------------------
Q4 Q3 Q2 Q1
-----------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, net of transpiration
and selling 5.14 5.74 5.90 6.91
Royalties 0.55 1.30 1.14 1.43
Operating expenses, net of
processing revenue 1.26 1.19 0.95 0.73
-----------------------------------------------------------------------
Netback before commodity hedge 3.33 3.25 3.81 4.75
Commodity hedge 0.25 (0.72) (1.09) (1.62)
-----------------------------------------------------------------------
Netback including commodity hedge 3.58 2.53 2.72 3.13
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Produced Oil & Natural Gas Liquids
($/Bbl)
Price, net of transpiration
and selling 36.02 36.48 36.94 42.98
Royalties 6.64 6.75 7.28 9.04
Operating expenses, net of
processing revenue 11.01 10.01 8.90 6.96
-----------------------------------------------------------------------
Netback before commodity hedge 18.37 19.72 20.76 26.98
Commodity hedge (3.13) (2.27) (1.67) (4.03)
-----------------------------------------------------------------------
Netback including commodity hedge 15.24 17.45 19.09 22.95
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Total Produced ($/Boe)
Price, net of transpiration
and selling 31.87 34.95 35.84 41.85
Royalties 3.95 7.56 6.95 8.70
Operating expenses, net of
processing revenue 8.25 7.85 6.46 5.02
-----------------------------------------------------------------------
Netback before commodity hedge 19.67 19.54 22.43 28.13
Commodity hedge 0.57 (3.76) (5.37) (8.33)
-----------------------------------------------------------------------
Netback including commodity hedge 20.24 15.78 17.06 19.80
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Sales Volumes 2002
-----------------------------------------------------------------------
Q4 Q3 Q2 Q1
-----------------------------------------------------------------------
Gas (MMcf/d) 172 162 182 170
Oil and Natural Gas Liquids (Bbl/d) 8,552 7,832 7,346 8,362
-----------------------------------------------------------------------
Total Sales Volumes (Boe/d) (6:1) 37,243 34,756 37,732 36,739
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Per-unit Results 2002
-----------------------------------------------------------------------
Q4 Q3 Q2 Q1
-----------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, net of transpiration
and selling 4.15 3.16 4.05 2.80
Royalties 0.92 0.65 0.91 0.49
Operating expenses, net of
processing revenue 0.64 0.70 1.05 0.64
-----------------------------------------------------------------------
Netback before commodity hedge 2.59 1.81 2.09 1.67
Commodity hedge 0.29 0.67 0.50 0.75
-----------------------------------------------------------------------
Netback including commodity hedge 2.88 2.48 2.59 2.42
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Produced Oil & Natural Gas Liquids
($/Bbl)
Price, net of transpiration
and selling 36.03 37.47 33.82 27.28
Royalties 6.83 8.71 5.97 3.78
Operating expenses, net of
processing revenue 5.72 8.40 5.75 6.18
-----------------------------------------------------------------------
Netback before commodity hedge 23.48 20.36 22.10 17.32
Commodity hedge (0.76) (0.76) - -
-----------------------------------------------------------------------
Netback including commodity hedge 22.72 19.60 22.10 17.32
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Total Produced ($/Boe)
Price, net of transpiration
and selling 27.44 23.14 26.15 19.20
Royalties 5.80 4.99 5.56 3.12
Operating expenses, net of
processing revenue 4.29 5.15 6.22 4.36
-----------------------------------------------------------------------
Netback before commodity hedge 17.35 13.00 14.37 11.72
Commodity hedge 1.15 2.96 2.40 3.48
-----------------------------------------------------------------------
Netback including commodity hedge 18.50 15.96 16.77 15.20
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Note 1 - Pro-forma is presented on the basis of combining the results
of Paramount and Summit Resources Limited for periods prior to the
acquisition of Summit and removing the results associated with the
properties that were part of the Trust Disposition for periods or as of
dates prior to the Trust Disposition.
Note 2 - The Alberta Securities Commission released National Instrument
51-101 (the "Instrument") in 2003, with an effective date of
September 30, 2003.
The instrument requires all reported petroleum and natural gas
production to be measured in marketable quantities with adjustments
for heat content included in the commodity price reported.
The Company has adopted the Instrument prospectively. As such, fourth
quarter natural gas production volumes are measured in marketable
quantities, with adjustments
Paramount Resources Ltd.
Pro-forma Quarterly Condensed Statements of Earnings - Unaudited
For 2002 and 2003
$000's 2003
Q4 Q3 Q2 Q1
-------------------------------------
Net revenue, before hedging $ 76,156 $ 76,427 $ 80,345 $ 101,050
Commodity hedging gain (loss) 1,541 (10,423) (15,218) (29,100)
-------------------------------------
Net revenue 77,697 66,004 65,127 71,950
Operating expenses 22,287 21,738 18,302 14,338
Interest 5,604 3,017 4,234 4,476
General and administrative 5,832 4,709 4,589 4,513
Lease rentals 1,027 1,070 702 775
Geological and geophysical 3,208 1,071 3,423 748
Dry hole costs 5,750 1,533 13,628 8,891
Depletion and depreciation 47,055 33,175 37,041 38,759
Other expenses (5,550) 5,512 31,866 733
-------------------------------------
85,213 71,825 113,785 73,233
-------------------------------------
Earnings (loss) before taxes (7,516) (5,821) (48,658) (1,283)
Current and large corporations tax 1,165 422 741 547
Future tax (recovery) (19,977) 1,608 (47,963) 370
-------------------------------------
Net earnings (loss) $ 11,296 $ (7,851) $(1,436) $ (2,200)
-------------------------------------
-------------------------------------
Net earnings (loss) per common share
- basic $ 0.19 $ (0.13) $ (0.02) $ (0.04)
- diluted $ 0.19 $ (0.13) $ (0.02) $ (0.04)
Cash flow from operations $ 43,157 $ 29,071 $36,559 $ 47,301
-------------------------------------
-------------------------------------
Cash flow from operations per
common share
-basic $ 0.72 $ 0.48 $ 0.61 $ 0.79
-diluted $ 0.72 $ 0.47 $ 0.61 $ 0.79
WA shares o/s (basic) 60,168 60,169 60,169 59,998
WA shares o/s (diluted) 60,340 60,287 60,244 60,072
2002
Q4 Q3 Q2 Q1
-------------------------------------
Net revenue, before hedging $ 77,000 $ 58,046 $ 95,202 $ 68,752
Commodity hedging gain (loss) 3,925 9,466 8,233 11,497
-------------------------------------
Net revenue 80,925 67,512 103,435 80,249
Operating expenses 14,709 16,468 21,339 14,408
Interest 9,367 4,670 3,140 2,097
General and administrative 4,850 3,821 3,689 3,579
Lease rentals 899 1,343 227 632
Geological and geophysical 1,182 1,238 6,991 1,003
Dry hole costs 115,909 963 2,308 2,444
Depletion and depreciation 49,726 33,975 36,131 35,371
Other expenses (8,126) 1,114 3,490 (40)
-------------------------------------
188,516 63,592 77,315 59,494
-------------------------------------
Earnings (loss) before taxes (107,591) 3,920 26,120 20,755
Current and large corporations tax 1,989 (479) 11,375 1,027
Future tax (recovery) (74,272) 333 (6,043) 3,090
-------------------------------------
Net earnings (loss) $ (35,308) $ 4,066 $ 20,788 $ 16,638
-------------------------------------
-------------------------------------
Net earnings (loss) per common share
- basic $ (0.59) $ 0.07 $ 0.35 $ 0.28
- diluted $ (0.59) $ 0.07 $ 0.35 $ 0.28
Cash flow from operations $ 49,111 $41,689 $ 63,665 $ 58,506
-------------------------------------
-------------------------------------
Cash flow from operations per
common share
-basic $ 0.83 $ 0.70 $ 1.07 $ 0.98
-diluted $ 0.82 $ 0.70 $ 1.07 $ 0.98
WA shares o/s (basic) 59,458 59,459 59,457 59,459
WA shares o/s (diluted) 59,581 59,616 59,524 59,544
Paramount Resources Ltd.
Condensed Balance Sheets - Unaudited
As at December 31, 2003 and 2002
$000's
(Pro forma - Note 1)
2003 2002
--------------------------------
Current assets $ 103,016 $ 119,366
Property, plant and equipment 1,006,205 1,132,311
Other assets 31,621
--------------------------------
Total assets $ 1,147,848 $ 1,283,298
--------------------------------
--------------------------------
Accounts payable $ 112,159 $ 140,396
Debt 298,561 289,269
Future income taxes 210,413 308,996
Other liabilities 25,073 23,647
Shareholders' equity 501,642 520,990
--------------------------------
Total liabilities & shareholders'
equity $ 1,147,848 $ 1,283,298
--------------------------------
--------------------------------
Note 1:
The unaudited Pro forma condensed consolidated balance sheet and
statements of earnings have been prepared to reflect both the
acquisition of Summit Resources Limited (the "Summit acquisition") and
the disposition of assets to Paramount Energy Trust (the "Trust
disposition"), as follows:
i) The balance sheet at December 31, 2002 gives effect to the Trust
disposition as though it had occurred on December 31, 2002.
ii) The statements of earnings for the quarters ended March 31, 2002
and June 30, 2002 give effect to the Summit acquisition as though
it had occurred on the first day of the respective quarter.
iii) The statements of earnings for the quarters ended March 31, 2002,
June 30, 2002, September 30, 2002, December 31, 2002 and March 31,
2003 give effect to the Trust disposition as though it had
occurred on the first day of the respective quarter.
The unaudited Pro forma condensed consolidated balance sheet and
statements of earnings may not be indicative of the financial
position and results of operations that would have occurred if the
events reflected therein had been in effect on the dates indicated
or of the results that may be obtained in the future.
For further information: Paramount Resources Ltd., C. H. (Clay) Riddell, Chairman and Chief Executive Officer, (403) 290-3600, (403) 262-7994 (FAX) or Paramount Resources Ltd., J. H. T. (Jim) Riddell, President and Chief Operating Officer, (403) 290-3600, (403) 262-7994 (FAX) or Paramount Resources Ltd., B. K. (Bernie) Lee, Chief Financial Officer, (403) 290-3600, (403) 262-7994 (FAX), Website: www.paramountres.com
