CALGARY, ALBERTA - May 6, 2004 /CNW/ - Paramount
Resources Ltd. ("Paramount" or the "Company") is pleased to
announce its financial and operating results for the quarter
ended March 31, 2004.
/T/
Financial Highlights (unaudited)
($ thousands except per share
amounts and where stated
otherwise) Three Months Ended March 31
FINANCIAL 2004 2003 % Change
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Petroleum and natural gas sales 105,504 150,932 -30%
Cash flow (1)
From operations 59,554 58,489 2%
Per share -basic 1.00 0.97 3%
-diluted 0.99 0.97 2%
Earnings
Net earnings 3,179 314 912%
Per share -basic and diluted 0.05 0.01 400%
Capital expenditures
Exploration and development 111,769 52,409 113%
Acquisitions, dispositions and other (2,939) (271,393) -99%
Net capital expenditures 108,830 (218,984) -
Total assets (3) 1,245,159 1,177,130 6%
Net debt (2) (3) 382,891 307,704 24%
Shareholders' equity (3) 490,901 496,033 -1%
Common shares outstanding (thousands)
- March 31 59,291 60,169 -1%
- April 30 58,465
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OPERATING
Production
Natural gas (MMcf/d) 141 193 -27%
Crude oil and liquids (Bbl/d) 5,675 7,892 -28%
Total production (Boe/d) @ 6:1 29,178 40,088 -27%
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Average prices
Natural gas (pre-hedge) ($/Mcf) 6.54 6.93 -6%
Natural gas ($/Mcf) (4) 6.92 5.40 28%
Crude oil and liquids (pre-hedge) ($/Bbl) 41.87 42.98 -3%
Crude oil and liquids ($/Bbl)(4) 38.38 38.95 -1%
Drilling activity (gross)
Gas 81 67 21%
Oil 4 5 -20%
Oil sands evaluation (5) 17 - -
D&A 4 5 -20%
Total wells 106 77 38%
Success rate (5) 96% 94% 2%
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(1) Cash flow from operations is a non-GAAP term that represents net
earnings adjusted for non-cash items, dry hole costs and geological
and geophysical costs. The Company considers cash flow from
operations a key measure as it demonstrates the Company's ability to
generate the cash necessary to fund future growth through capital
investment and to repay debt.
(2) Net debt is equal to long-term debt plus working capital deficiency.
(3) Comparative figures are as at December 31, 2003.
(4) Excludes non-cash gains and losses on financial instruments.
(5) Success rate excludes oil sands evaluation wells.
/T/
Review of Operations
Kaybob
In the Kaybob Operating Unit, Paramount participated in the
drilling of 25 (18.2 net) wells, as compared to 18 (11.2 net)
wells in the first quarter of 2003. The activity level at Kaybob
has continued to increase since the first quarter of 2003 and
should continue when drilling operations resume after spring
breakup. Nine (8.6 net) of the wells that were rig released in
the first quarter were on production by the end of March. Of the
remaining wells, 12 (7.3 net) will be tied in during the summer
or when ground conditions permit access, two wells (0.3 net) were
dry and abandoned and two wells (2.0 net) were not considered
economic after completion. Drilling, completion and construction
operations planned for early April were suspended prematurely due
to spring breakup; a dry summer will assist in resuming these
suspended operations.
First quarter 2004 capital spending totaled approximately $29
million, representing 30 percent of the expected 2004 capital
budget for the Kaybob area. Approximately $21 million was spent
on drilling and completion operations and the remaining $8
million on construction and seismic expenditures. Additional
construction capital will be required in the second quarter to
tie in wells that were drilled and completed in the first
quarter.
Natural gas and crude oil/natural gas liquid production averaged
84 MMcf/d and 2,454 Bbl/d in the first quarter of 2004, as
compared to the 2003 annual average of 79 MMcf/d and 2,451 Bbl/d.
First quarter production volumes were down slightly from budgeted
expectations as a result of downtime over a period of extremely
cold weather, which restricted field operations. Second quarter
production should continue the upward trend when field operations
are resumed and we are able to complete the tie in of 8 MMcf/d of
net gas production shut-in due to spring breakup. The heat
content of the natural gas produced from the Kaybob area is
relatively high and, as a result, Paramount receives a premium
price for this production.
The majority of activities for the remainder of the year will be
focused on down-spacing opportunities and the optimization of
existing well bores and infrastructure to add production. Finding
and development costs and operating costs should decline
throughout the year as Paramount continues to capitalize on
developing reserves within existing infrastructure.
Grande Prairie
During the first quarter of 2004, Paramount continued to grow its
undeveloped land and prospect position in the Mirage area within
the Grande Prairie Operating Unit. This region remains highly
prospective because of its multi-zone potential in both shallow
and conventional medium-depth gas reservoirs. Current net gas
volumes in Mirage exceed 15 MMcf/d, in addition to 277 Bbl/d of
oil. In the first quarter of 2004 Paramount drilled 5 (4.9 net)
shallow gas wells in the Mirage area. Of the five wells, two are
currently on production and the remaining three wells are
awaiting second quarter tie-ins. The drilling undertaken in the
first quarter was of a strategic nature and allowed the Company
to assess the size of the shallow gas pool and design the
Company's infrastructure accordingly. In addition to drilling and
completion activities, a second compressor was installed at
Mirage to handle increasing natural gas production.
Production at Saddle Hills has met Paramount's expectations. As a
result of the environmental sensitivity of this area, Paramount
has agreed with the respective provincial government agencies to
restrict further drilling, completion and infrastructure
development until late third and early fourth quarter of 2004.
Several wells are planned on a deep Devonian play in this area,
some of which have been already licensed. Natural gas production
volumes are currently at 8 MMcf/d, with 125 to 150 Bbl/d of
associated liquids production.
New production in the Berry Lake project area came onstream March
19, 2004, with the tie in of seven wells, three of which were
drilled during the 2004 winter season, via the expansion of a
major pipeline. Current natural gas production is 2 MMcf/d with 3
MMcf/d of additional developed gas volumes currently limited by
firm service availability at the nearest gas plant. An expansion
of the compression facility at Martin Creek should be completed
by the end of the second quarter.
Six wells were drilled in Goose River during the 2004 winter
program. One of these wells has been tied in, one has yet to be
completed, two are awaiting fracture stimulation, one is awaiting
evaluation, and one was abandoned. Owing to the difficult access
in this area and early spring break up, operations ceased in
early March 2004.
Northwest Alberta
In Northwest Alberta and Cameron Hills, Northwest Territories,
Paramount participated in the drilling of 22 (14.5 net) wells,
the completion of 20 (14.1 net) wells, and the tie-in of 14 (10.5
net) wells during the first quarter of 2004. Total area capital
expenditures of $24 million for the first quarter consisted of
$13 million on drilling and completions, $9 million on facilities
and well tie-ins, and $2 million on land and seismic. No
additional drilling or construction is currently being forecast
in the Northwest Alberta core area for the remainder of the year
due to seasonal access restrictions.
Drilling activities were delayed at the start of the quarter due
to warmer than usual weather in Haro and Cameron Hills, and
equipment availability in Bistcho. Delays were also experienced
during the completion phase as a result of a general shortage of
services. These delays, in addition to an earlier than usual
spring breakup, prevented the conclusion of Paramount's
evaluation of four oil wells in Cameron Hills, and one Bistcho
well tie in had to be postponed to the following winter.
Net production for the quarter averaged 547 Bbl/d of liquids and
15 MMcf/d of natural gas. Corrosion identified in the Bistcho
treater at turnaround and the subsequent repairs resulted in a
month of lost oil production from Cameron Hills during the first
quarter. Gas production from Cameron Hills and Bistcho was lost
for a week during turnaround.
An increase of 4 MMcf/d in net production from Haro is expected
in the second quarter when the related expanded facilities are
commissioned, and wells drilled during the first quarter are put
on production.
Liard, N.W.T. / Northeast British Columbia
Production from this area averaged 10 MMcf/d for the first
quarter. Development drilling activity was concentrated on the
Chevron non-operated property at Liard. The 3K-29 location was
drilled and is being evaluated for a possible sidetrack
opportunity. The 2M-25 location spud on March 31, 2004 and is
planned for tie in during the third quarter 2004.
On the exploration side, Paramount drilled six exploratory
locations in Northeast British Columbia ranging in depth from 700
to 3,200 meters. Three of these wells were encouraging and
warrant either tie in or potential follow-up drilling. Anadarko
has finished their farm-in program at Arrowhead, N.W.T., with one
well cased and a second well cased and completed.
At Colville Lake, three wells were drilled and cased during the
first quarter. Completion operations extended into April and
results from all the wells are currently being evaluated. One of
these locations is a follow-up to the successful wells drilled at
Nogha last year, while the other two are exploratory locations.
Paramount is continuing to evaluate various development scenarios
for the Colville Lake area.
Southern
Production in the first quarter of 2004 from the Southern
Operating Unit averaged 10 MMcf/d and 1,917 Bbl/d. Paramount
participated in 6 (3.5 net) wells in the unit with an 83 percent
success rate; five wells were in the Chain/Craigmyle area, and
one in Champion. The unit also participated in 10 (8.78 net)
completions of existing wellbores: five in Chain/Craigmyle, two
in Retlaw, two in Sylvan Lake and one in Champion. These
recompletions experienced an 80 percent success rate.
This quarter marked a milestone as our first coalbed-methane gas
well was put on production in the Chain/Craigmyle area. The
Horseshoe Canyon coal gas play has expanded significantly in the
last two quarters throughout south central Alberta with a
multitude of companies announcing projects, and new production
coming on daily. Paramount is well positioned with its land base
and infrastructure in Chain to take advantage of this play.
After production declines in the previous four quarters due to
dispositions, the Southern Operating Unit is well-positioned to
increase production volumes in 2004. Activities are planned in
the next three quarters on most operated properties in southern
Alberta, Saskatchewan, North Dakota and Montana.
Heavy Oil
Paramount acquired 20 sections of oil sands leases in the
Thornbury area in January, continuing to build an inventory of
Athabasca oil sand prospects. Paramount now holds lands on five
separate prospects, including very prospective channel sands in
Leismer and Surmont.
Paramount successfully drilled 17 oil sands evaluation wells
during the first quarter in our Leismer, Pelican Lake and Surmont
areas. All wells encountered bitumen as forecast, leading to
technology evaluation through 2004 and further delineation
drilling in 2005.
As part of the ongoing Gas-over-Bitumen Technical Solution
Committee, Paramount initiated an integrated review of gas pools
in the Surmont area since shut-in. The study will be the most
intensive combined review of geological interpretation and
engineering simulation performed in the Athabasca oil sands. The
study, a joint venture with several other companies and the
Alberta Government, will be completed in Q2 2004 and will lead to
new strategies on gas and bitumen production within the Surmont
area.
Financial
Petroleum and natural gas sales before hedging totaled $105.5
million for the three months ended March 31, 2004, as compared to
$150.9 million for the comparable period in 2003. The decrease is
due primarily to lower production volumes as a result of the
disposition of substantially all of Paramount's Northeast Alberta
properties to Paramount Energy Trust in the first quarter of
2003, as well as other property dispositions during 2003. Cash
flow for the first quarter of 2004 totaled $59.6 million or $1.00
per basic share as compared to $58.5 million or $0.97 per basic
share in the first quarter of 2003. The increase is due to
reduced interest costs as a result of lower average debt levels,
offset by lower net revenues. Cash flow per Boe improved
significantly as compared to the comparable period in 2003,
mainly as a result of positive cash hedging gains as compared to
a loss in the 2003 period.
Net earnings for the three months ended March 31, 2004 totaled
$3.2 million or $0.05 per basic and diluted share, as compared to
earnings of $0.3 million or $0.01 per basic share for the
comparable period in 2003. The increase in earnings is a result
of lower depletion and depreciation expenses, as well as a future
income tax recovery of $5.2 million attributed to a one percent
reduction in Alberta corporate income tax rates, mitigated
partially by lower net revenues. Paramount also incurred an
unrealized foreign exchange loss on US debt of $2.6 million in
the current quarter.
Outlook
Cash flow in 2004, based on current commodity prices, continues
to be forecast to be about $240 million or approximately $4.00
per basic share, which is essentially equal to the capital
expenditure budget. Paramount has budgeted a total of $240
million for capital expenditures for 2004 and first quarter
expenditures of $112 million are in line with this budget. Q1
2004 production levels are slightly below budgeted levels but
annual production volumes are still forecast to meet the
projected average of 160 MMcf/d and 6,000 Bbl/d (32,500 BOE/d)
with the expectation that the shortfall will be made up through
the rest of the year. Expansions in Kaybob and Grande Prairie
have resulted in a more balanced capital program. Our property
inventory consists of a number of all-season access
opportunities, and over half of our capital budget will be spent
during the remainder of the year.
A conference call will be held with the senior management of
Paramount Resources Ltd. to answer questions with respect to the
first quarter results on Thursday, May 6, 2004 at 9:00 a.m. MST.
To participate please call 1- 888-575-8232 or 1-416-406-6419
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 from an hour
after the call until May 13, 2004. The number for the replay is
1-800-408-3053 or 1-416-695-5800 with passcode number 3050430.
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
three months ended March 31, 2004.
The following discussion of financial position and results of
operations should be read in conjunction with the interim
unaudited consolidated financial statements and related notes for
the three months ended March 31, 2004, as well as the audited
consolidated financial statements and related notes and MD&A for
the year ended December 31, 2003.
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, reserve estimates, production estimates, hedging
policies, asset retirement costs, the size of available income
tax pools, 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 asset retirement, 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.
Included in this MD&A are references to financial measures such
as cash flow from operations ("cash flow") and cash flow per
share. While widely used in the oil and gas industry, these
financial measures have no standardized meaning and are not
defined by Canadian generally accepted accounting principles
("GAAP"). Consequently, these are referred to as non-GAAP
financial measures. Cash flow appears as a separate caption on
the Company's consolidated statement of cash flows and is
reconciled to net earnings. Paramount considers cash flow a key
measure as it demonstrates the Company's ability to generate the
cash necessary to fund future growth through capital investment
and to repay debt. Cash flow should not be considered an
alternative to, or more meaningful than, net earnings as
determined in accordance with GAAP as an indicator of the
Company's performance.
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 April 30, 2004.
Additional information on the Company 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.
/T/
REVENUE & PRODUCTION
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Three months ended March 31
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Revenue (thousands of dollars) 2004 2003
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Natural gas $ 83,879 $ 120,405
Oil and natural gas liquids 21,625 30,527
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Petroleum and natural gas revenue 105,504 150,932
Gain (loss) on financial instruments (6,462) (29,392)
Other 1,072 1,123
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Gross revenue $ 100,114 $ 122,663
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/T/
Natural gas revenue for the three months ended March 31, 2004
decreased 30 percent to $83.9 million as compared to $120.4
million for the comparable quarter in 2003. The decrease in
natural gas revenue results primarily from lower production
levels combined with lower natural gas prices received during the
quarter. Paramount's average natural gas sales price before
hedging decreased 6 percent to $6.54/Mcf as compared to $6.93/Mcf
in the comparable quarter in 2003. Natural gas production volumes
for the quarter decreased 27 percent to 141 MMcf/d as compared to
193 MMcf/d for the comparable quarter in the prior year,
primarily as a result of the disposition of natural gas assets in
Northeast Alberta (the "Trust assets") to Paramount Energy Trust
(the "Trust") in the first quarter of 2003, as well as other
property dispositions during 2003. Total natural gas production
volumes remained unchanged at 141 MMcf/d as compared to the
fourth quarter of 2003, as production increases in the Kaybob
area were offset by a scheduled, maintenance-related facility
shut-down in Northwest Alberta and lower natural gas production
in Northeast BC. The Company experienced delays in bringing on
additional new production at Kaybob due to an early spring
break-up; new deliverability in certain fields was also
constrained by a lack of capacity at surrounding facilities.
Nevertheless, the Company is pleased with the overall results to
date of the Kaybob infill drilling program, and expects to
further add to production volumes in the area through the
remainder of 2004.
Oil and natural gas liquids ("NGL") revenue during the period
decreased 29 percent to $21.6 million as compared to $30.5
million for the comparable quarter in 2003, primarily due to
lower production levels combined with lower commodity prices as
compared to the first quarter of 2003. Paramount's average oil
and NGL sales price before hedging was $41.87/Bbl for the quarter
as compared to $42.98/Bbl in the comparable quarter in 2003. Oil
and NGL sales volumes decreased 28 percent to average 5,675 Bbl/d
for the quarter as compared to 7,892 Bbl/d for the comparable
quarter in 2003, primarily as a result of the sale of Sturgeon
Lake and other minor oil properties in 2003, partially offset by
new oil production at Cameron Hills. Oil and NGL production
volumes for the current quarter were off 3 percent from the 5,877
Bbl/d produced in the fourth quarter of 2003. The decrease is
largely attributable to scheduled, maintenance-related plant
shut-downs in the Northwest Alberta operating unit.
MARKETING
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 forward
commodity price contracts. This risk management program is
generally for periods of less than one year and would not exceed
50 percent of Paramount's average annual production volumes.
/T/
At March 31, 2004, Paramount had the following forward commodity price contracts in place: -------------------------------------------------------------------- AECO Price Term -------------------------------------------------------------------- 10,000 GJ/d $5.51 April 2004 - October 2004 10,000 GJ/d $5.55 April 2004 - October 2004 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 -------------------------------------------------------------------- WTI -------------------------------------------------------------------- 1,000 Bbl/d US$24.07 March 2002 - April 2004 1,000 Bbl/d US$25.00 - $30.25 collar January 2004 - December 2004 --------------------------------------------------------------------
/T/
The Company also has in place foreign exchange forward contracts,
which have fixed the exchange rate on US $21.0 million for CDN
$30.1 million over the next two years at CDN $1.4337.
On January 1, 2004, the Company adopted the recommendations set
out by the Canadian Institute of Chartered Accountants ("CICA")
in Accounting Guideline ("AcG") 13 - Hedging Relationships and
Emerging Issues Committee Abstract 128 - Accounting for Trading,
Speculative or Non Trading Derivative Financial Instruments.
According to the recommendations, financial instruments that do
not qualify as a hedge under AcG 13 or are not designated as a
hedge are recorded in the consolidated balance sheet as either an
asset or a liability, with changes in fair value recorded in net
earnings. The Company has chosen not to designate any of its
financial instruments as hedges and, accordingly, has used
mark-to-market accounting for these instruments.
As a result of applying these recommendations, the Company
recorded deferred financial instrument gains and losses at
January 1, 2004 of $3.3 million and $1.8 million, respectively,
representing the fair values of financial contracts outstanding
at the beginning of the fiscal year. These deferred gains and
losses will be recognized in the earnings over the term of the
related contracts. Amortization for the three months ended March
31, 2004 totaled $1.0 million for the deferred financial
instrument loss and $0.8 million for the deferred financial
instrument gain, for a net decrease in earnings before tax of
$0.2 million.
In addition, the Company recorded a financial instrument
liability at March 31, 2004 with a fair value of $10.0 million,
respectively. This amount reflects the unrealized change in fair
value of Paramount's forward contracts during the quarter.
The total loss on financial instruments for the quarter of $6.5
million is comprised of the afore-mentioned mark to market before
tax loss on forward contracts of $10.0 million and net
amortization expense of $0.2 million, offset by cash gains on
financial instruments of $3.7 million related to monthly
settlements with counterparties. This represents a 78 percent
decrease from the $29.4 million loss on financial instruments
incurred in the first quarter of 2003.
/T/
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Three months ended March 31
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Cash Netbacks Per Unit of Production ($/Boe) 2004 2003
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Gross revenue before financial instruments $ 40.14 $ 42.14
Royalties 7.88 8.65
Operating costs 6.96 5.23
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Operating netback 25.30 28.26
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(Gain) loss on financial instruments (1) (1.41) 8.15
General and administration (2) 1.98 1.32
Interest (3) 1.54 2.22
Lease rentals 0.46 0.21
Current and Large Corporations tax 0.29 0.15
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Cash flow netback $ 22.44 $ 16.21
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(1) Excluding unrealized gains and losses on financial instruments.
(2) Excluding non-cash general and administrative expenses.
(3) Excluding non-cash interest expense.
/T/
ROYALTIES
Royalties, net of ARTC, totaled $20.9 million for the three
months ended March 31, 2004, as compared to $31.2 million for the
comparable period in 2003, due largely to decreased natural gas
revenues. As a percentage of revenue, royalties averaged 19.8
percent in current quarter as compared to 20.7 percent for first
quarter of 2003. The decreased rate results from the lower
Alberta natural gas reference prices experienced during the
current quarter.
OPERATING COSTS
For the three months ended March 31, 2004, operating costs
totaled $18.5 million compared to $18.9 million during the same
period a year earlier.
On a unit-of-production basis, in comparison to the first quarter
of 2003, average operating costs increased 33 percent to
$6.96/Boe, as a result of scheduled facility maintenance and
repair costs in the Northwest Alberta core area. In 2003,
scheduled facility maintenance charges in Northwest Alberta were
primarily incurred in the second quarter. As compared to the
fourth quarter of 2003, unit operating costs decreased 16
percent. Unit costs for the previous quarter were $8.25/Boe, and
were affected by $3.6 million or $1.32/Boe of non-recurring
charges, including post-closing adjustments related to the
Sturgeon Lake property disposition, as well as expenses stemming
from the settlement of a dispute with a facility operator.
/T/
GENERAL AND ADMINISTRATIVE EXPENSES
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Three months ended March 31
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General and Administrative Expenses
(thousands of dollars) 2004 2003
--------------------------------------------------------------------
General and administrative expenses $ 4,884 $ 4,627
Stock-based compensation expensed 956 141
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Total general and administrative expenses $ 5,840 $ 4,768
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/T/
General and administrative expenses totaled $5.8 million for the
three months ended March 31, 2004, as compared to $4.8 million
recorded for the same period a year earlier. On a
unit-of-production basis, general and administrative expenses
before costs associated with stock-based compensation increased
to $1.84/Boe as compared to $1.28/Boe for the quarter ended March
31, 2003. Paramount has increased its head-office staffing levels
in the past year in order to enable the Company to identify and
develop new core areas and build its production portfolio, as
well as to ensure compliance with the new corporate and reporting
obligations in Canada and the United States. Paramount does not
capitalize any general and administrative expenses.
INTEREST EXPENSE
Interest expense totaled $4.3 million, a 46 percent decrease from
$8.0 million in the first quarter of 2003. In the comparative
quarter, the Company's average debt level was significantly
higher than in 2004, until the disposition of assets to the Trust
on March 11, 2003.
DEPLETION AND DEPRECIATION
Depletion and depreciation ("D&D") expense decreased 10 percent
to $42.1 million from $46.9 million for the three months ended
March 31, 2003, primarily due to lower production levels, offset
by a higher depletion and depreciation rate. On a
unit-of-production basis, depletion and depreciation costs
increased to $15.87/Boe as compared to $12.99/Boe for the first
quarter of 2003, due primarily to the addition of capital costs
previously excluded from the depletable base, as well as the
addition to capital costs resulting from the implementation of
CICA Handbook Section 3110 - Asset Retirement Obligation,
described in Note 2 to the unaudited consolidated financial
statements. Expired mineral leases included in first quarter D&D
expense totaled $2.9 million (2003 - $2.7 million).
Capital costs associated with undeveloped land and exploratory,
non-producing petroleum and natural gas properties of $229.6
million are excluded from costs subject to depletion (2003 -
$356.2 million).
INCOME TAX
At December 31, 2003, the Company had accumulated tax pools of
approximately $495 million, which will be available for deduction
in 2004 in accordance with Canadian income tax regulations at
varying rates of amortization. Paramount does not expect to pay
current income taxes in 2004.
/T/
CASH FLOW AND EARNINGS
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Three months ended March 31
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(thousands of dollars,
except per share amounts) 2004 2003
--------------------------------------------------------------------
Cash flow from operations $ 59,554 $ 58,489
Cash flow from operations per share
- basic $ 1.00 $ 0.97
- diluted $ 0.99 $ 0.97
--------------------------------------------------------------------
Net earnings $ 3,179 $ 314
Earnings per share
- basic $ 0.05 $ 0.01
- diluted $ 0.05 $ 0.01
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
Cash flow from operations totaled $59.6 million, representing a 2
percent increase from the $58.5 million reported for the
corresponding period in 2003. The increase is due to reduced
interest costs as a result of lower average debt levels, offset
by lower net revenues.
Net earnings for the three months ended March 31, 2004 totaled
$3.2 million compared to $0.3 million reported for the same
period a year earlier. The increase in earnings is a result of
lower depletion and depreciation expenses, as well as a future
tax recovery of $5.2 million attributed to a 1 percent reduction
in Alberta income tax rates, mitigated partially by lower net
revenues. Paramount also incurred a non-cash unrealized foreign
exchange loss on US debt of $2.6 million in the current quarter.
/T/
QUARTERLY INFORMATION
--------------------------------------------------------------------
Three months ended
(thousands of dollars, Mar 31, Dec 31, Sep 30, Jun 30,
except per share amounts) 2004 2003 2003 2003
--------------------------------------------------------------------
Net revenues $79,179 $77,697 $66,004 $65,127
Net earnings (loss) $ 3,173 $11,296 $(7,851) $(1,436)
Net earnings (loss)
per share - basic $ 0.05 $ 0.18 $ (0.13) $ (0.02)
- diluted $ 0.05 $ 0.18 $ (0.13) $ (0.02)
--------------------------------------------------------------------
Three months ended
(thousands of dollars, Mar 31, Dec 31, Sep 30, Jun 30,
except per share amounts) 2003 2002 2002 2002
--------------------------------------------------------------------
Net revenues $91,446 $110,180 $95,780 $110,206
Net earnings (loss) $ 314 $(41,399) $ 6,180 $ 26,614
Net earnings (loss)
per share - basic $ 0.01 $ (0.70) $ 0.10 $ 0.45
- diluted $ 0.01 $ (0.70) $ 0.10 $ 0.44
--------------------------------------------------------------------
/T/
Quarterly net revenues in 2004 and 2003, as compared to 2002
quarters, reflect lower production volumes as a result of the
disposition of the Trust assets in the first quarter of 2003,
partially offset by generally higher commodity prices. 2003
quarterly earnings have been adjusted to give effect to the
retroactive application of the new Canadian Institute of
Chartered Accountants Handbook Section 3110 - Asset Retirement
Obligation, which is described in Note 2 to the unaudited
consolidated financial statements.
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.
Net earnings of $26.6 million for the three months ended June 30,
2002 include Surmont compensation received of $38.0 million and a
gain on sale of the investment in Peyto Exploration of $24.5
million, mitigated partially by a write-down of US petroleum and
natural gas properties of $40.0 million.
/T/
CAPITAL EXPENDITURES
--------------------------------------------------------------------
Three months ended March 31
2004 2003
--------------------------------------------------------------------
Wells Drilled Gross (1) Net (2) Gross (1) Net (2)
--------------------------------------------------------------------
Natural Gas 81 59 67 48
Oil 4 4 5 5
Oil sands evaluation 17 17 - -
Dry 4 2 5 4
--------------------------------------------------------------------
Total 106 82 77 57
--------------------------------------------------------------------
(1) "Gross" wells means the number of wells in which Paramount has a
working interest.
(2) "Net" wells means the aggregate number of wells obtained by
multiplying each gross well by Paramount's percentage working
interest therein.
/T/
During the three months ended March 31, 2004, Paramount
participated in the drilling of 106 gross wells (82 net),
compared to 77 gross wells (57 net) during the same period in
2004. Drilling activity for the quarter was concentrated in
Kaybob (25 gross wells, 18 net, 92 percent net success rate) and
Grande Prairie (22 gross wells, 21 net, 95 percent net success
rate), as well as in Paramount's bitumen leases in Northeast
Alberta.
/T/
--------------------------------------------------------------------
Three months ended March 31
--------------------------------------------------------------------
Capital Expenditures
(thousands of dollars) 2004 2003
--------------------------------------------------------------------
Land $ 6,722 $ 2,206
Geological and geophysical 3,992 748
Drilling 70,200 39,307
Production equipment and facilities 30,855 10,148
--------------------------------------------------------------------
Exploration and development expenditures $ 111,769 $ 52,409
Proceeds received on property dispositions (3,165) (271,668)
Other 226 275
--------------------------------------------------------------------
Net capital expenditures $ 108,830 $(218,984)
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
For the three months ended March 31, 2004, exploration and
development expenditures totaled $111.8 million, as compared to
$52.4 million for the comparable quarter in 2003. Higher capital
expenditures are due to a larger number of net wells drilled in
the current quarter, and were enabled by increased financial
flexibility as a result of the US debt issued in October 2003.
Capital additions for the quarter were concentrated in the Kaybob
and Grande Prairie core areas.
Property dispositions in 2003 include the disposition of the
Trust assets for net consideration of $246.4 million.
DEFERRED REVENUE
During the first quarter of 2004, Paramount recognized in revenue
$4.0 million of deferred revenue related to the early settlement
of natural gas hedging contracts, as compared to $2.5 million for
the comparable period in the prior year. In accordance with AcG
13, the Company will continue to defer gains or losses arising
from the early termination of contracts for which hedge
accounting is used and amortize the balances over the life of the
initial contract.
LIQUIDITY AND CAPITAL RESOURCES
Debt
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 senior unsecured indebtedness.
The Company has a $203 million committed revolving/non-revolving
term facility with a syndicate of Canadian chartered banks.
Borrowings under the facility bear interest at the lender's prime
rate, bankers' acceptance or LIBOR rates plus an applicable
margin, dependent on certain conditions. The revolving nature of
the facility is due to expire on March 31, 2005. The Company may
request an extension on the revolving credit facility of up to
364 days, subject to the approval of the lenders. To the extent
that any lenders participating in the syndicate do not approve
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, 2006. Advances drawn on the facility are
secured by a fixed charge over 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.
Long-term debt, including current portion, increased to $346.4
million at March 31, 2004, compared to $298.6 million at December
31, 2003, primarily as a result of capital expenditures in the
period of $111.8 million, or $52.8 million in excess of cash flow
for the quarter. Paramount's capital program is generally at its
highest level during the first three months of the year, as
certain of the Company's core areas are only accessible during
the winter months. For the remainder of 2004, Paramount expects
that cash flow from operations will exceed capital expenditures.
The Company's working capital deficiency at March 31, 2004,
excluding the current portion of long-term debt, was $36.5
million (December 31, 2003 - $9.1 million). Paramount will likely
continue to 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.
Share Capital
During the quarter 146,250 stock options were exercised for cash
consideration of $0.4 million; this amount was charged to general
and administrative expenses.
Pursuant to its Normal Course Issuer Bid, Paramount repurchased
803,700 common shares for cancellation in the first quarter of
2004 at an average price of $11.07 per common share. Subsequent
to March 31, 2004, the Company repurchased an additional 825,800
common shares at an average price of $12.72 per common share.
Common shares outstanding at April 30, 2004 totaled 58,465,100.
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.
Paramount's share of net operating income from the partnership
amounted to $0.2 million in the first three months of 2004 (2003
- $0.5 million), which has been recorded in Paramount's
consolidated statement of earnings.
RELATED PARTY TRANSACTIONS
In the first quarter of 2003, the Company transferred certain
natural gas assets in Northeast Alberta to the Trust, a related
party. The transaction is described in Note 3 to the consolidated
financial statements.
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 by 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.
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 expenses and
asset retirement obligation. If reserve estimates decline, the
rate at which the Company records depletion 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.
Asset Retirement Obligation
The asset retirement obligation recorded in the consolidated
financial statements is based on an estimate of the fair value of
the 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, the timing of asset retirement
expenditures 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.
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. Paramount
periodically assesses the realizability of its future tax assets.
If Paramount concludes that it is more likely than not that some
portion or all of the future tax assets will not be realized, the
tax asset would be reduced by a valuation allowance.
RECENT ACCOUNTING PRONOUNCEMENTS
Variable Interest Entities
The CICA recently issued a draft of 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. The Company does not expect the
implementation of this guideline to have a material impact on its
consolidated financial statements.
/T/
Consolidated Balance Sheets
March 31 December 31
-----------------------------------------------------------------------
(thousands of dollars) 2004 2003
-----------------------------------------------------------------------
(unaudited) (restated-note 2)
ASSETS (note 4)
Current Assets
Short-term investments
(market value: 2004 - $18,552;
2003 -$17,265) $ 17,652 $ 16,551
Accounts receivable 82,434 82,363
Financial instruments (note 2 and 6) 4,095 -
Prepaid expenses 2,298 2,282
-----------------------------------------------------------------------
106,479 101,196
-----------------------------------------------------------------------
Property, Plant and Equipment
Property, plant and equipment, at cost 1,557,191 1,459,004
Accumulated depletion and depreciation (457,075) (421,697)
-----------------------------------------------------------------------
1,100,116 1,037,307
-----------------------------------------------------------------------
Goodwill 31,621 31,621
Other Assets (note 4) 6,943 7,006
-----------------------------------------------------------------------
$ 1,245,159 $ 1,177,130
-----------------------------------------------------------------------
-----------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 128,672 $ 110,339
Financial instruments (note 2 and 6) 14,300 -
Current portion of long-term debt
(note 4) 1,468 1,450
-----------------------------------------------------------------------
144,440 111,789
-----------------------------------------------------------------------
Long-term debt (note 4) 344,930 297,111
Asset retirement obligations (note 2) 65,417 61,554
Deferred revenue - 3,959
Future income taxes 199,471 206,684
-----------------------------------------------------------------------
609,818 569,308
-----------------------------------------------------------------------
Commitments and contingencies (note 6)
Shareholders' Equity
Share capital (note 5)
Issued and outstanding
59,290,900 common shares
(2003 - 60,094,600 common shares) 197,702 200,274
Contributed surplus 1,333 746
Retained earnings 291,866 295,013
-----------------------------------------------------------------------
490,901 496,033
-----------------------------------------------------------------------
$ 1,245,159 $ 1,177,130
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Cash Flows (unaudited)
(thousands of dollars)
-----------------------------------------------------------------------
Three Months Ended March 31
-----------------------------------------------------------------------
2004 2003
-----------------------------------------------------------------------
Operating activities (restated-note 2)
Net earnings $ 3,179 $ 314
Add (deduct) non-cash items
Depletion and depreciation 42,140 46,864
(Gain) loss on sales of property
and equipment (445) (271)
Accretion of asset retirement
obligations 1,246 1,057
Future income tax (recovery)
expense (7,213) 3,956
Amortization of other assets 258 -
Non-cash general and
administrative expenses 587 -
Non-cash loss on financial
instruments 10,205 -
Unrealized foreign exchange loss
on US debt 2,590 -
Add items not related to
operating activities
Dry hole costs 3,015 5,821
Geological and geophysical 3,992 748
-----------------------------------------------------------------------
Cash flow from operations 59,554 58,489
Decrease in deferred revenue (3,959) (2,460)
Asset retirement obligation expenditure (63) -
Decrease in other assets (195) -
Change in non-cash operating
working capital (32,199) (28,527)
-----------------------------------------------------------------------
23,138 27,502
-----------------------------------------------------------------------
Financing activities
Current and long term debt - draws 69,989 10,000
Current and long term debt - repayments (24,742) (211,968)
Shareholder loan - (33,000)
Share capital - issued - 10,317
Share capital - repurchased (8,898) -
-----------------------------------------------------------------------
36,349 (224,651)
-----------------------------------------------------------------------
Cash flow (used in) provided by
operating and financing activities 59,487 (197,149)
-----------------------------------------------------------------------
Investing activities
Property, plant and equipment
expenditures (111,996) (52,684)
Proceeds on sale of property,
plant and equipment 3,165 222,832
Change in non-cash investing
working capital 49,344 27,001
-----------------------------------------------------------------------
Cash flow (used in) provided by
investing activities (59,487) 197,149
-----------------------------------------------------------------------
Decrease (increase) in cash - -
Cash, beginning of period - -
-----------------------------------------------------------------------
Cash, end of period $ - $ -
-----------------------------------------------------------------------
Income taxes paid 17,877 5,466
Interest paid 1,555 7,415
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Earnings and Retained Earnings (unaudited)
-----------------------------------------------------------------------
Three Months Ended March 31
-----------------------------------------------------------------------
(thousands of dollars except per
share amounts) 2004 2003
-----------------------------------------------------------------------
(restated-note 2)
Revenue
Petroleum and natural gas sales $ 105,504 $ 150,932
Gain (loss) on financial
instruments (note 6) (6,462) (29,392)
Royalties (net of ARTC) (20,935) (31,217)
Other income 1,072 1,123
-----------------------------------------------------------------------
79,179 91,446
-----------------------------------------------------------------------
Expenses
Operating 18,487 18,866
Interest 4,338 8,001
General and administrative 5,840 4,768
Lease rentals 1,234 775
Geological and geophysical 3,992 748
Dry hole costs 3,015 5,821
Gain on sales of property and equipment (445) (271)
Accretion of asset retirement
obligations (note 2) 1,246 1,057
Depletion and depreciation 42,140 46,864
Unrealized foreign exchange loss
on US debt (note 4) 2,590 -
-----------------------------------------------------------------------
82,437 86,629
-----------------------------------------------------------------------
Earnings (loss) before taxes (3,258) 4,817
-----------------------------------------------------------------------
Income and other taxes (note 7)
Large Corporations Tax and other 776 547
Future income tax (recovery) expense (7,213) 3,956
-----------------------------------------------------------------------
(6,437) 4,503
-----------------------------------------------------------------------
Net earnings 3,179 314
Retained earnings, beginning of
period (note 2) 295,013 355,912
Adjustment on disposition of
assets to a related party (note 3) - (1,388)
Dividends declared (note 3) - (51,000)
Redemption of share capital (note 5) (6,326) -
Adoption of new accounting
policies (note 2) - (4,127)
-----------------------------------------------------------------------
Retained earnings, end of period $ 291,866 $ 299,711
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Net earnings per common share
- basic 0.05 0.01
- diluted 0.05 0.01
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Weighted average common shares
outstanding (thousands)
- basic 59,560 59,998
- diluted 60,209 60,072
-----------------------------------------------------------------------
-----------------------------------------------------------------------
See accompanying notes to consolidated financial statements
/T/
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
(all tabular amounts expressed in thousands of dollars)
Paramount Resources Ltd. ("Paramount" or the "Company") is
involved in the exploration and development of petroleum and
natural gas primarily in western Canada. The interim consolidated
financial statements are stated in Canadian dollars and have been
prepared by management in accordance with Canadian generally
accepted accounting principles ("GAAP"). Certain information and
disclosures normally required to be included in notes to annual
consolidated financial statements have been condensed or omitted.
The interim consolidated financial statements should be read in
conjunction with the consolidated financial statements and the
notes thereto in Paramount's Annual Report for the year ended
December 31, 2003.
The preparation of interim consolidated financial statements
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the interim
consolidated financial statements and the reported amounts of
revenues and expenses during the period. Actual results could
differ from those estimates.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements have been prepared
in a manner consistent with accounting policies utilized in the
consolidated financial statements for the year ended December 31,
2003, except as noted below:
2. CHANGES IN ACCOUNTING POLICIES
Asset Retirement Obligations
Effective January 1, 2004, the Company retroactively adopted,
with restatement, the Canadian Institute of Chartered Accountants
recommendation on Asset Retirement Obligations, which requires
liability recognition for fair value of retirement obligations
associated with long-lived assets.
Under this new recommendation, the Company recognizes the fair
value of an asset retirement obligation in the period in which it
is incurred or when a reasonable estimate of the fair value can
be made. The asset retirement costs equal to the fair-value of
the retirement obligations, are capitalized as part of the cost
of the related long-lived asset and allocated to expense on a
basis consistent with depreciation and depletion. The liability
associated with the asset retirement costs is subsequently
adjusted for the passage of time, and is recognized as accretion
expense in the consolidated statement of earnings. The liability
is also adjusted due to revisions in either the timing or the
amount of the original estimated cash flows associated with the
liability. Actual costs incurred upon settlement of the asset
retirement obligation will reduce the asset retirement liability
to the extent of the liability recorded. Differences between the
actual costs incurred upon settlement of the asset retirement
obligation and the liability recorded are recognized in the
Company's earnings in the period in which the settlement occurs.
As a result of this change, net earnings for the three months
ended March 31, 2004 decreased by $0.3 million ($0.01 per share).
The site restoration liability as at December 31, 2003 increased
by $40.4 million and property, plant and equipment, net of
accumulated depletion, increased by $31.1 million. Opening 2003
retained earnings decreased by $4.1 million to reflect the
cumulative impact of depletion expense and accretion expense, net
of the previously recognized cumulative site restoration
provision and net of related future income taxes on the asset
retirement obligation, recorded retroactively.
The undiscounted asset retirement obligation at March 31, 2004 is
$109.1 million (December 31, 2003 - $104.8 million). The
Company's credit adjusted risk free rate is 7.875%.
Financial Instruments
The Company periodically utilizes derivative financial instrument
contracts such as forwards, futures, swaps and options to manage
its exposure to fluctuations in petroleum and natural gas prices,
the Canadian/U.S. dollar exchange rate and interest rates.
Emerging Issues Committee Abstract 128, "Accounting for Trading,
Speculative or Non Trading Derivative Financial Instruments"
("EIC 128") establishes accounting and reporting standards
requiring that every derivative instrument that does not qualify
for hedge accounting be recorded in the consolidated balance
sheet as either an asset or liability measured at fair value.
Accounting Guideline 13, Hedging Relationships, ("AcG 13"), which
was effective for years beginning after July 1, 2003, establishes
the need for companies to formally designate, document and assess
the effectiveness of relationships that receive hedge accounting
treatment.
The Company's policy is to account for those derivative financial
instruments in which management has formally documented its risk
objectives and strategies for undertaking the hedged transaction
as hedges. For these instruments, the Company has determined that
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 transaction being hedged. The Company
assesses the effectiveness of the derivative on an ongoing basis
to ensure that the derivatives entered into are highly effective
in offsetting changes in fair values or cash flows of the hedged
items. The fair value of derivative financial instruments
designated as hedges are not reflected in the consolidated
financial statements. Derivative financial instruments not
formally designated as hedges are measured at fair value and
recognized on the consolidated balance sheet with changes in the
fair value recognized in earnings during the period.
As at January 1, 2004, the Company had elected not to designate
any of its financial instruments as hedges under AcG 13 and has
fair-valued the derivatives and recognized the gains and losses
on the consolidated balance sheet and statement of earnings. The
impact on the Company's consolidated financial statements at
January 1, 2004, resulted in the recognition of financial
instrument assets with a fair value of $3.3 million, a financial
instrument liability of $1.8 million for a net deferred gain on
financial instrument of $1.5 million (note 6).
3. DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST
During the first quarter of 2003, the Company completed the
formation and structuring of Paramount Energy Trust (the "Trust")
through the following transactions:
a) On February 3, 2003, Paramount transferred to the Trust
natural gas properties in the Legend area of Northeast Alberta
for net proceeds of $28 million and 9,907,767 units of the Trust.
b) On February 3, 2003, Paramount declared a dividend-in-kind of
$51 million, consisting of an aggregate of 9,907,767 units of the
Trust. The dividend was paid to shareholders of Paramount's
common shares of record on the close of business on February 11,
2003.
c) On March 11, 2003, in conjunction with the closing of a rights
offering by the Trust, Paramount disposed of additional natural
gas properties in Northeast Alberta to Paramount Operating Trust
for net proceeds of $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.
/T/
4. LONG-TERM DEBT
Current portion of long-term debt as at:
-----------------------------------------------------------------------
March 31, December 31,
2004 2003
-----------------------------------------------------------------------
Drilling rig indebtedness -
current interest rate of 6.00%(2003 - 6.82%) $ 1,151 $ 1,138
Mortgage -interest rate of 6.15% 317 312
-----------------------------------------------------------------------
$ 1,468 $ 1,450
-----------------------------------------------------------------------
-----------------------------------------------------------------------
The Company has letters of credit totaling $19.9 million
(December 31, 2003 - $10.3 million) outstanding with a Canadian
chartered bank. These letters of credit reduce the amount available
under the Company's working capital facility.
Long-term debt:
-----------------------------------------------------------------------
March 31, December 31,
2004 2003
-----------------------------------------------------------------------
U.S. Senior Notes - interest rate of 7.875% $ 229,477 $ 226,887
Credit facility -
current interest rate of 3.6% (2003 - 4.5%) 105,929 60,350
Drilling rig indebtedness -
current interest rate of 6.00% (2003 - 6.82%) 3,187 3,456
Mortgage - interest rate of 6.15% 6,337 6,418
-----------------------------------------------------------------------
$ 344,930 $ 297,111
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/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 senior unsecured indebtedness. For the three months ended
March 31, 2004, an unrealized foreign exchange loss of $2.6
million (2003 - nil) was recognized on the consolidated statement
of earnings.
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.
The Company has a $203 million committed revolving/non-revolving
term facility with a syndicate of Canadian chartered banks.
Borrowings under the facility bear interest at the lender's prime
rate, banker's acceptance, or LIBOR rate plus an applicable
margin dependent on certain conditions. The revolving nature of
the facility is due to expire on March 31, 2005. The Company may
request an extension on the revolving credit facility of up to
364 days, subject to the approval of the lenders. To the extent
that any lenders participating in the syndicate do not approve
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, 2006. Advances drawn on the facility are
secured by a fixed charge over the assets of the Company.
The Company has an office building that is mortgaged at an
interest rate of 6.15 percent over a term of 5 years ending
December 31, 2007.
5. SHARE CAPITAL
Authorized Capital
The authorized capital of the Company is comprised of an
unlimited number of non-voting preferred shares without nominal
or par value, issuable in series, and an unlimited number of
common shares without nominal or par value.
/T/
Issued Capital ----------------------------------------------------------------------- Common Shares Number Consideration ----------------------------------------------------------------------- Balance December 31, 2002 59,458,600 $ 190,193 Stock options exercised during the year 710,000 10,317 Shares repurchased - at carrying value (74,000) (236) ----------------------------------------------------------------------- Balance December 31, 2003 60,094,600 $ 200,274 ----------------------------------------------------------------------- Shares repurchased - at carrying value (803,700) (2,572) ----------------------------------------------------------------------- Balance March 31, 2004 59,290,900 $ 197,702 ----------------------------------------------------------------------- -----------------------------------------------------------------------
/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 the
three months ended March 31, 2004, 803,700 shares were purchased
pursuant to the plan at an average price of $11.07 per share.
$6.3 million has been charged to retained earnings related to
share repurchase price in excess of the carrying value of the
shares.
Subsequent to March 31, 2004, the Company re-purchased 825,800
common shares at an average price of $12.72 per share.
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 March 31, 2004, 5.9 million shares were reserved for
issuance under the Company's Employee Incentive Stock Option
Plan, of which 3.5 million options are outstanding, exercisable
to September 30, 2008, at prices ranging from $8.91 to $12.51 per
share.
/T/
-----------------------------------------------------------------------
Stock options Three months ended
March 31, 2004
-----------------------------------------------------------------------
Average grant price Options
-----------------------------------------------------------------------
Balance, beginning of period $ 9.64 3,632,000
Granted 11.51 78,000
Exercised 9.73 (146,250)
Cancelled 9.57 (27,500)
-----------------------------------------------------------------------
Balance, end of period $ 9.68 3,536,250
-----------------------------------------------------------------------
Options exercisable, end of period $ 10.86 949,625
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
During the three months ended March 31, 2004, 146,250 stock
options were exercised for cash consideration of $0.4 million,
which has been charged to general and administrative expense
(2003 - nil).
The following table summarizes information about stock options
outstanding at March 31, 2004:
/T/
-----------------------------------------------------------------------
Outstanding Exercisable
Weighted Weighted Weighted
Average Average Average
Exercise Contractual Exercise Exercisable Exercise
Prices Number Life Price Number Price
-----------------------------------------------------------------------
$ 8.91-9.80 2,432,750 3 $ 9.02 255,125 $ 9.00
$10.01-12.51 1,103,500 2 $11.14 694,500 $11.55
-----------------------------------------------------------------------
Total 3,536,250 3 $ 9.68 949,625 $10.86
-----------------------------------------------------------------------
/T/
6. FINANCIAL INSTRUMENTS
As disclosed in Note 2, on January 1, 2004, the fair value of all
outstanding financial instruments that are not designated as
accounting hedges was recorded on the consolidated balance sheet
with an offsetting net deferred gain. The net deferred gain is
recognized into net earnings over the life of the associated
contracts. Changes in fair value associated with those financial
instruments are recorded on the consolidated balance sheet with
the associated unrealized gain or loss recorded in net earnings.
The estimated fair value of all financial instruments is based on
quoted prices or, in the absence, third party market indications
and forecasts.
The following tables present a reconciliation of the change in
the unrealized and realized gains and losses on financial
instruments from January 1, 2004 to March 31, 2004.
/T/
-----------------------------------------------------------------------
March 31, 2004
-----------------------------------------------------------------------
Financial instrument asset $ 4,095
Financial instrument liability (14,300)
-----------------------------------------------------------------------
Net financial instrument liability $ (10,205)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Net deferred
amounts on Mark-to-market
transition gain/loss Total
-----------------------------------------------------------------------
Fair value of contracts,
January 1, 2004 $ (1,450) $ 1,450 $ -
Change in fair value of contracts
recorded on transition, still
outstanding at March 31, 2004 - (4,727) (4,727)
Amortization of the fair value
of contracts as at March 31, 2004 (218) - (218)
Fair value of contracts entered
into during the period - (5,260) (5,260)
-----------------------------------------------------------------------
Unrealized loss on financial
instruments $ (1,668) $ (8,537) $ (10,205)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Realized gain (loss) on financial
instruments for the period
ended March 31, 2004 3,743
-----------------------------------------------------------------------
Net gain (loss) on financial
instruments for the period
ended March 31, 2004 $ (6,462)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
(a) FOREIGN EXCHANGE CONTRACTS
The Company has entered into the following currency index swap
transactions, fixing the exchange rate on receipts of US $21.0
million for CDN $30.1 million over the next two years at CDN
$1.4337. The US$/CDN$ closing exchange rate was 1.3113 as at
March 31, 2004 (December 31, 2003 - 1.2965).
/T/
Year of settlement U.S. dollars Weighted average exchange rate
-----------------------------------------------------------------------
2004 $ 9,000 1.4337
2005 12,000 1.4337
-----------------------------------------------------------------------
$ 21,000 1.4337
-----------------------------------------------------------------------
/T/
At January 1, 2004, the Company recorded a deferred gain on
financial instruments of $3.3 million related to existing foreign
exchange contracts. The fair value of these contracts at March
31, 2004, was a gain of $2.6 million. The change in fair value, a
$0.7 million loss, and $0.8 million amortization of the deferred
gain have been recorded in the consolidated statement of
earnings.
(b) COMMODITY PRICE CONTRACTS
At March 31, 2004, the Company has entered into financial forward
sales arrangements as follows:
/T/
----------------------------------------------------------------------- AECO Price Term ----------------------------------------------------------------------- 10,000 GJ/d $5.51 April 2004 - October 2004 10,000 GJ/d $5.55 April 2004 - October 2004 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 (collar) $5.25-$6.80 April 2004 - October 2004 10,000 GJ/d (collar) $5.25-$6.75 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/
At January 1, 2004, the Company recorded a deferred loss on
financial instruments of $1.8 million related to existing forward
commodity price contracts. The fair value of these contracts at
March 31, 2004, was a loss of $5.8 million. The change in fair
value, a $4.0 million loss, and $1.0 million amortization of the
deferred loss have been recorded in the consolidated statement of
earnings. At March 31, 2004, a $5.3 million loss was recorded in
the consolidated statement of earnings related to the fair value
of financial contracts entered into after January 1, 2004. No
deferred gains or losses were recorded related to these financial
contracts.
7. INCOME TAXES
In March, 2004, the Government of Alberta introduced legislation
to reduce its corporate income tax rate by 1 percent, effective
January 1, 2004. The change is considered substantively enacted
for the purposes of Canadian GAAP and, accordingly, the Company's
future income tax liability has been reduced by $5.2 million. The
effect of this reduction has been recognized in the future income
tax recovery for the three month period ended March 31, 2004.
8. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform
with the current period's financial statement presentation.
