Paramount Resources Ltd.: Financial and Operating Results for the Second Quarter Ended June 30, 2004
FOR: PARAMOUNT RESOURCES LTD.
TSX SYMBOL: POU
AUGUST 5, 2004 - 08:30 ET
Paramount Resources Ltd.: Financial and Operating
Results for the Second Quarter Ended June 30, 2004
CALGARY, ALBERTA - Aug. 5, 2004 /CNW/ - Paramount
Resources Ltd. ("Paramount" or the "Company") is pleased to
announce its financial and operating results for the second
quarter ended June 30, 2004.
/T/
Financial Highlights
($ thousands except per share amounts and where stated otherwise)
Three Months Ended June 30 Six Months Ended June 30
2004 2003 %Change 2004 2003 %Change
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FINANCIAL
Petroleum and
natural gas sales 125,616 101,512 24% 231,120 251,217 -8%
Cash flow (1)
From operations 69,515 36,697 89% 128,592 94,877 36%
Per share - basic 1.19 0.61 94% 2.18 1.58 38%
- diluted 1.17 0.61 92% 2.15 1.57 37%
Earnings
Net earnings (loss) 9,936 (1,888) 626% 13,115 (1,574) 933%
Per share - basic
and diluted 0.17 (0.03) 667% 0.22 (0.03) 833%
Capital expenditures
Exploration and
development 45,916 50,586 -9% 156,331 103,068 52%
Acquisitions,
dispositions
and other 183,182 (38,434) 577% 180,243 (260,991) 169%
Net capital
expenditures 229,098 12,152 1785% 336,574 (157,923) 313%
Total assets (3) 1,469,943 1,177,130 25%
Net debt (2) (3) 560,866 303,110 85%
Shareholders'
equity(3) 490,942 496,033 -1%
Common shares
outstanding
(thousands)
- June 30 58,465 60,095 -3%
- July 31 58,481
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OPERATING
Production
Natural gas (MMcf/d) 157 142 11% 149 167 -11%
Crude oil and
liquids (Bbl/d) 6,134 7,465 -18% 5,905 7,677 -23%
Total production
(Boe/d) @ 6:1 32,354 31,129 4% 30,766 35,584 -14%
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Average prices
Natural gas
(pre-hedge)($/Mcf) 7.01 5.91 19% 6.78 6.45 5%
Natural gas
($/Mcf)(4) 6.70 4.84 38% 6.82 5.13 33%
Crude oil and
liquids (pre-hedge)
($/Bbl) 45.37 36.94 23% 43.69 40.03 9%
Crude oil and
liquids ($/Bbl) (4) 42.62 35.27 21% 39.89 37.15 7%
Drilling activity
(gross)
Gas 24 29 -17% 102 96 6%
Oil - 5 -100% 5 10 -50%
Oilsands evaluation(5) - - - 17 - -
D&A - 3 -100% 6 8 -25%
Total wells 24 37 -35% 130 114 14%
Success rate (5) 100% 92% 9% 95% 93% 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 including working capital
excluding the current liabilities of discontinued operations.
(3) Comparative figures are as at December 31, 2003.
(4) Excludes non-cash gains and losses on financial instruments.
(5) Success rate excludes oilsands evaluation wells.
/T/
Review of Operations
The 2004 second quarter daily production for Paramount Resources
Ltd. ("Paramount" or the "Company") averaged 157 MMcf/d of
natural gas and 6,134 Bbl/d of oil and natural gas liquids. Total
production for the quarter was 32,354 Boe/d, an 11 percent
increase compared to 29,178 Boe/d in first quarter of 2004.
Drilling was less active in the second quarter as a result of
spring break up with a total of 24 wells (17 net) drilled,
resulting in 24 gross gas wells (17 net) for a 100 percent
success rate.
Kaybob
Natural gas production volumes were up 6 MMcf/d, an eight percent
increase from the first quarter, averaging 90 MMcf/d in the
second quarter. The higher production volumes were the result of
improved on-stream performance in the second quarter compared to
the operational difficulties caused by the cold weather during
the first three months of the year. Oil and natural gas liquids
volumes averaged 2,543 Bbl/d in the second quarter versus 2,454
Bbl/d in the first quarter as the result of higher natural gas
production.
Second quarter 2004 capital expenditures were approximately $10
million, bringing year-to-date capital spending to $40 million
for the Kaybob Operating Unit. Third and fourth quarter capital
expenditures are expected to be around $60 million, reflecting
the increase in drilling, completion and construction activities.
Field activities in Kaybob resumed in late May after being shut
down for most of the quarter due to the early spring break up.
Paramount participated in the drilling of 8 (5.0 net) wells in
the quarter; all were cased for gas potential. These wells will
be completed in the third quarter and are forecast to be on
production prior to the end of the year. Construction was also
completed on the pipelines to tie in 4 MMcf/d of natural gas that
was stranded at the end of the first quarter; an additional 4
MMcf/d will also be on-stream in the third quarter.
With the closing of the Kaybob asset acquisition on June 30,
production in Kaybob is forecast to be significantly higher for
the remainder of the year. The acquisition will add approximately
20 MMcf/d and 3,300 Bbl/d of oil and natural gas liquids or
approximately 6,600 Boe/d to the Kaybob Operating Unit. Third and
fourth quarter production volumes including the newly acquired
assets are expected to be in the 25,000 Boe/d range. Field
operations associated with the acquired assets are currently
being integrated into the existing Paramount operations.
Exploitation, development and exploration operations in the
Kaybob area will increase in the third and fourth quarters.
Paramount currently has two drilling rigs and three service rigs
active in Kaybob and anticipates this to increase to four
drilling rigs and four service rigs by the end of the year.
Operations will continue to be focused on down-spacing
opportunities and optimization of existing well bores and
infrastructure. The acquisition will provide additional
opportunities that will be funded from the existing 2004 Kaybob
capital budget of approximately $100 million.
Grande Prairie
Production averaged 21 MMcf/d and 579 Bbl/d for a total of 4,093
Boe/d, a one percent increase from the first quarter production
of 4,058 Boe/d. Four wells were turned on in the second quarter
resulting in an additional 3 MMcf/d (initial rate) of production.
The third-party facility limitations at Berry Lake will be
mitigated by an expansion to be completed in the third quarter.
This should further increase production by about 3 MMcf/d. At
Mirage, the third-party pipeline will be looped in the third
quarter to remove the current bottleneck which will allow further
production increases.
To avoid higher drilling costs associated with wet weather, most
activities in the Grande Prairie area were deferred to late in
the second quarter and early in the third quarter. The major
accomplishments for the second quarter were the drilling of 5
(4.4 net) wells, completing 2 (2.0 net) wells, the tie in of 3
(3.0 net) wells and the installation of a compressor.
Paramount is currently drilling a 3,800 metre exploratory well in
Valhalla. Some new gas discoveries have been made in the Mirage
area. The Company is continuing to develop the shallow gas
resource play with 20 wells planned at Mirage. This drilling
program is to follow up primarily on the success in the shallow
Dunvegan gas play but is also targeting deeper zones. Completions
of the second quarter new drills are ongoing and early
indications are that they have been successful.
Land acquisitions through Crown land sales and farm-ins have
significantly added to Paramount's position on key play types in
the Saddle Hills and Mirage areas. The acquisition at Kaybob also
included some assets in the Elmworth area and has also added
non-operated production and undeveloped land position in this
classic deep basin area.
Northwest Alberta
Northwest Alberta's second quarter production averaged 23 MMcf/d
of natural gas and 967 Bbl/d of liquids, for a total of 4,731
Boe/d, a 52 percent increase over first quarter production of
3,114 Boe/d which was hampered by the extended turnaround. The
expanded Haro facility came on-stream during the first week of
June. This expansion has allowed the Company to increase its
production from 1.8 MMcf/d to 5 MMcf/d. Efforts are ongoing to
match production throughput to the facility ownership capacity of
6 MMcf/d.
Capital expenditures to the end of the second quarter amounted to
$29 million. No drilling or completion activities were undertaken
in Northwest Alberta and Cameron Hills in the second quarter due
to winter-only access in the area. Evaluations of 2D and 3D
seismic acquired during the winter in Bistcho and Cameron Hills
are ongoing in an effort to firm up drilling locations for the
coming winter season targeting middle Devonian opportunities.
Follow-up drilling locations in Haro are also being developed
targeting Mississippian subcrop objectives.
Northwest Territories/Northeast British Columbia
Production from the four producing properties in this area
remained steady at 10 MMcf/d for the second quarter of 2004.
Paramount acquired the operator's interest in the Nahanni pool at
Fort Liard and has assumed the operatorship of this facility. The
acquisition adds 20 MMcf/d of natural gas production commencing
the second half of 2004. The acquisition also added undeveloped
land totaling 61,173 net hectares in the Patry/Maxhamish area.
Over 1,700 kilometers of seismic data covering portions of
northeast British Columbia and the Northwest Territories were
included and will be used to delineate additional exploration
prospects in the Liard basin area.
During the second quarter, the 2M-25 location at Fort Liard was
drilled and cased with completion and testing operations
currently underway. It is anticipated that 2M-25 will be tied in
and on production in the third quarter. Additional workover
activities at M-25 and 2K-29 will also be completed later this
year.
At Colville Lake, two parcels of land were purchased in June.
Paramount acquired a 50 percent working interest in Exploration
License 426 which offsets the Nogha discovery and covers 36,728
hectares. Further to the south, Paramount acquired a 100 percent
interest in Exploration License 424 which is adjacent to EL 414
and covers 80,608 hectares.
Southern
Production in the second quarter of 2004 from the Southern
Operating Unit averaged 11 MMcf/d and 2,065 Bbl/d or 3,845 Boe/d.
This is a seven percent increase over the first quarter
production of 3,579 Boe/d. Production increases in the quarter
can be attributed to new production which was tied in at Chain,
de-bottlenecking operations in Chain and Retlaw, and successful
recompletions in Sylvan Lake and Beaver Creek, North Dakota.
Paramount participated in 10 (7.1 net) exploration wells, seven
of which were 100 percent operations, four in Saskatchewan, two
in Chain, and one at Enchant. All wells were cased for
evaluation. The Company also participated in 5 (4.3 net)
completion wells, three in Chain/Craigmyle, one in Sylvan Lake,
and one in Beaver Creek, North Dakota.
The Horseshoe Canyon coal gas play has continued to gather steam
throughout south central Alberta with a multitude of companies
announcing projects and new production coming on daily. We are
well placed in Chain to take advantage of this play with our land
base and infrastructure.
Northeast Alberta
Paramount has submitted an AEUB application for a Gas
Re-Injection & Production Experiment at Surmont in order to
initiate production from natural gas pools which are in potential
communication to the commercial bitumen resources. This
experiment involves the collection and re-injection of up to 4
MMcf/d of compressor exhaust gases to maintain reservoir pressure
while producing a similar volume of natural gas. The pilot is
expected to start-up in the second quarter of 2005. This
experiment could also offer the opportunity to sequester other
green house gases such as carbon dioxide.
Acquisitions and Divestitures
On June 30, 2004, Paramount closed the acquisition of oil and
natural gas assets in the Kaybob area in central Alberta and in
the Fort Liard area in the Northwest Territories and northeast
British Columbia for $189 million, before customary adjustments.
The properties are producing approximately 10,000 Boe/d,
comprised of 40 MMcf/d of natural gas and 3,300 Bbl/d of oil and
natural gas liquids. The proved reserves attributable to the
properties as of the effective date, June 1, 2004, are estimated
to be approximately 47.2 Bcf of natural gas and 4.4 million Bbl
of oil and natural gas liquids, or a total of 12.3 million Boe;
and proved plus probable reserves of approximately 93.6 Bcf of
natural gas and 6.7 million Bbl of oil and natural gas liquids,
or a total of 22.2 million Boe.
Subsequent to the end of the second quarter, Paramount entered
into an agreement to acquire assets in our Marten Creek producing
area in Grande Prairie for $83.7 million, subject to adjustments.
The assets to be acquired are currently producing approximately
14 MMcf/d of natural gas, or 2,300 Boe/d. The reserves
attributable to the properties as of July 1, 2004, as estimated
by McDaniel and Associates, consist of proved reserves of
approximately 17.4 Bcf of natural gas, or 2.9 million Boe, and
proved plus probable reserves of approximately 22.2 Bcf or 3.7
million Boe. Closing is expected to occur in mid August.
Paramount has also entered into agreements to divest
approximately 1,000 Boe/d of non-core oil and gas assets for
$42.2 million. In addition, the Company is also divesting its
investment in Wilson Drilling Ltd., a private drilling company in
which Paramount owns a 50 percent equity interest for $32
million, $16 million net to Paramount. Since the second quarter
of this year, the Company has liquidated all or part of its
investments in Harvest Energy Trust, Altius Energy Corporation
and Spearhead Resources Inc., receiving a total of approximately
$13 million. The Company is also investigating the possibility of
disposing of its commercial real estate.
The proceeds from the disposition of these non-core assets are
expected to total in excess of $80 million which funds the
acquisition of the strategic oil and gas assets in Marten Creek.
The result of all of these transactions is a net increase of
approximately 1,300 Boe/d in production.
Financing
On June 29, 2004, Paramount issued US $125 million of 8 7/8
percent Senior Notes due 2014 and used the proceeds from the
offering to finance the Company's acquisition of oil and natural
gas assets in the Kaybob and Fort Liard areas. On July 20, 2004,
Paramount's borrowing capacity under its credit facility was
increased to $250 million. The combined debt financing available
is now approximately $650 million.
Financial
Petroleum and natural gas sales before hedging totaled $125.6
million for the three months ended June 30, 2004 as compared to
$101.5 million for the comparable period in 2003. The increase is
due to higher production as a result of the Company's successful
exploration and development activities as well as higher natural
gas prices as compared to the second quarter of 2003.
Cash flow from operations for the three months ended June 30,
2004 totaled $69.5 million or $1.17 per diluted common share as
compared to $36.7 million or $0.61 per diluted common share for
the second quarter of 2003. The 89 percent increase resulted
primarily from higher petroleum and natural gas revenues due to
increased production and higher commodity prices.
Paramount recorded net earnings for the current quarter of $9.9
million or $0.17 per diluted common share as compared to a net
loss of $1.9 million or $0.03 per diluted common share for the
comparable period in 2003. The increase in earnings is primarily
the result of higher petroleum and natural gas revenues due to
increased production and higher commodity prices as well as
decreased financial instrument losses.
Capital expenditures in the second quarter of 2004 were $45.9
million comprised of $18.7 million for drilling and completions,
$15.6 million for facilities expenditures, $9.8 million for land
and $1.8 million for geological and geophysical expenditures. Net
debt at the end of the second quarter was $560.9 million and will
continue to be reduced through the remainder of the year as
Paramount expects cash flow for operations will exceed capital
expenditures.
Outlook
Paramount now forecasts its production to average 180 MMcf/d of
natural gas and 7,500 Bbl/d of oil and natural gas liquids, or a
total of 37,500 Boe/d for all of 2004. Current production,
including the acquisition, is approximately 200 MMcf/d and over
9,000 Bbl/d, or in excess of a total of 42,500 Boe/d. Paramount
forecasts cash flow in 2004 to be about $300 million or
approximately $5.00/share and net capital expenditures to total
$460 million. Net debt levels at year end giving effect to the
acquisition are projected to be around $480 million which would
equate to a debt to cash flow ratio of approximately 1.6 times.
A conference call will be held with the senior management of
Paramount Resources Ltd. to answer questions with respect to the
second quarter results on Thursday, August 5, 2004 at 9:00 a.m.
MST. 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.fulldisclosure.com.
A replay of the conference call will be available from an hour
after the call until August 12, 2004. The number for the replay
is 1-800-408-3053 or 1-416-695-5800 with passcode number 3085676.
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 six
months ended June 30, 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 and six months ended June 30, 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 July 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.
SIGNIFICANT EVENTS
$189 MILLION ASSET ACQUISITION
On June 30, 2004, Paramount completed the acquisition of assets
in the Kaybob area of central Alberta and the Fort Liard area of
the Northwest Territories for $185.1 million, after adjustments.
The properties to be acquired are currently producing
approximately 10,000 Boe/d, comprised of 40 MMcf/d of natural gas
and 3,300 Bbl/d of oil and natural gas liquids ("NGL"). The
reserves attributable to the properties as of June 1, 2004 are
estimated by Paramount to consist of proved reserves of
approximately 47.2 Bcf of natural gas and 4.4 million Bbl of oil
and NGL, or a total of 12.3 million Boe, and proved plus probable
reserves of approximately 93.6 Bcf of natural gas and 6.7 million
Bbl of oil and NGL, or a total of 22.2 million Boe.
ISSUANCE OF US $125 MILLION OF LONG-TERM SENIOR NOTES
On June 29, 2004, the Company issued US $125 million 8 7/8
percent Senior Notes due 2014. Proceeds from the Senior Notes
issuance were used to finance the $189 million asset acquisition.
Interest on the note is payable semi-annually, beginning in 2005.
The Company may redeem some or all of the notes at any time after
July 15, 2009, at redemption prices ranging from 100 percent to
104.438 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 July 15, 2007 at 108.875 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 the Company's existing
and future senior unsecured indebtedness. The financing charges
related to the issuance of the senior notes are capitalized to
other assets and amortized evenly over the term of the notes.
DISCONTINUED OPERATIONS
On July 27, 2004, Wilson Drilling Ltd. ("Wilson"), a private
drilling company in which Paramount owns a 50 percent equity
interest, closed the sale of Wilson's drilling assets for $32
million to a publicly traded Income Trust. The proceeds were
$19.2 million in cash with the balance in exchangeable shares.
The exchangeable shares can be redeemed for trust units in the
Income Trust, subject to customary securities laws and
regulations. In connection with the closing of the sale, certain
indebtedness related to these operations will be extinguished.
For reporting purposes, $6.2 million of capital assets, $4.4
million of current and long-term debt, and a $0.1 million loss
have been classified as discontinued operations as at, and for
the six months ended, June 30, 2004.
/T/
REVENUE AND PRODUCTION
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Three months Six months
ended June 30 ended June 30
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Revenue
(thousands of dollars) 2004 2003 2004 2003
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Natural gas $ 100,288 $ 76,418 $ 184,167 $ 195,596
Oil and natural gas liquids 25,328 25,094 46,953 55,621
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Petroleum and natural
gas revenue 125,616 101,512 231,120 251,217
(Loss) on financial
instruments (6,297) (15,218) (12,759) (44,322)
(Loss) on sale of
short-term investments (34) (1,020) (34) (1,020)
Other (283) (478) 199 225
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Gross revenue $ 119,002 $ 84,796 $ 218,526 $ 206,100
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/T/
Natural gas revenue for the six months ended June 30, 2004
decreased six percent to $184.2 million as compared to $195.6
million for the comparable period in 2003. The decrease in
natural gas revenue results primarily from lower production
levels partially offset by higher natural gas prices received
during the period. Natural gas production volumes for the six
month period ended June 30, 2003 decreased 11 percent to 149
MMcf/d as compared to 167 MMcf/d for the comparable period 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. This decrease was
partially offset by new production in the Kaybob area.
Paramount's average year-to-date natural gas sales price before
hedging increased five percent to $6.78/Mcf as compared to
$6.45/Mcf for the comparable period in 2003.
Natural gas revenue for the three months ended June 30, 2004
increased 31 percent to $100.3 million as compared to $76.4
million for the same period in 2003. The increase in natural gas
revenue resulted primarily from an increase in production levels
combined with higher natural gas prices.
Total natural gas production volumes for the three months ended
June 30, 2004 increased 11 percent to average 157 MMcf/d as
compared to 141 MMcf/d in the first quarter of 2004. The increase
in natural gas volumes were primarily the result of new natural
gas production from the Kaybob area combined with Northwest
Alberta returning to normal production levels, as the first
quarter production was affected by a scheduled,
maintenance-related facility shut-down.
Oil and NGL revenue during the six months ended June 30, 2004,
decreased 15 percent to $47.0 million as compared to $55.6
million for the comparable period in 2003, primarily due to lower
production levels partially offset by higher commodity prices
received during the period. Oil and NGL sales volumes decreased
23 percent to average 5,905 Bbl/d for the six months ended June
30, 2004 as compared to 7,677 Bbl/d for the comparable six months
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. Paramount's average year to date oil
and NGL sales price before hedging was $43.69/Bbl for the period
as compared to $40.03/Bbl in the comparable period in 2003.
Oil and NGL revenue for the three months ended June 30, 2004
increased one percent to $25.3 million as compared to $25.1
million for the same period in 2003. The increase in oil and NGL
revenue resulted primarily from the higher oil and NGL prices
received during the period offset by lower production volumes.
Current quarter production was 6,134 Bbl/d compared to 7,465
Bbl/d in the comparable period in 2003. Second quarter oil and
NGL production increased eight percent as compared to 5,675 Bbl/d
of production for the first quarter of 2004. The increase is the
result of Northwest Alberta returning to normal production
levels.
FINANCIAL INSTRUMENTS
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 June 30, 2004, Paramount had the following forward commodity price
contracts in place:
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AECO Price Term
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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
20,000 GJ/d $7.90 November 2004 - March 2005
20,000 GJ/d $8.03 November 2004 - March 2005
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WTI
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1,000 Bbl/d US $25.00 - $30.25 collar January 2004 - December 2004
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/T/
The Company also has in place foreign exchange forward contracts,
which have fixed the exchange rate on US $18.0 million for CDN
$25.8 million over the next two years at CDN $1.4337.
On June 6, 2004, the Company entered into a fixed to floating
interest rate swap. The Company swapped US$ 7.875 percent fixed
interest for US$ LIBOR plus 320 basis points on the Company's US
$175 million Senior Notes.
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-Hedging 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 are being recognized in the earnings over the term of the
related contracts. Amortization for the six months ended June 30,
2004 totaled $1.5 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 $0.7 million.
In addition, the Company recorded a financial instrument
liability at June 30, 2004 with a fair value of $10.3 million.
This amount reflects the unrealized changes in fair value of
Paramount's financial instruments.
The total loss on financial instruments for the quarter of $12.8
million is comprised of the afore-mentioned mark-to-market before
tax loss on forward contracts of $10.3 million, net amortization
expense of $0.7 million, and cash losses on financial instruments
of $1.7 million related to monthly settlements with
counterparties. The $1.7 million realized cash losses on
financial instruments for the six months ended June 30, 2004 is a
96 percent decrease from the $44.3 million of realized cash
losses on financial instruments for the 2003 comparative period.
/T/
-----------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
-----------------------------------------------------------------------
Cash Netbacks
Per Unit of Production ($/Boe) 2004 2003 2004 2003
-----------------------------------------------------------------------
Gross revenue before
financial instruments $ 42.56 $ 35.31 $ 41.30 $ 38.88
Royalties 7.89 6.95 7.89 7.90
Operating costs 6.54 6.46 6.74 5.77
-----------------------------------------------------------------------
Operating netback 28.13 21.90 26.67 25.21
-----------------------------------------------------------------------
Loss on financial
instruments (1) 1.86 5.37 0.31 6.88
General and administration (2) 1.69 1.59 1.82 1.43
Interest (3) 1.81 1.47 1.66 1.74
Lease rentals 0.30 0.25 0.38 0.23
Bad debt (recovery) (1.73) - (0.91) -
Current and Large
Corporations tax 0.60 0.26 0.46 0.20
-----------------------------------------------------------------------
Cash flow netback $ 23.60 $ 12.96 $ 22.95 $ 14.73
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(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 $44.2 million for the six months
ended June 30, 2004, as compared to $50.9 million for the
comparable period in 2003, due largely to decreased petroleum and
natural gas revenues as a result of lower production during the
period. As a percentage of petroleum and natural gas sales,
royalties averaged 19 percent in the current period as compared
to 20 percent for 2003.
For the three months ended June 30, 2004, royalties totaled $23.2
as compared to $19.7 million during the same period a year
earlier. The increase is primarily the result of increased
petroleum and natural gas revenues during the period.
OPERATING COSTS
For the six months ended June 30, 2004, operating costs totaled
$37.8 million compared to $37.2 million during the same period a
year earlier. On a unit-of-production basis, average operating
costs increased 17 percent to $6.74/Boe from $5.77/Boe. The
increase reflects a general increase in the cost of field
services and supplies, as compared to the prior year. For the
three months ended June 30, 2004, average operating costs on a
unit-of-production basis, decreased six percent to average
$6.54/Boe as compared to $6.96/Boe for the first quarter of 2004.
Unit costs for the first quarter of 2004 were affected by
scheduled, facility maintenance and repair costs in the Northwest
Alberta area.
/T/
GENERAL AND ADMINISTRATIVE EXPENSES
-----------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
-----------------------------------------------------------------------
General and Administrative
Expenses (thousands of dollars) 2004 2003 2004 2003
-----------------------------------------------------------------------
General and administrative
expenses $ 5,334 $ 4,637 $ 10,201 $ 9,179
Stock-based compensation
expensed 240 (141) 1,196 -
-----------------------------------------------------------------------
Total general and
administrative expenses $ 5,574 $ 4,496 $ 11,397 $ 9,179
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
General and administrative expenses totaled $11.4 million for the
six months ended June 30, 2004, as compared to $9.2 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 $1.82/Boe as compared to $1.43/Boe for the six month period
ended June 30, 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 for the six months ended June 30, 2004,
decreased 13 percent to $9.8 million from $11.2 million for the
same period in 2003, as a result of lower debt levels resulting
from the Trust disposition. Interest expense for the three months
ended June 30, 2004 was $5.6 million, a 30 percent increase from
$4.3 million in the previous quarter. The Company's second
quarter average debt level was higher as a result of the first
quarter capital expenditure program and the $189 million asset
acquisition. During the first quarter, capital expenditures
exceeded cash flow from operations and the Company drew down its
credit facility to finance the cash short falls. For the
remainder of the year, cash from operations is expected to exceed
the Company's capital expenditure program. It is anticipated the
excess will be used to pay down the debt.
DEPLETION AND DEPRECIATION
Depletion and depreciation ("D&D") expense increased to $84.5
million from $84.2 million for the six months ended June 30,
2004, primarily due to a higher depletion and depreciation rate.
On a unit-of-production basis, depletion and depreciation costs
increased to $15.09/Boe as compared to $13.07/Boe for the first
six months 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 Obligations
described in note 2 to the unaudited consolidated financial
statements. Expired mineral leases included in D&D expense for
the three-month and six-month period ended June 30, 2004 totaled
$2.0 million and $4.9 million, respectively (2003 - $0.7 million
and $3.4 million respectively).
Capital costs associated with undeveloped land and exploratory,
non-producing petroleum and natural gas properties of $257.7
million are excluded from costs subject to depletion (2003 - $286
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
-----------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
-----------------------------------------------------------------------
(thousands of dollars,
except per share amounts) 2004 2003 2004 2003
-----------------------------------------------------------------------
Cash flow from operations $ 69,515 $ 36,697 $ 128,592 $ 94,877
Per share - basic $ 1.19 $ 0.61 $ 2.18 $ 1.58
- diluted $ 1.17 $ 0.61 $ 2.15 $ 1.57
-----------------------------------------------------------------------
Net earnings (loss) $ 9,936 $ (1,888) $ 13,115 $ (1,574)
Per share - basic $ 0.17 $ (0.03) $ 0.22 $ (0.03)
- diluted $ 0.17 $ (0.03) $ 0.22 $ (0.03)
-----------------------------------------------------------------------
/T/
Cash flow from operations totaled $128.6 million for the six
months ending June 30, 2004, representing a 36 percent increase
from the $94.9 million for the comparable period in 2003. The
increase is due to a $31.6 million reduction of financial
instrument losses, and a net $5.1 million recovery of bad debts,
partially offset by lower revenue as a result of the Trust
disposition.
For the three months ended June 30, 2004, cash flow from
operations totaled $69.5 million as compared to $36.7 million in
the comparable period in 2003. The 89 percent increase in cash
flow resulted from higher revenues due to increased production
and higher commodity prices, the bad debt recovery and the
reduction in financial instrument losses.
Net earnings for the six months ended June 30, 2004 totaled $13.1
million compared to a net loss of $1.6 million for the comparable
period in 2003. The increase in earnings is a result of decreased
financial instrument losses.
/T/
QUARTERLY INFORMATION
-----------------------------------------------------------------------
Three months ended
-----------------------------------------------------------------------
(thousands of dollars, Jun 30, Mar 31, Dec 31, Sep 30,
except per share amounts) 2004 2004 2003 2003
-----------------------------------------------------------------------
Net revenues $ 95,767 $ 79,179 $ 77,697 $ 66,004
Net earnings (loss) $ 9,936 $ 3,179 $ 11,296 $ (7,851)
Net earnings (loss) per share
- basic $ 0.17 $ 0.05 $ 0.18 $ (0.13)
- diluted $ 0.17 $ 0.05 $ 0.18 $ (0.13)
-----------------------------------------------------------------------
Three months ended
-----------------------------------------------------------------------
(thousands of dollars, Jun 30, Mar 31, Dec 31, Sep 30,
except per share amounts) 2003 2003 2002 2002
-----------------------------------------------------------------------
Net revenues $ 65,101 $ 91,446 $ 110,180 $ 95,780
Net earnings (loss) $ (1,888) $ 314 $ (41,399) $ 6,180
Net earnings (loss) per share
- basic $ (0.03) $ 0.01 $ (0.70) $ 0.10
- diluted $ (0.03) $ 0.01 $ (0.70) $ 0.10
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
Quarterly net revenues have continued to increase since June 2003
as the Company has steadily increased production and commodity
prices continue to remain high. As a result of the disposition of
the Trust assets in the first quarter of 2003, quarterly net
revenue in prior periods were higher due to higher production,
partially offset by generally lower commodity prices.
The net loss of $41.4 million in the fourth quarter of 2002 was
primarily due to dry hole costs and impairment charges on
non-core properties recorded in the quarter.
/T/
CAPITAL EXPENDITURES
-----------------------------------------------------------------------
Three months ended June 30
-----------------------------------------------------------------------
2004 2003
-----------------------------------------------------------------------
Wells Drilled Gross(1) Net(2) Gross(1) Net(2)
-----------------------------------------------------------------------
Natural Gas 24 17 29 27
Oil - - 5 4
Oilsands evaluation - - - -
Dry - - 3 2
-----------------------------------------------------------------------
Total 24 17 37 33
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Six months ended June 30
-----------------------------------------------------------------------
2004 2003
-----------------------------------------------------------------------
Wells Drilled Gross(1) Net(2) Gross(1) Net(2)
-----------------------------------------------------------------------
Natural Gas 102 72 96 75
Oil 5 5 10 9
Oilsands evaluation 17 17 - -
Dry 6 3 8 6
-----------------------------------------------------------------------
Total 130 97 114 90
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1) "Gross" wells means the number of wells in which Paramount has a
working interest or a royalty interest that may be convertible
to a working interest.
(2) "Net" wells means the aggregate number of wells obtained by
multiplying each gross well by Paramount's percentage working
interest therein.
/T/
During the six months ended June 30, 2004, Paramount participated
in the drilling of 130 gross wells (97 net) including 24 gross
wells (17 net) in the second quarter, compared to 114 gross wells
(90 net) for the comparable period in 2003.
/T/
-----------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
-----------------------------------------------------------------------
Capital Expenditures
(thousands of dollars) 2004 2003 2004 2003
-----------------------------------------------------------------------
Land $ 9,803 $ 5,235 $ 17,803 $ 7,441
Geological and geophysical 1,841 3,423 5,833 4,171
Drilling 18,704 16,128 87,626 55,435
Production equipment
and facilities 15,568 25,800 45,069 36,021
-----------------------------------------------------------------------
Exploration and
development expenditures $ 45,916 $ 50,586 $ 156,331 $ 103,068
Proceeds received on
property dispositions (2,448) (38,649) (5,613) (261,481)
Property acquisitions 185,117 - 185,117 -
Other 513 215 739 490
-----------------------------------------------------------------------
Net capital expenditures $ 229,098 $ 12,152 $ 336,574 $(157,923)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
For the six months ended June 30, 2004, exploration and
development expenditures totaled $156.3 million, as compared to
$103.1 million for the comparable period in 2003. Higher capital
expenditures are due to a larger number of net wells drilled,
including a larger number of deep wells in the Grande Prairie
area. Capital additions for the six month period 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.
LIQUIDITY AND CAPITAL RESOURCES
Debt
On June 29, 2004, the Company issued US $125 million of 8 7/8
percent Senior Notes due 2014. Interest on the notes is payable
semi-annually, beginning in 2005. The Company may redeem some or
all of the notes at any time after July 15, 2009 at redemption
prices ranging from 100 percent to 104.438 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 July 15, 2007 at 108.875 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.
As at June 30, 2004, 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 lenders' 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.
On July 20, 2004, the Company's borrowing capacity under this
facility was increased from $203 million to $250 million as a
result of the Company's $189 million asset acquisition of oil and
natural gas assets.
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 $570.6
million at June 30, 2004, compared to $346.4 million at March 31,
2004, primarily as a result of the US $125 million Senior Notes
issued to finance the $189 million asset acquisition. 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. Accordingly,
the Company drew down its credit facility to fund the first
quarter capital expenditure program which was in excess of cash
flow from operations. For the remainder of 2004, Paramount
expects that cash flow from operations will continue to exceed
capital expenditures, excluding any major acquisitions.
The Company's working capital at June 30, 2004, excluding the
current portion of long-term debt, was $9.7 million (March 31,
2004 and December 31, 2003 - $36.5 million and $9.1 million
working capital deficiency, respectively). The change in working
capital reflects the high level of capital expenditures in the
first quarter.
Share Capital
For the three months ended June 30, 2004, 42,500 stock options
were exercised for cash consideration of $0.1 million; this
amount was charged to general and administrative expenses.
Pursuant to its Normal Course Issuer Bid, Paramount repurchased
1,629,500 common shares for cancellation for the six months ended
June 30, 2004 at an average price of $11.91 per common share.
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 to secure access to drilling rigs during peak demand
periods.
Paramount's share of net operating income from the partnership
amounted to $0.1 million for the six months ended June 30, 2004
(2003 - $0.1 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 4 to the unaudited
interim 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 obligations. 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 Obligations
The asset retirement obligations recorded in the consolidated
financial statements are 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 (unaudited)
(thousands of dollars)
June 30 December 31
2004 2003
Restated
(notes 2 & 5)
-----------------------------------------------------------------------
ASSETS (note 6)
Current Assets
Short-term investments (market value:
2004 - $10,078; 2003 - $17,265) $ 10,078 $ 16,551
Accounts receivable 94,856 82,363
Financial instruments (notes 2 and 8) 3,614 -
Prepaid expenses 3,314 2,282
-----------------------------------------------------------------------
111,862 101,196
-----------------------------------------------------------------------
Property, Plant and Equipment
Property, plant and equipment, at cost 1,804,043 1,452,749
Accumulated depletion and depreciation (494,456) (418,676)
Assets of discontinued operations (note 5) 6,208 3,234
-----------------------------------------------------------------------
1,315,795 1,037,307
-----------------------------------------------------------------------
Goodwill 31,621 31,621
Other assets 10,665 7,006
-----------------------------------------------------------------------
$ 1,469,943 $ 1,177,130
-----------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 87,514 $ 110,339
Financial instruments (notes 2 and 8) 14,654 -
Current portion of long-term debt (note 6) 322 312
Liabilities of discontinued operations
(note 5) 1,509 1,138
-----------------------------------------------------------------------
103,999 111,789
-----------------------------------------------------------------------
Long-term debt (note 6) 570,238 293,655
Asset retirement obligations (note 2) 94,400 61,554
Deferred revenue - 3,959
Future income taxes 207,469 206,684
Liabilities of discontinued operations
(note 5) 2,895 3,456
-----------------------------------------------------------------------
875,002 569,308
-----------------------------------------------------------------------
Commitments and Contingencies (note 8)
Shareholders' Equity
Share capital (note 7)
Issued and outstanding
58,465,100 common shares (2003-
60,094,600 common shares) 194,952 200,274
Contributed surplus 1,942 746
Retained earnings 294,048 295,013
-----------------------------------------------------------------------
490,942 496,033
-----------------------------------------------------------------------
$ 1,469,943 $ 1,177,130
-----------------------------------------------------------------------
See accompanying notes to consolidated financial statements
Consolidated Statements of Earnings (Loss) and Retained Earnings
(unaudited)
(thousands of dollars except per share amounts)
Three months ended Six months ended
June 30 June 30
2004 2003 2004 2003
restated restated
(notes (notes
2 and 5) 2 and 5)
-----------------------------------------------------------------------
Revenue
Petroleum and
natural gas sales $ 125,616 $ 101,512 $ 231,120 $ 251,217
(Loss) on financial
instruments (note 8) (6,297) (15,218) (12,759) (44,322)
Royalties (net of
ARTC) (23,235) (19,695) (44,170) (50,912)
Loss on investments (34) (1,020) (34) (1,020)
Other income (283) (478) 199 225
-----------------------------------------------------------------------
95,767 65,101 174,356 155,188
-----------------------------------------------------------------------
Expenses
Operating 19,264 18,302 37,751 37,168
Interest 5,579 4,163 9,821 11,199
General and
administrative 5,574 4,496 11,397 9,179
Bad debt recovery
(note 9) (5,107) - (5,107) -
Lease rentals 872 702 2,106 1,477
Geological and
geophysical 1,841 3,423 5,833 4,171
Dry hole costs 1,171 10,558 4,186 19,449
(Gain) loss on sales
of property, plant
and equipment (30) 21,065 (521) 20,794
Accretion asset
retirement
obligations (note 2) 1,292 965 2,538 2,022
Depletion and
depreciation 42,577 40,609 84,476 84,180
Writedown of
petroleum and
natural gas
properties - 9,868 - 9,868
Unrealized foreign
exchange loss on US
debt 2,680 - 5,270 -
-----------------------------------------------------------------------
75,713 114,151 157,750 199,507
-----------------------------------------------------------------------
Earnings (loss)
before taxes from
continuing operations 20,054 (49,050) 16,606 (44,319)
-----------------------------------------------------------------------
Income and other
taxes
Large Corporations
Tax and other 1,773 741 2,549 1,288
Future income tax
(recovery) expense
(note 10) 8,180 (48,128) 828 (44,426)
-----------------------------------------------------------------------
9,953 (47,387) 3,377 (43,138)
-----------------------------------------------------------------------
Net earnings from
continuing operations 10,101 (1,663) 13,229 (1,181)
Net earnings from
discontinued
operations (note 5) (165) (225) (114) (393)
-----------------------------------------------------------------------
Net earnings (loss) 9,936 (1,888) 13,115 (1,574)
-----------------------------------------------------------------------
Retained earnings,
beginning of period 291,866 299,711 295,013 355,912
Adjustment on
disposition of
assets to a related
party (note 4) - - - (1,388)
Dividends (note 4) - - - (51,000)
Redemption of share
capital (note 7) (7,754) - (14,080) -
Adoption of new
accounting policy
(note 2) - - - (4,127)
-----------------------------------------------------------------------
Retained earnings,
end of period $ 294,048 $ 297,823 $ 294,048 $ 297,823
-----------------------------------------------------------------------
Net earnings (loss)
from continiung
operations per
common share
- basic $ 0.17 $ (0.03) $ 0.22 $ (0.02)
- diluted $ 0.17 $ (0.03) $ 0.22 $ (0.02)
Net earnings (loss)
from discontinued
operations per
common share
- basic $ - $ - $ - $ (0.01)
- diluted $ - $ - $ - $ (0.01)
Net earnings (loss)
per common share
- basic $ 0.17 $ (0.03) $ 0.22 $ (0.03)
- diluted $ 0.17 $ (0.03) $ 0.22 $ (0.03)
Weighted average
common shares
outstanding
(thousands)
- basic 58,626 60,169 59,085 60,084
- diluted 59,558 60,244 59,868 60,343
See accompanying notes to consolidated financial statements
Consolidated Statements of Cash Flows (unaudited)
(thousands of dollars)
Three months ended Six months ended
June 30 June 30
2004 2003 2004 2003
restated restated
(notes (notes
2 and 5) 2 and 5)
-----------------------------------------------------------------------
Operating activities
Net earnings (loss)
from continuing
operations $ 10,101 $ (1,663) $ 13,229 $ (1,181)
Add (deduct)
non-cash items
Depletion and
depreciation 42,577 40,609 84,476 84,180
Writedown of
petroleum and
natural gas
properties - 9,868 - 9,868
(Gain) loss on sales
of property, plant
and equipment (30) 21,065 (521) 20,794
Accretion of asset
retirement
obligations 1,292 965 2,538 2,022
Future income tax
(recovery) expense 8,180 (48,128) 828 (44,426)
Amortization of
other assets 259 - 517 -
Non-cash general and
administrative
expense 609 - 1,196 -
Non-cash loss on
financial
instruments (note 8) 835 - 11,040 -
Unrealized foreign
exchange loss on US
debt 2,680 - 5,270 -
Add items not
related to operating
activities
Dry hole costs 1,171 10,558 4,186 19,449
Geological and
geophysical costs 1,841 3,423 5,833 4,171
-----------------------------------------------------------------------
Cash flow from
operations 69,515 36,697 128,592 94,877
Decrease in deferred
revenue - (2,380) (3,959) (4,840)
Asset retirement
obligations expenditure (173) - (236) -
Decrease in other
assets (45) - (240) -
Change in non-cash
operating working
capital from
continuing operations (9,231) 19,577 (41,430) (8,950)
-----------------------------------------------------------------------
60,066 53,894 82,727 81,087
-----------------------------------------------------------------------
Financing activities
Current and
long-term debt -
draws 65,828 - 135,817 10,000
Current and
long-term debt -
repayments (7,991) (21,238) (32,478) (232,874)
Shareholder loan - - - (33,000)
Proceeds from US
debt, net of
issuance costs 164,047 - 164,047 -
Share capital -
issued - - - 10,317
Share capital -
repurchased (10,503) - (19,401) -
-----------------------------------------------------------------------
211,381 (21,238) 247,985 (245,557)
-----------------------------------------------------------------------
Cash flow (used in)
provided by
operating and
financing
activities 271,447 32,656 330,712 (164,470)
-----------------------------------------------------------------------
Investing activities
Property, plant and
equipment
expenditures (46,484) (50,861) (157,127) (102,548)
Petroleum and
natural gas property
acquisitions (note 3) (185,117) - (185,117) -
Proceeds on sale of
property, plant and
equipment (note 4) 2,448 38,649 5,613 261,481
Change in non-cash
investing working
capital (39,891) (19,908) 9,453 7,093
Discontinued
operations (note 5) (2,403) (536) (3,534) (1,556)
-----------------------------------------------------------------------
Cash flow (provided
by) used in
investing activities (271,447) (32,656) (330,712) 164,470
-----------------------------------------------------------------------
Decrease (increase)
in cash - - - -
Cash, beginning of
period - - - -
-----------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-----------------------------------------------------------------------
Income taxes paid $ 1,353 $ - $ 19,230 $ 5,466
Interest paid $ 10,617 $ 3,572 $ 12,172 $ 10,987
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 obligations 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 obligations 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
obligations 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 and six
months ended June 30, 2003 decreased by $0.5 million and $0.8
million ($nil and $0.01 per share), respectively. The asset
retirement obligations 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 obligations at June 30, 2004 is
$141.0 million (December 31, 2003 - $104.8 million). The
Company's credit adjusted risk free rate is 7.875 percent.
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/US dollar exchange rate and interest rates. Emerging
Issues Committee Abstract 128, "Accounting for Trading,
Speculative or Non-Hedging 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 on or 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 hedging relationship,
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 instruments of $1.5 million (note 8).
3. ACQUISITION OF OIL AND GAS PROPERTIES
On June 30, 2004, the Company completed an agreement to acquire
oil and natural gas assets for $185.1 million, after adjustments.
The assets acquired by the Company are located in the Kaybob area
in central Alberta, and in the Fort Liard area in the Northwest
Territories and in northeast British Columbia. The properties
acquired are adjacent to, or nearby, the Company's existing
properties in Kaybob and Fort Liard. The Company has assigned the
entire amount of the purchase price to property, plant and
equipment and has recognized a $26.8 million liability related to
asset retirement obligations, related to those properties.
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.
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 were
included as a cost of disposition.
During the first six months of 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. DISCONTINUED OPERATIONS
On July 27, 2004, Wilson Drilling Ltd. ("Wilson"), a private
drilling company in which Paramount owns a 50 percent equity
interest, closed the sale of Wilson's drilling assets for $32
million to a publicly traded Income Trust. The proceeds were
$19.2 million cash with the balance in exchangeable shares. The
exchangeable shares are valued at the fair market value of the
purchasers' shares and can be redeemed for trust units in the
Income Trust subject to customary securities laws and
regulations. In connection with the closing of the sale, certain
indebtedness related to these operations will be extinguished.
For reporting purposes, the results of operations, capital
assets, and the current and long-term debt have been presented as
discontinued operations. Prior period financial statements have
been reclassified to reflect this change.
/T/
Selected financial information of the discontinued operations:
-----------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------------------------------------
2004 2003 2004 2003
-----------------------------------------------------------------------
Revenue
Other Income $ 225 $ 26 $ 815 $ 446
Expenses
Interest 121 71 217 97
General and
administrative 110 93 128 178
Depreciation 312 224 553 447
(Gain) loss on sale of
property and equipment (27) - 19 -
-----------------------------------------------------------------------
516 388 917 722
-----------------------------------------------------------------------
Net (loss) before income
tax (291) (362) (102) (276)
Future income tax expense
(recovery) (126) (137) 12 117
-----------------------------------------------------------------------
Net (loss) from
discontinued operations $ (165) $ (225) $ (114) $ (393)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
June 30, 2004 December 31, 2003
-----------------------------------------------------------------------
Property, plant and
equipment, net $ 6,208 $ 3,234
Current liabilities
Current portion of long-term debt $ 1,509 $ 1,138
Long-term debt $ 2,895 $ 3,456
-----------------------------------------------------------------------
-----------------------------------------------------------------------
6. LONG-TERM DEBT
Current portion of long-term debt as at:
-----------------------------------------------------------------------
June 30, 2004 December 31, 2003
-----------------------------------------------------------------------
Mortgage -interest rate
of 6.15 percent $ 322 $ 312
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Long-term debt as at:
-----------------------------------------------------------------------
June 30, 2004 December 31, 2003
-----------------------------------------------------------------------
US $175 million Senior Notes
- interest rate of 7.875 percent $ 233,415 $ 226,887
US $125 million Senior Notes
- interest rate of 8.875 percent 166,725 -
Credit facility - current interest
rate of 3.3 percent
(2003 - 4.5 percent) 163,843 60,350
Mortgage - interest rate
of 6.15 percent 6,255 6,418
-----------------------------------------------------------------------
$ 570,238 $ 293,655
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
On June 29, 2004, the Company issued US $125 million 8 7/8
percent Senior Notes due 2014. Interest on the note is payable
semi-annually, beginning in 2005. The Company may redeem some or
all of the notes at any time after July 15, 2009, at redemption
prices ranging from 100 percent to 104.438 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 July 15, 2007, at 108.875 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 the Company's existing and
future senior unsecured indebtedness. The financing charges
related to the issuance of the senior notes are capitalized to
other assets and amortized evenly over the term of the notes.
As at June 30, 2004, 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.
On July 20, 2004, the Company's borrowing capacity under this
facility was increased from $203 million to $250 million as a
result of the Company's $189 million asset acquisition of oil and
natural gas assets (note 3).
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.
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.
7. 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
-----------------------------------------------------------------------
Shares repurchased at carrying value (825,800) (2,750)
-----------------------------------------------------------------------
Balance June 30, 2004 58,465,100 $ 194,952
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
The Company instituted a Normal Course Issuer Bid to acquire a
maximum of five percent of its issued and outstanding shares
which commenced May 15, 2003 and expired May 14, 2004. During the
six months ended June 30, 2004, 1,629,500 shares were purchased
pursuant to the plan at an average price of $11.91 per share. For
the three and six-month period ended June 30, 2004, $7.8 million
and $14.1 million, respectively, has been charged to retained
earnings related to the share repurchase price in excess of the
carrying value of the shares.
Stock Option Plan
As at June 30, 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 December 31, 2008, at prices ranging from $8.91 to $13.94 per
share.
/T/
-----------------------------------------------------------------------
Stock options Six months ended June 30, 2004
-----------------------------------------------------------------------
Average
grant price Options
-----------------------------------------------------------------------
Balance, beginning of period $ 9.64 3,632,000
Granted 12.23 142,000
Exercised 9.98 (188,750)
Cancelled 9.16 (89,000)
-----------------------------------------------------------------------
Balance, end of period $ 9.74 3,496,250
-----------------------------------------------------------------------
Options exercisable, end of period $ 10.81 943,625
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
During the three months ended June 30, 2004, 42,500 stock options
were exercised for cash consideration of $0.1 million, which has
been charged to general and administrative expense (2003 - $nil).
/T/
The following table summarizes information about stock options
outstanding at June 30, 2004:
--------------------------------------------------------------------
Outstanding Exercisable
Weighted Weighted Weighted
Average Average Average
Exercise Contractual Exercise Exercisable Exercise
Prices Number Life Price Number Price
--------------------------------------------------------------------
$ 8.91-9.80 2,357,250 3 $ 9.02 267,125 $ 9.00
$10.01-13.94 1,139,000 1 $ 11.24 676,500 $ 11.52
--------------------------------------------------------------------
Total 3,496,250 3 $ 9.74 943,625 $ 10.81
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
8. 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 June 30, 2004.
/T/
--------------------------------------------------------------------
June 30, 2004
--------------------------------------------------------------------
Financial instrument asset $ 3,614
Financial instrument liability (14,654)
--------------------------------------------------------------------
Net financial instrument liability $ (11,040)
--------------------------------------------------------------------
--------------------------------------------------------------------
--------------------------------------------------------------------
Three months ended June 30, 2004
--------------------------------------------------------------------
Net deferred
amounts on Mark-to-market
transition gain (loss) Total
--------------------------------------------------------------------
Fair value of contracts,
January 1, 2004 $ - $ - $ -
Change in fair value of
contracts recorded on
transition, still outstanding
at June 30, 2004 - (3,747) (3,747)
Amortization of the fair
value of contracts as at
June 30, 2004 (480) - (480)
Fair value of contracts
entered into during the
period - 3,392 3,392
--------------------------------------------------------------------
Unrealized loss on
financial instruments $ (480) $ (355) $ (835)
--------------------------------------------------------------------
Realized (loss) on
financial instruments for
the period ended June
30, 2004 (5,462)
--------------------------------------------------------------------
Net (loss) on financial
instruments for the
period ended June
30, 2004 $ (6,297)
--------------------------------------------------------------------
--------------------------------------------------------------------
--------------------------------------------------------------------
Six months ended June 30, 2004
--------------------------------------------------------------------
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 June 30, 2004 - (8,474) (8,474)
Amortization of the fair
value of contracts as at
June 30, 2004 (698) - (698)
Fair value of contracts
entered into during the
period - (1,868) (1,868)
--------------------------------------------------------------------
Unrealized loss on
financial instruments $ (2,148) $ (8,892) $(11,040)
--------------------------------------------------------------------
Realized (loss) on
financial instruments for
the period ended June
30, 2004 (1,719)
--------------------------------------------------------------------
Net (loss) on financial
instruments for the
period ended June
30, 2004 $(12,759)
--------------------------------------------------------------------
--------------------------------------------------------------------
/T/
For the three and six months ended June 30, 2004, the Company has
realized losses on financial instruments of $5.5 million and $1.7
million, respectively, compared to $15.2 million and $44.3
million of realized losses on financial instruments for the same
period in 2003.
(a) INTEREST RATE CONTRACTS
On June 6, 2004, the Company entered into a fixed to floating
interest rate swap. The fair value of this contract as at June
30, 2004, was a loss of $1.0 million.
/T/
-----------------------------------------------------------------------
Description
of Swap Maturity Notional Indebture Effective
Transaction Date Amount Interest Swap to Rate
-----------------------------------------------------------------------
Swap of 7.875 November US$175 US$ fixed US$ US$ LIBOR
percent US$ 1, 2010 million floating plus 320
Senior Notes Basis
Points
-----------------------------------------------------------------------
/T/
(b) FOREIGN EXCHANGE CONTRACTS
The Company has entered into the following currency index swap
transactions, fixing the exchange rate on receipts of US $18.0
million for CDN $25.8 million over the next two years at CDN
$1.4337. The US$/CDN$ closing exchange rate was 1.3338 as at June
30, 2004 (December 31, 2003 - 1.2965).
/T/
-----------------------------------------------------------------------
Year of settlement US dollars Weighted average exchange rate
-----------------------------------------------------------------------
2004 $ 6,000 1.4337
2005 12,000 1.4337
-----------------------------------------------------------------------
$ 18,000 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 June 30,
2004, was a loss of $1.7 million. The change in fair value, a
$5.0 million loss, and $0.8 million amortization of the deferred
gain have been recorded in the consolidated statement of
earnings.
(c) COMMODITY PRICE CONTRACTS
At June 30, 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
20,000 GJ/d $7.90 November 2004 - March 2005
20,000 GJ/d $8.03 November 2004 - March 2005
-----------------------------------------------------------------------
WTI
-----------------------------------------------------------------------
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
June 30, 2004, was a loss of $4.1 million. The change in fair
value, a $3.5 million loss, and $1.5 million amortization of the
deferred loss have been recorded in the consolidated statement of
earnings. At June 30, 2004, a $0.9 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.
9. BAD DEBT RECOVERY
During 2003, one of the Company's customers filed for bankruptcy
protection under the Companies Credit Arrangement Act. The
Company was owed approximately $8 million for which a $6 million
bad debt provision was recorded during 2003.
On April 22, 2004, a settlement negotiated with the customer was
approved by the Creditor Committee of the customer, and the Plan
of Arrangement was approved by the Court of Queen's Bench. The
Company received approximately $7 million on settlement and has
been recorded as a bad debt recovery in the period.
10. INCOME TAXES
In 2004, the Government of Alberta reduced its corporate income
tax rate by one percent. As a result, the Company's future income
tax liability has been reduced by $5.2 million and recognized in
the future income tax provision for the six month period ended
June 30, 2004.
11. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform
with the current period's financial statement presentation.
/T/
Paramount Resources Ltd,
Pro-forma Supplemental Oil and Gas Operating Statistics - unaudited
For the Period Ended June 30, 2004
(Note 1)
Sales Volumes 2004 2003
--------------------------------------------------------------------
Q2 Q1 Q4 Q3
--------------------------------------------------------------------
Gas (MMcf/d) 157 141 141 136
Oil and Natural Gas
Liquids (Bbl/d) 6,134 5,675 5,877 7,461
--------------------------------------------------------------------
Total Sales Volumes
(Boe/d) (6:1) 32,354 29,178 29,353 30,098
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Per-unit Results 2004 2003
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Q2 Q1 Q4 Q3
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Produced Gas ($/Mcf)
Price, net of transporation
and selling 7.01 6.54 5.14 5.74
Royalties 1.33 1.33 0.55 1.30
Operating expenses, net of
processing revenue 1.03 1.08 1.26 1.19
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Cash netback before realized
commodity hedge 4.65 4.13 3.33 3.25
Realized commodity hedge (0.31) 0.42 0.25 (0.72)
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Cash netback including
realized commodity hedge 4.34 4.55 3.58 2.53
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Produced Oil & Natural
Gas Liquids ($/Bbl)
Price, net of transporation
and selling 45.37 41.87 36.02 36.48
Royalties 7.58 7.52 6.64 6.75
Operating expenses, net of
processing revenue 8.14 8.87 11.01 10.01
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Cash netback before realized
commodity hedge 29.65 25.48 18.37 19.72
Realized commodity hedge (2.75) (4.93) (3.13) (2.27)
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Cash netback including
realized commodity hedge 26.90 20.55 15.24 17.45
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Total Produced ($/Boe)
Price, net of transporation
and selling 42.67 39.73 31.87 34.95
Royalties 7.89 7.88 3.95 7.56
Operating expenses, net of
processing revenue 6.54 6.96 8.25 7.85
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Cash netback before realized
commodity hedge 28.24 24.89 19.67 19.54
Realized commodity hedge (2.03) 1.07 0.57 (3.76)
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Cash netback including
realized commodity hedge 26.21 25.96 20.24 15.78
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Sales Volumes 2003 2002
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Q2 Q1 Q4 Q3
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Gas (MMcf/d) 142 143 172 162
Oil and Natural Gas
Liquids (Bbl/d) 7,465 7,892 8,552 7,832
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Total Sales Volumes
(Boe/d) (6:1) 31,129 31,711 37,243 34,756
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Per-unit Results 2003 2002
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Q2 Q1 Q4 Q3
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Produced Gas ($/Mcf)
Price, net of transporation
and selling 5.91 6.91 4.15 3.16
Royalties 1.14 1.43 0.92 0.65
Operating expenses, net of
processing revenue 0.95 0.73 0.64 0.70
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Cash netback before realized
commodity hedge 3.82 4.75 2.59 1.81
Realized commodity hedge (1.07) (1.62) 0.29 0.67
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Cash netback including
realized commodity hedge 2.75 3.13 2.88 2.48
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Produced Oil & Natural
Gas Liquids ($/Bbl)
Price, net of transporation
and selling 36.94 42.98 36.03 37.47
Royalties 7.28 9.04 6.83 8.71
Operating expenses, net of
processing revenue 8.90 6.96 5.72 8.40
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Cash netback before realized
commodity hedge 20.76 26.98 23.48 20.36
Realized commodity hedge (1.67) (4.03) (0.76) (0.76)
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Cash netback including
realized commodity hedge 19.09 22.95 22.72 19.60
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Total Produced ($/Boe)
Price, net of transporation
and selling 35.84 41.85 27.44 23.14
Royalties 6.95 8.70 5.80 4.99
Operating expenses, net of
processing revenue 6.46 5.02 4.29 5.15
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Cash netback before realized
commodity hedge 22.43 28.13 17.35 13.00
Realized commodity hedge (5.37) (8.33) 1.15 2.96
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Cash netback including
realized commodity hedge 17.06 19.80 18.50 15.96
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Note 1 - Pro-forma is presented on the basis of 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,
commencing with the fourth quarter of 2003, natural gas production
volumes are measured in marketable quantities, with adjustments for heat
content and transportation reflected in the reported natural gas price.
Paramount Resources Ltd.
Pro-forma Quarterly Condensed Financial Statements - unaudited
For Q3-Q4 2002, 2003 and Q1-Q2 2004
(thousands of dollars except for per share amounts)
(Note 1)
2004 2003
Q2 Q1 Q4 Q3
Net revenue, before hedging $102,064 $ 85,641 $ 76,156 $ 76,427
Financial instruments gain
(loss) (6,297) (6,462) 1,541 (10,423)
--------------------------------------
95,767 79,179 77,697 66,004
Operating expenses 19,264 18,487 22,287 21,738
Interest 5,579 4,338 5,604 3,017
General and administrative 5,574 5,840 5,832 4,709
Lease rentals 872 1,234 1,027 1,070
Geological and geophysical 1,841 3,992 3,208 1,071
Dry hole costs 1,171 3,015 5,750 1,533
Depletion and depreciation 42,577 42,140 47,055 33,175
Other (1,000) 3,391 (5,550) 5,512
--------------------------------------
75,878 82,437 85,213 71,825
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Earnings (loss) before taxes 19,889 (3,258) (7,516) (5,821)
Current and large corporations
tax 1,773 776 1,165 422
Future tax (recovery) 8,180 (7,213) (19,977) 1,608
--------------------------------------
Net earnings (loss) $ 9,936 $ 3,179 $ 11,296 $ (7,851)
--------------------------------------
--------------------------------------
Net earnings (loss) per
common share
- basic $ 0.17 $ 0.05 $ 0.19 $ (0.13)
- diluted $ 0.17 $ 0.05 $ 0.19 $ (0.13)
Cash flow from operations $ 69,515 $ 59,554 $ 43,157 $ 29,071
Cash flow from operations
per common share $ 1.19 $ 1.00 $ 0.72 $ 0.48
- basic $ 1.17 $ 0.99 $ 0.72 $ 0.48
- diluted
WA shares o/s (basic) 58,626 59,560 60,168 60,169
WA shares o/s (diluted) 59,558 60,209 60,340 60,287
2003 2002
Q2 Q1 Q4 Q3
Net revenue, before hedging $ 80,319 $101,989 $ 77,000 $ 58,046
Financial instruments gain
(loss) (15,218) (29,100) 3,925 9,466
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65,101 72,889 80,925 67,512
Operating expenses 18,302 14,338 14,709 16,468
Interest 4,163 5,415 9,367 4,670
General and administrative 4,496 4,513 4,850 3,821
Lease rentals 702 775 899 1,343
Geological and geophysical 3,423 748 1,182 1,238
Dry hole costs 10,558 5,821 115,909 963
Depletion and depreciation 40,609 42,551 49,726 33,975
Other 32,123 528 (8,126) 1,114
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114,376 74,689 188,516 63,592
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Earnings (loss) before taxes (49,275) (1,800) (107,591) 3,920
Current and large corporations
tax 741 547 1,989 (479)
Future tax (recovery) (48,128) 163 (74,272) 333
--------------------------------------
Net earnings (loss) $ (1,888) $ (2,510) $(35,308) $ 4,066
--------------------------------------
--------------------------------------
Net earnings (loss) per
common share
- basic $ (0.03) $ (0.04) $ (0.59) $ 0.07
- diluted $ (0.03) $ (0.04) $ (0.59) $ 0.07
Cash flow from operations $ 36,697 $ 47,301 $ 49,111 $ 41,689
Cash flow from operations
per common share $ 0.61 $ 0.79 $ 0.83 $ 0.70
- basic $ 0.61 $ 0.79 $ 0.82 $ 0.70
- diluted
WA shares o/s (basic) 60,169 59,998 59,458 59,459
WA shares o/s (diluted) 60,244 60,072 59,581 59,616
Note 1 - Pro-forma is presented on the basis of 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.
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
