Paramount Resources Ltd.: Financial and Operating Results for the Third Quarter Ended September 30, 2004
FOR: PARAMOUNT RESOURCES LTD.
TSX SYMBOL: POU
NOVEMBER 4, 2004 - 06:00 ET
Paramount Resources Ltd.: Financial and Operating
Results for the Third Quarter Ended September 30, 2004
CALGARY, ALBERTA - Nov. 4, 2004 /CNW/ - Paramount Resources
Ltd. ("Paramount" or the "Company") is pleased to announce its financial
and operating results for the third quarter ended September 30, 2004.
/T/
Financial Highlights
($ thousands except per share amounts and where stated otherwise)
Three Months Ended Nine Months Ended
September 30 September 30
% %
2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------
FINANCIAL
Petroleum and
natural gas sales 153,652 96,774 59% 384,772 347,991 11%
Cash flow (1)
From operations 75,679 28,568 165% 204,045 123,181 66%
Per share - basic 1.29 0.47 174% 3.47 2.05 69%
- diluted 1.26 0.47 168% 3.40 2.04 67%
Earnings
Net earnings
(loss) 45,812 (8,383) 646% 58,927 (9,957) 692%
Per share - basic 0.78 (0.14) 657% 1.00 (0.17) 688%
- diluted 0.76 (0.14) 643% 0.98 (0.16) 713%
Capital expenditures
Exploration and
development 51,101 36,185 41% 207,433 139,253 49%
Acquisitions,
dispositions and
other 45,006 (10,062) 547% 225,250 (271,053) 183%
Net capital
expenditures 96,107 26,123 268% 432,683 (131,800) 428%
Total assets (3) 1,429,533 1,175,310 22%
Net debt (2) (3) 535,511 295,375 81%
Shareholders'
equity (3) 537,928 496,033 8%
Common shares
outstanding
(thousands)
- September 30 58,522 60,169 -3%
- October 31 63,041
------------------------------------------------------------------------
------------------------------------------------------------------------
OPERATING
Production
Natural gas
(MMcf/d) 196 136 44% 165 157 5%
Crude oil and
liquids (Bbl/d) 8,446 7,461 13% 6,758 7,605 -11%
Total production
(Boe/d) @ 6:1 41,072 30,098 36% 34,226 33,735 1%
------------------------------------------------------------------------
Average prices
Natural gas
(pre-hedge)
($/Mcf) 6.36 5.74 11% 6.62 6.25 6%
Natural gas
($/Mcf) (4) 6.23 5.02 24% 6.58 5.10 29%
Crude oil and
liquids
(pre-hedge)
($/Bbl) 50.26 36.48 38% 46.45 38.85 20%
Crude oil and
liquids
($/Bbl) (4) 50.08 34.21 46% 44.17 36.18 22%
Drilling activity
(gross)
Gas 38 26 46% 141 122 16%
Oil 2 2 - 7 12 -42%
Oilsands
evaluation (5) - - - 17 - -
D&A 1 2 -50% 6 10 -40%
Total wells 41 30 37% 171 144 19%
Success rate (5) 98% 93% 5% 96% 93% 3%
------------------------------------------------------------------------
------------------------------------------------------------------------
(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 third quarter daily production for Paramount Resources Ltd.
("Paramount" or the "Company") averaged 196 MMcf/d of natural gas and
8,446 Bbl/d of oil and natural gas liquids. Average daily production for
the quarter was 41,072 Boe/d, a 27 percent increase over the prior
quarter and a 36 percent increase over the same period in 2003. The
increase in production was primarily due to the Company's major asset
acquisitions. Drilling activity consisted of 41 (32.9 net) wells
drilled, resulting in 38 (30.5 net) gas wells and 2 (2.0 net) oil wells
(2.0 net) and 1 (0.4 net) dry hole for a 99 percent success rate. Field
activity in general was curtailed as a result of wet weather which left
surface access conditions difficult for the majority of locations.
Kaybob
Natural gas production volumes increased 17 percent to 105 MMcf/d in the
third quarter compared to 90 MMcf/d in the second quarter. Oil and
natural gas liquids production increased 113 percent to 5,421 Bbl/d in
the third quarter compared to 2,543 Bbl/d in the second quarter. Total
production was 22,950 Boe/d as compared to 17,550 Boe/d in the previous
quarter, a 31 percent increase. The increase in gas and liquids
production is primarily attributed to the Kaybob assets acquired at the
end of June. Excluding the impact of the acquisition, production volumes
were essentially unchanged from second quarter production despite
reduced activity resulting from wet weather conditions and problems at
third party facilities.
Third quarter capital expenditures, excluding acquisitions and land,
totaled $18 million, bringing year-to-date capital spending to $55
million. Capital spending during the quarter continued to be focused on
drilling and completions work including workover and production
optimization projects.
Paramount participated in the drilling of 16 (11.6 net) wells in the
third quarter, resulting in 12 (9.4 net) gas wells, 2 (2.0 net) oil
wells, and 2 (0.2 net) standing wells. Wet summer conditions have
restricted construction and tie-in operations. The successful gas and
oil wells are expected to be onstream by year end.
Paramount had two drilling rigs operating in the Kaybob area during the
third quarter, and plans to have five drilling rigs active in the area
by year end. In addition, there are currently four service rigs
operating in the area, working on new completions, workover and
optimization projects. As a result of the major acquisition earlier in
the year, the Company has expanded its position in the Kakwa area and
plans to use two of the five drilling rigs to exploit identified
opportunities.
Paramount has been incorporating the newly acquired assets into
integrated field operations, and the staff associated with the asset
acquisitions have been instrumental in providing continuity during the
transition period. The Company has also identified optimization
opportunities that have started adding production and reserves during
the quarter.
The fourth quarter will be busy with drilling and service rig activities
peaking during the winter months. The construction group will also be
extremely active this winter to get caught up for work that was delayed
due to the wet summer.
Grande Prairie
Third quarter production volumes averaged 32 MMcf/d and 525 Bbl/d for a
total of 5,829 Boe/d, a 42 percent increase over second quarter
production of 4,093 Boe/d. The increase in production volumes is due to
the Marten Creek asset acquisition. Pre-acquisition volumes decreased
four percent to 3,915 Boe/d for the third quarter due to a one week
facility turnaround at Mirage, downtime in Saddle Hills caused by
facility modifications and weather related delays in bringing on new
wells. Four wells were turned on in the third quarter resulting in an
additional 1.5 MMcf/d of initial production rate.
Facility and infrastructure issues identified earlier in the year are
expected to be resolved during the fourth quarter. The third-party
facility limitations at Marten Creek will be mitigated by an expansion
scheduled to be completed by the end of October and production should
increase by about 3 MMcf/d. At Mirage, work continues on the third-party
pipeline that will be looped to remove the current bottleneck which will
allow further increases in production.
Drilling, completion and construction operations were hampered by wet
weather conditions leaving approximately 5 MMcf/d of gas to be tied-in
during the fourth quarter. The major accomplishment for the third
quarter was the drilling of 14 (13.4 net) wells, completing 16 (15.8
net) wells and the tie-in of 4 (3.5 net) wells.
Northwest Alberta / Cameron Hills, Northwest Territories
Northwest Alberta's third quarter production remained steady averaging
854 Bbl/d of liquids and 22 MMcf/d of natural gas, for a total of 4,530
Boe/d. Liquids production fell short of the 1,293 Bbl/d target, the
result of not realizing production from the Cameron Hills wells drilled
in the first quarter. Gas production exceeded the target of 19.4 MMcf/d,
predominately the result of better than expected performance from
existing wells.
Third quarter activities were focused on the technical development of
workover and drilling opportunities that will be undertaken in the first
quarter of 2005. Surveying activities of new drill sites are ongoing and
surface access applications have also been prepared. A total of 22 high
working interest drilling locations are planned for 2005, of which 19
will be operated and 3 will be non-operated.
The expanded Haro facility that came on line during the first week of
June has facilitated a net production increase from 1.8 MMcf/d to an
average of 4.9 MMcf/d for the third quarter. Efforts to match production
throughput to the facility ownership capacity of 5.6 MMcf/d have been
delayed as the result of lower facility operating suction pressure.
Liard, Northwest Territories / Northeast British Columbia
Production for the third quarter averaged 23 MMcf/d, a 13 MMcf/d
increase from second quarter production of 10 MMcf/d. The Liard assets
acquired at the end of the second quarter contributed to the production
increase. Subsequent to quarter end, Paramount has purchased additional
working interests in 3 of the 4 producing properties in the Liard Basin
which will add 14 MMcf/d of production.
During the third quarter, the 2M-25 well in Fort Liard was completed and
flow-tested raw natural gas at rates in excess of 25 MMcf/d. Workover
operations are currently underway on M-25 which is capable of producing
up to 10 MMcf/d of raw gas but was shut-in due to accessibility. Both
wells are anticipated to be on production by the end of October.
Workovers on the 2K-29 and K-29 wells are scheduled for completion
during the fourth quarter.
At Colville Lake, Paramount (50% working interest) has drilled 3 wells
on the Nogha prospect with very positive results; Nogha C-49, Nogha M-17
and Nogha B-23. The first 2 wells, C-49 and M-17, were cased, completed
and flow tested as successful Mt. Clark sweet gas wells and are
currently shut-in. Post stimulation flow rates in the wells ranged from
3 to 5 MMcf/d. The B-23 well was cased and completed but due to spring
break up was not flow tested. McDaniel and Associates have independently
reviewed the exploration results to date and have assigned Possible Raw
Gas Reserves in the range of 250 Bcf based on a 6,800 - hectare area
covered by the Nogha C-49 and M-17 wells.
Paramount has drilled further exploratory wells targeting the basal
Cambrian at Lac Maunoir C-34 which was successfully drilled and tested
last year; and a separate structure was tested at West Nogha K-14 which
was successfully drilled and cased. Due to spring break up, the K-14
well will not be evaluated until the upcoming winter season. The results
of these wells were very positive but details have not be released at
this time for reasons of confidentiality.
The Company continues to mobilize materials and equipment in advance of
the planned winter operations at Colville Lake. Paramount plans to drill
between three and five wells this winter to follow up on last winter's
successes as well as evaluate new exploratory prospects. Based on the
positive results so far, several scenarios to bring this gas to market
are being investigated.
Southern
Third quarter production averaged 11 MMcf/d of natural gas and 1,611
Bbl/d of liquids for a total of 3,476 Boe/d. This 10 percent decrease
over second quarter production of 3,845 Boe/d is the result of the
divestment of 540 Bbls/d of non-core oil assets in southeast
Saskatchewan.
Capital expenditures during the quarter resulted in 10 (7.5 net) wells
drilled, for which 3 (2.4 net) wells are in the Chain area. The Company
also participated in three completion wells, all successful, two of
which were in the Chain/Craigmyle area.
In the Chain/Craigmyle area, Paramount presently has 5 (2.5 net)
Horseshoe Canyon CBM wells on production at a total gross rate of 0.6
MMcf/d (0.2 MMcf/d net). The Company has commenced a 20 well development
project which will proceed throughout the fourth quarter and into the
first quarter of 2005. These wells are expected to be on production by
the end of the first quarter in 2005.
Financial
Petroleum and natural gas sales before hedging totaled $153.7 million
for the three months ended September 30, 2004, as compared to $96.8
million for the comparable period in 2003. The increase in revenue is a
result of a 36 percent increase in average production to 41,072 Boe/d in
the current quarter as compared to 30,098 Boe/d in the third quarter of
2003, combined with higher commodity prices. Cash flow from operations
for the three months ended September 30, 2004 was $75.7 million or $1.26
per diluted common share as compared to $28.6 million or $0.47 per
diluted common share for the same period in 2003. Net income for the
three months ended September 30, 2004 totaled $45.8 million or $0.76 per
diluted common share as compared to a net loss of $8.4 million or $0.14
loss per diluted common share for the comparable period in 2003. Current
quarter earnings were impacted by higher production levels combined with
higher commodity prices, a $21.7 million unrealized foreign exchange
gain on US debt and a $15.0 million gain on the disposition of non-core
assets in southeast Saskatchewan. Net debt decreased by $25.4 million
from June 30, 2004 to $535.5 million primarily due to a $21.7 million
unrealized foreign exchange gain on US debt. Capital expenditures,
including acquisitions net of proceeds from dispositions, during the
third quarter were $96.1 million, bringing the year to date total
capital expenditures to $432.7 million.
Equity Issue
On October 26, 2004, Paramount completed its public offering of
2,500,000 common shares at a price of $23.00 per share for gross
proceeds of $57.5 million. Paramount also issued 2,000,000 common shares
on a "flow-through" basis at $29.50 per share for gross proceeds of
$59.0 million by way of private placement. 1,020,000 of the flow-through
shares were subscribed by directors, management and employees of
Paramount. The $113.0 million net proceeds from the issuances will be
used to repay existing indebtedness and for general corporate purposes
including ongoing exploration activities.
Strategic Alternatives Process
The Board of Directors of Paramount Resources Ltd. has authorized
management of Paramount to undertake an examination of possible
corporate restructuring alternatives available to Paramount to increase
shareholder value. No decision on any particular alternative has been
reached at this time and there can be no assurance that the Board of
Directors will determine to undertake any transaction identified and
presented to it by management.
Management of Paramount has been asked to consider strategic options
available to Paramount, including but not limited to: maintaining the
status quo and continuing Paramount's strategic direction as an
independent oil and natural gas exploration and development company, and
reorganizing Paramount, either in whole or in part, into an energy
trust. Any restructuring initiatives identified by management will be
subject to review by, and approval of, the Board of Directors and will
also be subject to the receipt of all required shareholder and
regulatory approvals. In addition, depending on the alternative chosen,
Paramount may be required to seek the consents of the holders of its
outstanding 7 7/8 percent Senior Notes and 8 7/8 percent Senior Notes or
otherwise deal with the outstanding Senior Notes in a manner acceptable
to each of Paramount and the holders of such Senior Notes.
Outlook
Paramount continues to forecast production to average 180 MMcf/d of
natural gas and 7,500 Bbl/d of oil and NGL's, or a total of 37,500
Boe/d, for 2004. Current production including the acquisition is
approximately 210 MMcf/d of natural gas and over 8,500 Bbl/d of liquids,
or 43,500 Boe/d. Paramount forecasts cash flow in 2004 to be
approximately $300 million or $5.00/share, after adjusting for the
equity issuances. Capital expenditures for the year are estimated to be
$550 million, including acquisitions net of proceeds from dispositions.
Net debt levels at year end, giving effect to the acquisitions,
dispositions and the recent equity offerings, are projected to be
approximately $440 million.
A conference call will be held with the senior management of Paramount
Resources Ltd. to answer questions with respect to the Q3 2004 results
Thursday November 4, 2004 at 9:00 am MST (11:00 am EST). To participate
please call 1-888-789-0150 or 1-416-695-9753 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 within an hour of the
call for seven days: until November 11, 2004. The number for the replay
is 1-866-518-1010 or 1-416-695-5275. The conference call will be
available for replay on the Company website, www.paramountres.com within
two hours of the webcast.
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 nine months ended
September 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 nine months
ended September 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 November 3, 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
EQUITY ISSUANCE
On October 15, 2004, Paramount completed the private placement of
2,000,000 common shares issued on a "flow-through" basis at $29.50 per
share. The gross proceeds of the issue are $59 million. On October 25,
2004, Paramount completed the issuance of 2,500,000 common shares at a
price of $23.00 per share. The gross proceeds of the issue are $57.5
million.
The proceeds from the equity issuances were used to repay existing
indebtedness and for general corporate purposes including ongoing
exploration activities.
$84 MILLION ASSET ACQUISITION
On August 16, 2004, Paramount completed the acquisition of assets in the
Marten Creek area in Grande Prairie for $83.7 million, subject to
adjustments. The assets acquired were 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; proved plus probable reserves of approximately 22.2 Bcf
or 3.7 million Boe. In accounting for this acquisition, the Company
recorded a future tax asset in the amount of $96.5 million and a
deferred credit of $7.7 million.
$185 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
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; 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.
On August 12, 2004, Paramount disposed of the Notikewan assets acquired
in the $185 million asset acquisition for approximately $20 million. No
gain or loss was recorded on the transaction.
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 partially finance the $185 million asset acquisition. 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 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 its drilling assets for $32 million to a publicly traded Income
Trust. The gross 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 has been extinguished.
On September 10, 2004, Paramount completed the disposition of its 99
percent interest in a drilling partnership for approximately $1 million.
For reporting purposes, the drilling partnership has been accounted for
as discontinued operations.
Paramount intends to sell a building acquired as a result of the 2002
Summit acquisition, in the fourth quarter of 2004. For reporting
purposes, $7.9 million of property, plant and equipment, $6.5 million of
current and long-term debt, and $0.2 million of earnings have been
classified as discontinued operations as at, and for the nine months
ended, September 30, 2004.
/T/
Revenue and Production
Three Months Nine Months
Ended Ended
Revenue September 30 September 30
(thousands of dollars) 2004 2003 2004 2003
-----------------------------------------------------------------------
Natural gas $ 114,598 $ 71,734 $ 298,765 $ 267,330
Oil and natural
gas liquids 39,054 25,040 86,007 80,661
-----------------------------------------------------------------------
Petroleum and natural
gas revenue 153,652 96,774 384,772 347,991
Gain (Loss) on financial
instruments 4,033 (10,423) (8,726) (54,745)
(Loss) on investments - - (34) (1,020)
-----------------------------------------------------------------------
Gross revenue $ 157,685 $ 86,351 $ 376,012 $ 292,226
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
Natural gas revenue for the nine months ended September 30, 2004
increased 12 percent to $298.8 million as compared to $267.3 million for
the comparable period in 2003. The increase in natural gas revenue
resulted from higher natural gas prices received during the period,
combined with higher production levels. Paramount's average year-to-date
natural gas sales price before hedging increased six percent to
$6.62/Mcf as compared to $6.25/Mcf for the comparable period in 2003.
Natural gas production volumes for the nine-month period ended September
30, 2004 increased five percent to 165 MMcf/d as compared to 157 MMcf/d
for the same period in the prior year. The increase in natural gas
production volumes is primarily the result of the Company's capital
expenditure programs. Production from the 2004 acquisitions offset the
decreases in production from the disposition of natural gas assets in
Northeast Alberta (the "Trust assets") to Paramount Energy Trust (the
"Trust") in the first quarter of 2003.
Natural gas revenue for the three months ended September 30, 2004
increased 60 percent to $114.6 million as compared to $71.7 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. Gas production for the three months ended September
30, 2004 increased 44 percent to average 196 MMcf/d as compared to 136
MMcf/d in the third quarter of 2003. The 2004 asset acquisition
contributed 45 MMcf/d of the increase in gas production while the other
15 MMcf/d production growth was the result of the Company's capital
expenditure programs.
Oil and NGL revenue during the nine months ended September 30, 2004,
increased seven percent to $86.0 million as compared to $80.7 million
for the comparable period in 2003, primarily due to higher commodity
prices received during the period partially offset by lower production
volumes. Paramount's average year to date oil and NGL sales price before
hedging was $46.45/Bbl for the period as compared to $38.85/Bbl in the
comparable period in 2003. Oil and NGL sales volumes decreased 11
percent to average 6,758 Bbl/d for the nine months ended September 30,
2004 as compared to 7,605 Bbl/d for the same period in 2003, primarily
as a result of the sale of Sturgeon Lake in 2003 and the sale of
properties in southeast Saskatchewan, partially offset by production
from asset acquisitions.
Oil and NGL revenue for the three months ended September 30, 2004
increased 56 percent to $39.1 million as compared to $25.0 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
combined with higher production volumes. During the current quarter,
production increased 13 percent to 8,446 Bbl/d compared to 7,461 Bbl/d
in the comparable period in 2003. The increase is primarily a result of
the asset acquisition and partially offset by the disposition of
Sturgeon Lake in 2003 and the disposition of the southeast Saskatchewan
properties in 2004.
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 September 30, 2004, Paramount had the following forward financial
contracts in place:
Amount Price Term
------------------------------------------------------------------------
Sales Contracts
AECO Fixed Price 10,000 GJ/d $5.51 April 2004 -
October 2004
AECO Fixed Price 10,000 GJ/d $5.55 April 2004 -
October 2004
AECO Fixed Price 20,000 GJ/d $5.80 April 2004 -
October 2004
AECO Fixed Price 10,000 GJ/d $5.81 April 2004 -
October 2004
AECO Fixed Price 10,000 GJ/d $5.86 April 2004 -
October 2004
AECO Collars 10,000 GJ/d $5.25 - April 2004 -
$6.75 collar October 2004
AECO Collars 10,000 GJ/d $5.25 - April 2004 -
$6.80 collar October 2004
AECO Fixed Price 20,000 GJ/d $6.82 September 2004 -
October 2004
NYMEX Fixed Price 10,000 MMbtu/d US $6.41 November 2004 -
March 2005
NYMEX Fixed Price 10,000 MMbtu/d US $7.46 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $7.60 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $7.90 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $8.03 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $6.28 April 2005 -
June 2005
AECO Fixed Price 20,000 GJ/d $6.30 April 2005 -
June 2005
AECO Fixed Price 20,000 GJ/d $6.80 April 2005 -
June 2005
WTI Collars 1,000 Bbl/d US $25.00- January 2004 -
30.25 collar December 2004
Purchase Contracts
AECO Fixed Price 20,000 GJ/d $6.76 November 2004 -
March 2005
/T/
The Company also has in place foreign exchange forward contracts, which
have fixed the exchange rate on US $15.0 million for CDN $21.5 million
over the next two years at CDN $1.4337.
The Company entered into a fixed to floating interest rate swap. The
Company swapped US$ 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 sheets 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
nine months ended September 30, 2004 totaled $1.7 million for the
deferred financial instrument loss and $1.2 million for the deferred
financial instrument gain, for a net decrease in earnings before tax of
$0.5 million.
In addition, the Company recorded a financial instrument liability at
September 30, 2004 with a fair value of $2.7 million. This amount
reflects the unrealized changes in fair value of Paramount's financial
instruments.
The total loss on financial instruments for the period of $8.7 million
is comprised of the aforementioned mark-to-market before tax loss on
forward contracts of $2.7 million, net amortization expense of $0.5
million and cash losses on financial instruments of $5.5 million related
to monthly settlements with counterparties. The $5.5 million realized
cash losses on financial instruments for the nine months ended September
30, 2004 is a 90 percent decrease from the $54.7 million of realized
cash losses on financial instruments for the 2003 comparative period.
/T/
Three Months Nine Months
Ended Ended
Cash Netbacks Per Unit September 30 September 30
of Production ($/Boe) 2004 2003 2004 2003
-----------------------------------------------------------------------
Gross revenue before
financial instruments $ 40.66 $ 34.95 $ 41.03 $ 37.67
Royalties 8.07 7.56 7.96 7.80
Operating costs 7.18 7.85 6.92 6.40
-----------------------------------------------------------------------
Operating netback 25.41 19.54 26.15 23.47
-----------------------------------------------------------------------
Loss on financial
instruments (1) 1.01 3.76 0.59 5.94
General and administration (2) 1.71 1.72 1.81 1.54
Interest (3) 2.08 1.04 1.81 1.51
Lease rentals 0.30 0.39 0.35 0.28
Bad debt (recovery) - 2.16 (0.54) 0.65
Current and Large
Corporations tax 0.29 0.15 0.37 0.18
-----------------------------------------------------------------------
Cash flow netback $ 20.02 $ 10.32 $ 21.76 $ 13.37
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(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 $74.7 million for the nine months ended
September 30, 2004, as compared to $71.8 million for the comparable
period in 2003. The increase is due to higher petroleum and natural gas
revenues partially offset by higher gas cost allowance credits from
prior years capital expenditures adjustments. As a percentage of
petroleum and natural gas sales, royalties averaged 19 percent in the
current period as compared to 21 percent for 2003.
For the three months ended September 30, 2004, royalties totaled $30.5
million as compared to $20.9 million during the same period a year
earlier. The increase is primarily the result of increased petroleum and
natural gas revenues during the period. As a percentage of petroleum and
natural gas sales, royalties averaged 20 percent compared to 22 percent
for the comparable three month period in 2003.
Operating Costs
For the nine months ended September 30, 2004, operating costs totaled
$64.9 million compared to $58.9 million during the same period a year
earlier. On a unit-of-production basis, average operating costs
increased eight percent to $6.92/Boe from $6.40/Boe, reflecting a
general increase in the cost of field services and supplies and the
higher operating costs related to the asset acquisitions. For the three
months ended September 30, 2004, average per-unit operating costs
decreased nine percent to average $7.18/Boe as compared to $7.85/Boe for
the comparable period in 2003. The decrease is primarily due to the
disposition of the high operating costs of the Sturgeon Lake property in
2003.
/T/
General and Administrative Expenses
Three Months Nine Months
General and Ended Ended
Administrative Expenses September 30 September 30
(thousands of dollars) 2004 2003 2004 2003
-----------------------------------------------------------------------
General and administrative
expenses $ 5,864 $ 4,764 $ 16,021 $ 14,170
Stock-based compensation
expensed 1,227 - 2,817 -
-----------------------------------------------------------------------
Total general and
administrative expenses $ 7,091 $ 4,764 $ 18,838 $ 14,170
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
General and administrative expenses totaled $18.8 million for the nine
months ended September 30, 2004, as compared to $14.2 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 $1.71/Boe as compared to $1.54/Boe
for the nine-month period ended September 30, 2003. Paramount has
increased its head-office staffing levels due to the major acquisitions
during the year, as well as to enable the Company to identify and
develop new core areas and build its production portfolio, and 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 nine months ended September 30, 2004, increased
29 percent to $17.9 million from $13.9 million for the same period in
2003. The increase is attributed to higher debt levels resulting from
the major acquisitions in 2004. Interest expense for the three months
ended September 30, 2004 was $8.2 million, a 186 percent increase from
$2.9 million for the same period in 2003.
Depletion and Depreciation
Depletion and depreciation ("D&D") expense increased to $136.8 million
from $117.6 million for the nine months ended September 30, 2004,
primarily due to a larger asset base with the major acquisitions,
combined with a higher depletion and depreciation rate. On a
unit-of-production basis, depletion and depreciation costs increased to
$14.58/Boe as compared to $12.77/Boe for the first nine 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
and nine month periods ended September 30, 2004 totaled $3.1 million and
$7.8 million, respectively, (2003 - $2.4 million and $5.8 million,
respectively).
Capital costs associated with undeveloped land and exploratory,
non-producing petroleum and natural gas properties of $264 million are
excluded from costs subject to depletion at September 30, 2004
(September 30, 2003 - $274 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.
Cash Flow and Earnings
Cash flow from operations totaled $204.0 million for the nine months
ended September 30, 2004, representing a 66 percent increase from the
$123.2 million for the comparable period in 2003. The increase is due to
a $49.2 million reduction of realized financial instrument losses, and a
$36.8 million increase in petroleum and natural gas sales as a result of
higher commodity prices and increased production volumes.
For the three months ended September 30, 2004, cash flow from operations
totaled $75.7 million as compared to $28.6 million in the comparable
period in 2003. The 165 percent increase in cash flow is attributed to
increased higher petroleum and natural gas sales given increased
production volumes and higher commodity prices.
Net earnings for the nine months ended September 30, 2004 totaled $58.9
million compared to a net loss of $10.0 million for the comparable
period in 2003. The increase in earnings is a result of decreased
financial instrument losses.
/T/
Quarterly Information
(thousands of Three Months Ended
dollars, except Sep 30, Jun 30, Mar 31, Dec 31,
per share amounts) 2004 2004 2004 2003
-----------------------------------------------------------------------
Net revenues $ 127,192 $ 95,767 $ 79,179 $ 77,697
Net earnings (loss) $ 45,812 $ 9,936 $ 3,179 $ 11,296
Net earnings (loss)
per share - basic $ 0.78 $ 0.17 $ 0.05 $ 0.18
- diluted $ 0.76 $ 0.17 $ 0.05 $ 0.18
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(thousands of Three Months Ended
dollars, except Sep 30, Jun 30, Mar 31, Dec 31,
per share amounts) 2003 2003 2003 2002
-----------------------------------------------------------------------
Net revenues $ 65,415 $ 65,101 $ 91,446 $ 110,180
Net earnings (loss) $ (8,383) $ (1,888) $ 314 $ (41,399)
Net earnings (loss)
per share - basic $ (0.14) $ (0.03) $ 0.01 $ (0.70)
- diluted $ (0.14) $ (0.03) $ 0.01 $ (0.70)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/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 periods prior to
March 31, 2003 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
September 30
2004 2003
-----------------------------------------------------------------------
Wells Drilled Gross (1) Net (2) Gross (1) Net (2)
-----------------------------------------------------------------------
Natural Gas 38 31 26 10
Oil 2 2 2 1
Oilsands evaluation - - - -
Dry 1 - 2 -
-----------------------------------------------------------------------
Total 41 33 30 11
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Nine Months Ended
September 30
2004 2003
-----------------------------------------------------------------------
Wells Drilled Gross (1) Net (2) Gross (1) Net (2)
-----------------------------------------------------------------------
Natural Gas 141 103 122 85
Oil 7 6 12 11
Oilsands evaluation 17 17 - -
Dry 6 4 10 3
-----------------------------------------------------------------------
Total 171 130 144 99
-----------------------------------------------------------------------
(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 nine months ended September 30, 2004, Paramount participated
in the drilling of 171 gross wells (130 net) including 41 gross wells
(33 net) in the third quarter, compared to 144 gross wells (99 net) for
the comparable nine month period in 2003.
/T/
Three Months Nine Months
Ended Ended
Capital Expenditures September 30 September 30
(thousands of dollars) 2004 2003 2004 2003
-----------------------------------------------------------------------
Land $ 9,363 $ 5,082 $ 27,166 $ 12,523
Geological and geophysical 692 1,071 6,525 5,242
Drilling 28,930 19,558 116,556 74,993
Production equipment and
facilities 12,116 10,474 57,186 46,495
-----------------------------------------------------------------------
Exploration and development
expenditures $ 51,101 $ 36,185 $ 207,433 $ 139,253
Proceeds received on
property dispositions (42,087) (10,374) (47,699) (271,855)
Property acquisitions 86,667 - 271,784 -
Other 426 312 1,165 802
-----------------------------------------------------------------------
Net capital expenditures $ 96,107 $ 26,123 $ 432,683 $(131,800)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
For the nine months ended September 30, 2004, exploration and
development expenditures totaled $207.4 million, as compared to $139.3
million for the same period in 2003. The increase is due to a higher
number of net wells were drilled in 2004, including a larger number of
deep wells in the Grande Prairie area. The Company has also increased
land expenditures to $27.2 million from $12.5 million as Paramount
continues to build its strategic land inventory.
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 September 30, 2004, the Company had a $250 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 October 12, 2004, the Company's borrowing capacity under this
facility was increased from $250 million to $270 million as a result of
the Company's $84 million acquisition of oil and natural gas assets.
Long-term debt from continuing operations increased to $542.6 million at
September 30, 2004, compared to $272.0 million at September 30, 2003,
primarily as a result of the asset acquisition.
The Company's working capital at September 30, 2004, excluding the
current portion of long-term debt and liabilities of discontinued
operations, was a $7.1 million surplus compared to a $18.4 million
deficit at September 30, 2003. The change in working capital is a result
of higher cash flows resulting from higher commodity prices and
increased production in 2004.
SHARE CAPITAL
For the three and nine months ended September 30, 2004, 121,750 and
310,500 stock options were exercised for cash consideration of $0.6
million and $1.0 million, respectively; 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 at an average price of $11.91
per common share.
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 (loss) 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 (loss). Acquisition costs for leases that are not individually
significant are charged to earnings (loss) as the related leases expire.
Further impairment expense could result if petroleum and natural gas
prices decline in the future or 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 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)
September 30 December 31
(thousands of dollars) 2004 2003
------------------------------------------------------------------------
(restated -
notes 2
and 5)
ASSETS (note 6)
Current Assets
Short-term investments
(market value: 2004 - $12,700; 2003 -$17,265) $ 11,715 $ 16,551
Accounts receivable 96,387 78,890
Financial instruments (notes 2 and 8) 3,438 -
Prepaid expenses 3,016 2,255
Assets of discontinued operations (note 5) - 1,680
------------------------------------------------------------------------
114,556 99,376
------------------------------------------------------------------------
Property, Plant and Equipment
Property, plant and equipment, at cost
(note 3) 1,800,447 1,444,139
Accumulated depletion and depreciation (536,327) (418,225)
Assets of discontinued operations (note 5) 7,869 11,393
------------------------------------------------------------------------
1,271,989 1,037,307
------------------------------------------------------------------------
Goodwill 31,621 31,621
Other assets 11,367 7,006
------------------------------------------------------------------------
$1,429,533 $1,175,310
------------------------------------------------------------------------
------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 100,853 $ 107,514
Financial instruments (notes 2 and 8) 6,625 -
Liabilities of discontinued operations (note 5) 327 2,455
------------------------------------------------------------------------
107,805 109,969
------------------------------------------------------------------------
Long-term debt (note 6) 542,589 287,237
Asset retirement obligations (note 2) 97,449 61,554
Deferred credit (note 3 and 10) 7,369 -
Deferred revenue - 3,959
Future income taxes 130,222 206,684
Liabilities of discontinued operations (note 5) 6,171 9,874
------------------------------------------------------------------------
783,800 569,308
------------------------------------------------------------------------
Commitments and Contingencies (note 8 and 11)
Shareholders' Equity
Share capital (note 7)
Issued and outstanding 58,521,600 common shares
(2003- 60,094,600 common shares) 195,480 200,274
Contributed surplus 2,588 746
Retained earnings 339,860 295,013
------------------------------------------------------------------------
537,928 496,033
------------------------------------------------------------------------
$1,429,533 $1,175,310
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
Consolidated Statements of Earnings (Loss) and
Retained Earnings (unaudited)
Three Months Ended Nine Months Ended
(thousands of dollars September 30 September 30
except per share amounts) 2004 2003 2004 2003
------------------------------------------------------------------------
(restated (restated
- notes - notes
2 and 5) 2 and 5)
Revenue
Petroleum and natural gas sales $153,652 $ 96,774 $384,772 $347,991
Gain (loss) on financial
instruments (note 8) 4,033 (10,423) (8,726) (54,745)
Royalties (net of ARTC) (30,493) (20,936) (74,663) (71,848)
Loss on investments - - (34) (1,020)
------------------------------------------------------------------------
127,192 65,415 301,349 220,378
------------------------------------------------------------------------
Expenses
Operating 27,120 21,738 64,871 58,906
Interest 8,246 2,879 17,865 13,902
General and administrative 7,091 4,764 18,838 14,170
Bad debt expense (recovery)
(note 9) - 5,977 (5,107) 5,977
Lease rentals 1,141 1,070 3,247 2,547
Geological and geophysical 692 1,071 6,525 5,242
Dry hole costs 4,842 1,533 9,028 20,982
(Gain) loss on sales of property,
plant and equipment (14,980) (1,313) (15,501) 19,481
Accretion asset retirement
obligations (note 2) 1,728 1,011 4,266 3,033
Depletion and depreciation 52,438 33,596 136,757 117,627
Writedown of petroleum and natural
gas properties - - - 9,868
Unrealized foreign exchange (gain)
on US debt (21,660) - (16,390) -
------------------------------------------------------------------------
66,658 72,326 224,399 271,735
------------------------------------------------------------------------
Earnings (loss) before taxes from
continuing operations 60,534 (6,911) 76,950 (51,357)
------------------------------------------------------------------------
Income and other taxes
Large Corporations Tax and other 1,083 419 3,511 1,695
Future income tax (recovery)
expense (note 10) 18,852 1,161 19,671 (43,361)
------------------------------------------------------------------------
19,935 1,580 23,182 (41,666)
------------------------------------------------------------------------
Net earnings (loss) from
continuing operations 40,599 (8,491) 53,768 (9,691)
Net earnings (loss) from
discontinued operations (note 5) 5,213 108 5,159 (266)
------------------------------------------------------------------------
Net earnings (loss) 45,812 (8,383) 58,927 (9,957)
------------------------------------------------------------------------
Retained earnings, beginning of
period 294,048 297,823 295,013 355,912
Adjustment on disposition of
assets to a related party (note 4) - - - (1,388)
Dividends (note 4) - - - (51,000)
Redemption of share capital (note 7) - - (14,080) -
Adoption of new accounting policy
(note 2) - - - (4,127)
------------------------------------------------------------------------
Retained earnings, end of period $339,860 $289,440 $339,860 $289,440
------------------------------------------------------------------------
------------------------------------------------------------------------
Net earnings (loss) from
continuing operations per
common share
- basic $ 0.69 $ (0.14) $ 0.91 $ (0.16)
- diluted $ 0.68 $ (0.14) $ 0.90 $ (0.16)
------------------------------------------------------------------------
Net earnings (loss) from
discontinued operations per
common share
- basic $ 0.09 $ - $ 0.09 $ -
- diluted $ 0.09 $ - $ 0.09 $ -
------------------------------------------------------------------------
Net earnings (loss) per common
share
- basic $ 0.78 $ (0.14) $ 1.00 $ (0.17)
- diluted $ 0.76 $ (0.14) $ 0.98 $ (0.16)
------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands)
- basic 58,496 60,169 58,887 60,112
- diluted 60,003 60,287 59,945 60,520
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
Consolidated Statements of Cash Flows (unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
(thousands of dollars) 2004 2003 2004 2003
------------------------------------------------------------------------
(restated (restated
- notes - notes
2 and 5) 2 and 5)
Operating activities
Net earnings (loss) from
continuing operations $ 40,599 $ (8,491) $ 53,768 $ (9,691)
Add (deduct) non-cash items
Depletion and depreciation 52,438 33,596 136,757 117,627
Writedown of petroleum and
natural gas properties - - - 9,868
(Gain) loss on sales of property,
plant and equipment (14,980) (1,313) (15,501) 19,481
Accretion of asset retirement
obligations 1,728 1,011 4,266 3,033
Future income tax (recovery)
expense 18,852 1,161 19,671 (43,361)
Amortization of other assets 375 - 892 -
Non-cash general and
administrative expense 646 - 1,842 -
Non-cash (gain) loss on financial
instruments (note 8) (7,853) - 3,187 -
Unrealized foreign exchange (gain)
on US debt (21,660) - (16,390) -
Dry hole costs 4,842 1,533 9,028 20,982
Geological and geophysical costs 692 1,071 6,525 5,242
------------------------------------------------------------------------
Cash flow from operations 75,679 28,568 204,045 123,181
Decrease in deferred revenue - (2,223) (3,959) (7,063)
Asset retirement obligations
expenditure (199) - (435) -
Decrease in other assets (1) - (241) -
Change in non-cash operating
working capital from continuing
operations 11,516 (4,247) (29,947) (12,987)
------------------------------------------------------------------------
86,995 22,098 169,463 103,131
------------------------------------------------------------------------
Financing activities
Current and long-term debt
- draws 172,896 - 308,713 10,000
Current and long-term debt
- repayments (172,647) (2,769) (204,971)(235,319)
Shareholder loan - - - (33,000)
Proceeds from US debt, net of
issuance costs (1,076) - 162,971 -
Share capital - issued 528 - 528 10,317
Share capital - repurchased - - (19,401) -
------------------------------------------------------------------------
(299) (2,769) 247,840 (248,002)
------------------------------------------------------------------------
Cash flow (used in) provided by
operating and financing activities 86,696 19,329 417,303 (144,871)
------------------------------------------------------------------------
Investing activities
Property, plant and equipment
expenditures (51,461) (35,477) (208,587)(137,909)
Petroleum and natural gas property
acquisitions (note 3) (86,667) - (271,784) -
Proceeds on sale of property,
plant and equipment (note 4) 42,087 10,374 47,699 271,855
Change in non-cash investing
working capital (1,020) 5,388 8,433 12,481
Discontinued operations (note 5) 10,365 386 6,936 (1,556)
------------------------------------------------------------------------
Cash flow (provided by) used in
investing activities (86,696) (19,329) (417,303) 144,871
------------------------------------------------------------------------
Decrease (increase) in cash - - - -
Cash, beginning of period - - - -
------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
------------------------------------------------------------------------
------------------------------------------------------------------------
Income taxes paid $ 10,135 $ - $ 29,365 $ 5,466
------------------------------------------------------------------------
Interest paid $ 1,421 $ 3,169 $ 13,593 $ 13,798
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
/T/
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
(all tabular amounts expressed in thousands of dollars except as
otherwise noted)
Paramount Resources Ltd. ("Paramount" or the "Company") is involved in
the exploration and development of petroleum and natural gas primarily
in western Canada. The interim consolidated financial statements are
stated in Canadian dollars and have been prepared by management in
accordance with Canadian generally accepted accounting principles
("GAAP"). Certain information and disclosures normally required to be
included in notes to annual consolidated financial statements have been
condensed or omitted. The interim consolidated financial statements
should be read in conjunction with the consolidated financial statements
and the notes thereto in Paramount's Annual Report for the year ended
December 31, 2003.
The preparation of interim consolidated financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the interim consolidated financial
statements and the reported amounts of revenues and expenses during the
period. Actual results could differ from those estimates.
1. Summary of Significant Accounting Policies
The interim consolidated financial statements have been prepared in a
manner consistent with accounting policies utilized in the consolidated
financial statements for the year ended December 31, 2003, except as
noted below:
2. Changes in Accounting Policies
ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2004, the Company retroactively adopted, with
restatement, the Canadian Institute of Chartered Accountants
recommendation on Asset Retirement Obligations, which requires liability
recognition for fair value of retirement obligations associated with
long-lived assets.
Under this new recommendation, the Company recognizes the fair value of
an asset retirement obligation in the period in which it is incurred or
when a reasonable estimate of the fair value can be made. The asset
retirement costs equal to the fair-value of the retirement obligations
are capitalized as part of the cost of the related long-lived asset and
allocated to expense on a basis consistent with depreciation and
depletion. The liability associated with the asset retirement costs is
subsequently adjusted for the passage of time which is recognized as
accretion expense in the consolidated statement of earnings (loss). 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 (loss) in the period
in which the settlement occurs.
As a result of this change, net earnings for the three and nine months
ended September 30, 2003 decreased by $0.5 million and $1.3 million
($0.01 and $0.02 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 September 30, 2004 are
$146.0 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 derivatives 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 values 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 sheets and statement of earnings (loss). 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
$185 MILLION ASSET ACQUISITION
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, 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.
$84 MILLION ASSET ACQUISITION
On August 16, 2004, Paramount completed the acquisition of assets in the
Marten Creek area in Grande Prairie for $83.7 million, subject to
adjustments. The assets acquired were 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; proved plus probable reserves of approximately 22.2 Bcf
or 3.7 million Boe. In accounting for the acquisition, the Company
recorded a future tax asset in the amount of $96.5 million and a
deferred credit of $7.7 million (note 10)
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 nine 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 its drilling assets for $32 million to a publicly traded Income
Trust. The gross 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 has been extinguished. For
reporting purposes, the results of operations, property, plant and
equipment, and the current and long-term debt have been presented as
discontinued operations. Prior period financial statements have been
reclassified to reflect this change.
On September 10, 2004, Paramount completed the disposition of its 99%
interest in a drilling partnership for approximately $1.0 million. For
reporting purposes, the drilling partnership has been been accounted for
as discontinued operations.
Paramount has reclassified a building (910083 Alberta Ltd.) acquired as
a result of the Summit acquisition as an asset held for sale. For
reporting purposes, $7.9 million of property, plant and equipment, $6.5
million of current and long-term debt, and $0.2 million of earnings have
been classified as discontinued operations as at, and for the nine
months ended, September 30, 2004.
/T/
Selected financial information of the discontinued operations for the
nine months ended September 30, 2004
Wilson Shehtah Wilson 910083
Drilling Drilling Alberta
Ltd. Partnership Ltd. Total
2004 2003 2004 2003 2004 2003 2004 2003
-----------------------------------------------------------------------
Revenue
Other Income 897 914 327 346 - - 1,224 1,260
-----------------------------------------------------------------------
Expenses -
Interest 247 131 - - 301 280 548 411
General and
administrative 165 296 384 407 (782) (807) (233) (104)
Depreciation 652 670 6 4 228 224 886 898
(Gain) loss on sale
of property and
equipment (6,737) - (34) - - - (6,771) -
-----------------------------------------------------------------------
(5,673) 1,097 356 411 (253) (303)(5,570) 1,205
-----------------------------------------------------------------------
Net income (loss)
before income tax 6,570 (183) (29) (65) 253 303 6,794 55
Large Corporation
Tax and other 1,537 - - - (5) 15 1,532 15
Future income tax
expense (recovery) 94 234 - - 9 72 103 306
-----------------------------------------------------------------------
Net income (loss)
from discontinued
operations 4,939 (417) (29) (65) 249 216 5,159 (266)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Selected financial information of the discontinued operations for the
three months ended September 30, 2004:
Wilson Shehtah Wilson 910083
Drilling Drilling Alberta
Ltd. Partnership Ltd. Total
2004 2003 2004 2003 2004 2003 2004 2003
-----------------------------------------------------------------------
Revenue
Other Income 83 468 125 121 - - 208 589
-----------------------------------------------------------------------
Expenses
Interest 30 34 - - 99 104 129 138
General and
administrative 37 118 115 89 (163) (262) (11) (55)
Depreciation 99 223 2 2 76 76 177 301
(Gain) loss on sale
of property and
equipment (6,757) - (34) - - - (6,791) -
-----------------------------------------------------------------------
(6,591) 375 83 91 12 (82)(6,496) 384
-----------------------------------------------------------------------
Net income (loss)
before income tax 6,674 93 42 30 (12) 82 6,704 205
Large Corporation
Tax and other 1,537 - - - (127) 3 1,410 3
Future income
tax expense
(recovery) 81 117 - - - (23) 81 94
-----------------------------------------------------------------------
Net income (loss)
from discontinued
operations 5,056 (24) 42 30 115 102 5,213 108
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Wilson Shehtah Wilson 910083
Drilling Drilling Alberta
Ltd. Partnership Ltd. Total
Sep-30 Dec-31 Sep-30 Dec-31 Sep-30 Dec-31 Sep-30 Dec-31
2004 2003 2004 2003 2004 2003 2004 2003
------------------------------------------------------------------------
Current Assets
Accounts Receivable - - - 1,653 - - - 1,653
Prepaid Expenses - - - 27 - - - 27
Property, plant
and equipment, net - 3,234 - 62 7,869 8,097 7,869 11,393
Current Liabilities
Accounts payable
and accrued
liabilities - - - 1,005 - - - 1,005
Current portion of
long-term debt - 1,138 - - 327 312 327 1,450
Long-term debt - 3,456 - - 6,171 6,418 6,171 9,874
------------------------------------------------------------------------
------------------------------------------------------------------------
6. Long-Term Debt
Long-term debt as at:
September 30, 2004 December 31, 2003
-----------------------------------------------------------------------
US $175 million Senior Notes
- interest rate of 7.875 percent $ 220,780 $ 226,887
US $125 million Senior Notes
- interest rate of 8.875 percent 157,700 -
Credit facility - current interest rate
of 3.5 percent (2003 - 4.5 percent) 164,109 60,350
-----------------------------------------------------------------------
$ 542,589 $ 287,237
----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
On June 29, 2004, the Company issued US $125 million 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 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 September 30, 2004, the Company had a $250 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 October 12, 2004, the Company's borrowing capacity under this
facility was increased from $250 million to $270 million as a result of
the Company's $84 million acquisition of oil and natural gas assets
(note 3).
The Company has letters of credit totaling $26.7 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.
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
Stock options exercised 56,500 528
-----------------------------------------------------------------------
Balance September 30, 2004 $ 58,521,600 $ 195,480
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/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. Between January 1, 2004 and May 14,
2004, 1,629,500 shares were purchased pursuant to the plan at an average
price of $11.91 per share. For the three and nine-month periods ended
September 30, 2004, $nil 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.
Subsequent to September 30, 2004, the Company issued 2,500,000 common
shares and 2,000,000 common shares on a "flow- through" basis (note 13).
STOCK OPTION PLAN
As at September 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 $19.51 per share.
/T/
Nine Months Ended September 30, 2004
Average
Stock Options Grant Price Options
-----------------------------------------------------------------------
Balance, beginning of period $ 9.64 3,632,000
Granted 14.86 274,000
Exercised 10.01 (310,500)
Cancelled 9.12 (115,000)
-----------------------------------------------------------------------
Balance, end of period $ 10.04 3,480,500
-----------------------------------------------------------------------
Options exercisable, end of period $ 10.75 919,375
-----------------------------------------------------------------------
/T/
During the three and nine month periods ended September 30, 2004,
121,750 and 310,500 stock options were exercised for cash consideration
of $0.6 million and $1.0 million respectively, which has been charged to
general and administrative expense (2003 - $nil).
The following table summarizes information about stock options
outstanding at September 30, 2004:
/T/
Outstanding Exercisable
Weighted Weighted Weighted
Average Average Average
Exercise Contractual Exercise Exercisable Exercise
Prices Number Life Price Number Price
-----------------------------------------------------------------------
$ 8.91-9.80 2,265,500 3 $ 9.02 283,875 $ 9.04
$ 10.01-19.51 1,215,000 2 $ 11.94 635,500 $ 11.52
-----------------------------------------------------------------------
Total 3,480,500 2 $ 10.04 919,375 $ 10.75
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/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 sheets with an
offsetting net deferred gain. The net deferred gain is recognized into
net earnings (loss) over the life of the associated contracts.
The changes in fair value associated with the financial instruments are
recorded on the consolidated balance sheets with the associated
unrealized gain or loss recorded in net earnings (loss). 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 September 30, 2004.
/T/
September 30, 2004
-----------------------------------------------------------------------
Financial instrument asset $ 3,438
Financial instrument liability (6,625)
-----------------------------------------------------------------------
Net financial instrument liability $ (3,187)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, 2004 September 30, 2004
Net Mark-to Net Mark-to
Deferred Market Deferred Market
Amounts on Gain Amounts on Gain
Transition (Loss) Total Transition (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
September 30, 2004 - 1,307 1,307 - (7,168) (7,168)
-----------------------------------------------------------------------
Amortization of the
fair value of
contracts as
at September 30,
2004 234 - 234 (464) - (464)
-----------------------------------------------------------------------
Fair value of
contracts entered
into during the
period - 6,312 6,312 - 4,445 4,445
-----------------------------------------------------------------------
Unrealized loss on
financial
instruments 234 7,619 7,853 (1,914) (1,273) (3,187)
-----------------------------------------------------------------------
Realized (loss) on
financial instruments
for the period ended
September 30, 2004 - - (3,820) - - (5,539)
-----------------------------------------------------------------------
Net (loss) on financial
instruments for the
period ended
September 30, 2004 - - 4,033 - - (8,726)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
/T/
For the three and nine months ended September 30, 2004, the Company has
realized losses on financial instruments of $3.8 million and $5.5
million, respectively, compared to $10.4 million and $54.7 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 September 30, 2004, was
a gain of $5.8 million.
/T/
Description
of Swap Notional Indenture Effective
Transaction Maturity Date Amount Interest Swap to Rate
-----------------------------------------------------------------------
Swap of 7.875 November 1, 2010 US$175 US$ fixed US$ US$ LIBOR
percent US$ 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 $15.0 million
for CDN $21.5 million over the next two years at CDN $1.4337. The
US$/CDN$ closing exchange rate was 1.2616 as at September 30, 2004
(December 31, 2003 - 1.2965).
/T/
Year of settlement US dollars Weighted average exchange rate
-----------------------------------------------------------------------
2004 $ 3,000 1.4337
2005 12,000 1.4337
-----------------------------------------------------------------------
$ 15,000 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 September 30, 2004, was
a loss of $2.5 million. The change in fair value, a $5.8 million loss,
and $1.2 million amortization of the deferred gain have been recorded in
the consolidated statement of earnings.
(c) COMMODITY PRICE CONTRACTS
At September 30, 2004, the Company has entered into financial forward
contracts as follows:
/T/
Amount Price Term
------------------------------------------------------------------------
Sales Contracts
AECO Fixed Price 10,000 GJ/d $5.51 April 2004 - October 2004
AECO Fixed Price 10,000 GJ/d $5.55 April 2004 - October 2004
AECO Fixed Price 20,000 GJ/d $5.80 April 2004 - October 2004
AECO Fixed Price 10,000 GJ/d $5.81 April 2004 - October 2004
AECO Fixed Price 10,000 GJ/d $5.86 April 2004 - October 2004
AECO Collars 10,000 GJ/d $5.25-$6.75
collar April 2004 - October 2004
AECO Collars 10,000 GJ/d $5.25-$6.80
collar April 2004 - October 2004
AECO Fixed Price 20,000 GJ/d $6.82 September 2004 - October 2004
NYMEX Fixed
Price 10,000 MMbtu/d US $6.41 November 2004 - March 2005
NYMEX Fixed
Price 10,000 MMbtu/d US $7.46 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $7.60 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $7.90 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $8.03 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $6.28 April 2005 - June 2005
AECO Fixed Price 20,000 GJ/d $6.30 April 2005 - June 2005
AECO Fixed Price 20,000 GJ/d $6.80 April 2005 - June 2005
WTI Collars 1,000 Bbls US $25.00- January 2004 - December 2004
30.25 collar
Purchase Contracts
AECO Fixed Price 20,000 GJ/d $6.76 November 2004 - March 2005
------------------------------------------------------------------------
------------------------------------------------------------------------
/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 September 30, 2004, was
a loss of $2.0 million. The change in fair value, a $1.4 million loss,
and $1.7 million amortization of the deferred loss have been recorded in
the consolidated statement of earnings. At September 30, 2004, a $1.3
million loss was recorded in the consolidated statement of earnings
related to the fair value of financial contracts entered into after
January 1, 2004. No deferred gains or losses were recorded related to
these financial contracts.
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
On August 16, 2004, Paramount completed the acquisition of assets in the
Marten Creek area in Grande Prairie for $83.7 million, subject to
adjustments. In accounting for the acquisition, the Company recorded a
future tax asset in the amount of $96.5 million and a deferred credit of
$7.7 million. The future tax asset will be realized as deductions
associated with the tax pools are claimed for income tax purposes. The
deferred credit is amortized in proportion to the realization of the
future tax asset.
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 nine month period ended September 30, 2004.
11. Commitments
At September 30, 2004, the Company has entered into the following
physical delivery contracts:
/T/
Amount Price Term
------------------------------------------------------------------------
Sales Contracts
NIT Fixed Price 20,000 GJ/d $6.22 October 2004
NIT Fixed Price 10,000 GJ/d $6.71 October 2004
NIT Fixed Price 20,000 GJ/d $7.32 November 2004
NIT Fixed Price 10,000 GJ/d $7.16 September 2004 - October 2004
NIT Fixed Price 10,000 GJ/d $7.22 September 2004 - October 2004
Station 2 Fixed
Price 15,000 GJ/d $7.24 July 2004 - October 2004
Station 2 Fixed
Price 10,000 GJ/d $7.30 June 2004 - October 2004
Station 2 Fixed
Price 8,000 GJ/d $7.99 November 2004 - March 2005
Station 2 Fixed
Price 12,000 GJ/d $8.00 November 2004 - March 2005
------------------------------------------------------------------------
------------------------------------------------------------------------
/T/
12. Comparative Figures
Certain comparative figures have been reclassified to conform with the
current period's financial statement presentation.
13. Subsequent Events
On October 25, 2004, Paramount completed the issuance of 2,500,000
common shares at a price of $23.00 per share. The gross proceeds of the
issue are $57.5 million.
On October 15, 2004, Paramount completed the private placement of
2,000,000 common shares issued on a "flow-through" basis at $29.50 per
share. The gross proceeds of the issue are $59 million.
/T/
Paramount Resources Ltd.
Pro-forma Quarterly Condensed Financial Statements - unaudited
For Q4 2002, 2003 and Q1-Q3 2004
(thousands of dollars except for per share amounts)
(Note 1)
2004
Q3 Q2 Q1
(Note 2)
------------------------------------------------------------------------
Net revenue, before hedging $123,159 $102,064 $85,641
Financial instruments gain (loss) 4,033 (6,297) (6,462)
------------------------------------------------------------------------
127,192 95,767 79,179
Operating expenses 27,120 19,264 18,487
Interest 8,246 5,579 4,338
General and administrative 7,091 5,574 5,840
Lease rentals 1,141 872 1,234
Geological and geophysical 692 1,841 3,992
Dry hole costs 4,842 1,171 3,015
Depletion and depreciation 52,438 42,577 42,140
Other expenses (40,125) (1,000) 3,391
------------------------------------------------------------------------
61,445 75,878 82,437
------------------------------------------------------------------------
Earnings (loss) before taxes 65,747 19,889 (3,258)
Current and large corporations tax 1,083 1,773 776
Future tax (recovery) 18,852 8,180 (7,213)
------------------------------------------------------------------------
Net earnings (loss) $ 45,812 $ 9,936 $ 3,179
------------------------------------------------------------------------
Net earnings (loss) per common share
- basic $ 0.78 $ 0.17 $ 0.05
- diluted $ 0.76 $ 0.17 $ 0.05
Cash flow from operations $ 75,679 $ 69,515 $59,554
Cash flow from operations per common share
- basic $ 1.29 $ 1.19 $ 1.00
- diluted $ 1.26 $ 1.17 $ 0.99
WA shares o/s (basic) 58,496 58,626 59,560
WA shares o/s (diluted) 60,003 59,558 60,209
2003 2002
Q4 Q3 Q2 Q1 Q4
------------------------------------------------------------------------
Net revenue, before
hedging $76,156 $75,838 $ 80,319 $101,989 $ 77,000
Financial instruments
gain (loss) 1,541 (10,423) (15,218) (29,100) 3,925
------------------------------------------------------------------------
77,697 65,415 65,101 72,889 80,925
Operating expenses 22,287 21,738 18,302 14,338 14,709
Interest 5,604 2,879 4,163 5,415 9,367
General and
administrative 5,832 4,764 4,496 4,513 4,850
Lease rentals 1,027 1,070 702 775 899
Geological and
geophysical 3,208 1,071 3,423 748 1,182
Dry hole costs 5,750 1,533 10,558 5,821 115,909
Depletion and
depreciation 47,055 33,596 40,609 42,551 49,726
Other expenses (5,550) 5,567 32,123 528 (8,126)
------------------------------------------------------------------------
85,213 72,218 114,376 74,689 188,516
------------------------------------------------------------------------
Earnings (loss) before
taxes (7,516) (6,803) (49,275) (1,800) (107,591)
Current and large
corporations tax 1,165 419 741 547 1,989
Future tax (recovery) (19,977) 1,161 (48,128) 163 (74,272)
------------------------------------------------------------------------
Net earnings (loss) $11,296 $(8,383) $ (1,888) $ (2,510) $(35,308)
------------------------------------------------------------------------
Net earnings (loss) per
common share
- basic $ 0.19 $ (0.14) $ (0.03) $ (0.04) $ (0.59)
- diluted $ 0.19 $ (0.14) $ (0.03) $ (0.04) $ (0.59)
Cash flow from
operations $43,157 $28,568 $ 36,697 $ 47,301 $ 49,111
Cash flow from
operations per common
share $ 0.72 $ 0.47 $ 0.61 $ 0.79 $ 0.83
- basic $ 0.72 $ 0.47 $ 0.61 $ 0.79 $ 0.82
- diluted
WA shares o/s (basic) 60,168 60,169 60,169 59,998 59,458
WA shares o/s (diluted) 60,340 60,287 60,244 60,072 59,581
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 - Q3 2004 includes the major assets acquisitions.
Paramount Resources Ltd,
Pro-forma Supplemental Oil and Gas Operating Statistics - unaudited
For the Period Ended September 30, 2004
(Note 1)
Sales Volumes 2004
------------------------------------------------------------------------
Q3 Q2 Q1
------------------------------------------------------------------------
Gas (MMcf/d) 196 157 141
Oil and Natural Gas Liquids (Bbl/d) 8,446 6,134 5,675
------------------------------------------------------------------------
Total Sales Volumes (Boe/d) (6:1) 41,072 32,354 29,178
------------------------------------------------------------------------
------------------------------------------------------------------------
Per-unit Results 2004
------------------------------------------------------------------------
Q3 Q2 Q1
------------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, net of transporation and selling 6.36 7.01 6.54
Royalties 1.26 1.33 1.33
Operating expenses, net of processing revenue 1.16 1.03 1.08
------------------------------------------------------------------------
Cash netback before realized commodity hedge 3.94 4.65 4.13
Realized commodity hedge (0.13) (0.31) 0.42
------------------------------------------------------------------------
Cash netback including realized
commodity hedge 3.81 4.34 4.55
------------------------------------------------------------------------
------------------------------------------------------------------------
Produced Oil & Natural Gas Liquids ($/Bbl)
Price, net of transporation and selling 50.26 45.37 41.87
Royalties 10.02 7.58 7.52
Operating expenses, net of processing revenue 8.04 8.14 8.87
------------------------------------------------------------------------
Cash netback before realized commodity hedge 32.20 29.65 25.48
Realized commodity hedge (0.18) (2.75) (4.93)
------------------------------------------------------------------------
Cash netback including realized
commodity hedge 32.02 26.90 20.55
------------------------------------------------------------------------
------------------------------------------------------------------------
Total Produced ($/Boe)
Price, net of transporation and selling 40.66 42.67 39.73
Royalties 8.07 7.89 7.88
Operating expenses, net of processing
revenue 7.18 6.54 6.96
------------------------------------------------------------------------
Cash netback before realized commodity
hedge 25.41 28.24 24.89
Realized commodity hedge (0.67) (2.03) 1.07
------------------------------------------------------------------------
Cash netback including realized commodity
hedge 24.74 26.21 25.96
------------------------------------------------------------------------
------------------------------------------------------------------------
Sales Volumes 2003 2002
------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4
------------------------------------------------------------------------
Gas (MMcf/d) 141 136 142 143 172
Oil and Natural Gas
Liquids (Bbl/d) 5,877 7,461 7,465 7,892 8,552
------------------------------------------------------------------------
Total Sales Volumes
(Boe/d) (6:1) 29,353 30,098 31,129 31,711 37,243
------------------------------------------------------------------------
------------------------------------------------------------------------
Per-unit Results 2003 2002
------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4
------------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, net of
transporation
and selling 5.14 5.74 5.91 6.91 4.15
Royalties 0.55 1.30 1.14 1.43 0.92
Operating expenses,
net of processing
revenue 1.26 1.19 0.95 0.73 0.64
------------------------------------------------------------------------
Cash netback before
realized commodity
hedge 3.33 3.25 3.82 4.75 2.59
Realized commodity
hedge 0.25 (0.72) (1.07) (1.62) 0.29
------------------------------------------------------------------------
Cash netback including
realized commodity
hedge 3.58 2.53 2.75 3.13 2.88
------------------------------------------------------------------------
------------------------------------------------------------------------
Produced Oil & Natural Gas Liquids ($/Bbl)
Price, net of
transporation
and selling 36.02 36.48 36.94 42.98 36.03
Royalties 6.64 6.75 7.28 9.04 6.83
Operating expenses,
net of processing
revenue 11.01 10.01 8.90 6.96 5.72
------------------------------------------------------------------------
Cash netback before
realized commodity
hedge 18.37 19.72 20.76 26.98 23.48
Realized commodity
hedge (3.13) (2.27) (1.67) (4.03) (0.76)
------------------------------------------------------------------------
Cash netback including
realized commodity
hedge 15.24 17.45 19.09 22.95 22.72
------------------------------------------------------------------------
------------------------------------------------------------------------
Total Produced ($/Boe)
Price, net of
transporation
and selling 31.87 34.95 35.84 41.85 27.44
Royalties 3.95 7.56 6.95 8.70 5.80
Operating expenses,
net of processing
revenue 8.25 7.85 6.46 5.02 4.29
------------------------------------------------------------------------
Cash netback before
realized commodity
hedge 19.67 19.54 22.43 28.13 17.35
Realized commodity
hedge 0.57 (3.76) (5.37) (8.33) 1.15
------------------------------------------------------------------------
Cash netback including
realized commodity
hedge 20.24 15.78 17.06 19.80 18.50
------------------------------------------------------------------------
------------------------------------------------------------------------
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 - Q3 2004 includes the major asset acquisitions.
Note 3 - 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.
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
