Paramount Resources Ltd. Announces Results for the Third Quarter Ended September 30, 2003
FOR: PARAMOUNT RESOURCES LTD. TSX SYMBOL: POU NOVEMBER 12, 2003 - 21:46 ET Paramount Resources Ltd. Announces Results for the Third Quarter Ended September 30, 2003 CALGARY, ALBERTA-- Paramount Resources Ltd. ("Paramount") is pleased to announce its financial and operating results for the three months ended September 30, 2003. /T/ FINANCIAL HIGHLIGHTS (unaudited) Three Months Nine Months FINANCIAL Ended September 30 ended September 30 (thousands of dollars except for % % per share amounts) 2003 2002 Change 2003 2002 Change ------------------------------------------------------------------------ ------------------------------------------------------------------------ Gross Revenue 86,940 116,467 -25% 293,486 335,605 -13% Cash Flow (1) From operations 29,071 58,661 -50% 124,119 197,814 -37% Per share - basic 0.48 0.99 -52% 2.06 3.33 -38% - diluted 0.47 0.98 -52% 2.05 3.32 -38% Earnings (loss) Net earnings (loss) (7,851) 6,180 -227% (8,663) 51,706 -117% Per share - basic (0.13) 0.10 -230% (0.14) 0.87 -116% - diluted (0.13) 0.10 -230% (0.14) 0.86 -116% ------------------------------------------------------------------------ Exploration & development expenditures 36,185 26,097 39% 139,253 203,149 -31% ------------------------------------------------------------------------ Total Assets 1,180,551 1,654,742 -29% ------------------------------------------------------------------------ Net Debt (2) 298,148 597,752 -50% ------------------------------------------------------------------------ Shareholders' Equity 495,371 587,504 -16% ------------------------------------------------------------------------ Common shares outstanding (thousands) - September 30 60,169 59,459 1% - October 31 60,169 ------------------------------------------------------------------------ ------------------------------------------------------------------------ OPERATING Production Natural gas (MMcf/d) 135.8 259.3 -48% 156.8 234.3 -33% Crude oil and liquids (Bbl/d) 7,461 7,832 -5% 7,605 4,690 62% Total Production (BOE/d)@6:1 30,098 51,049 -41% 33,735 43,740 -23% ----------------------------------------------------------------------- Average Prices Natural gas (pre-hedge)($/Mcf) 5.74 3.04 89% 6.25 3.15 98% Natural gas ($/Mcf) 5.02 3.72 35% 5.10 3.88 31% Crude oil and liquids ($/Bbl) 34.21 36.71 -7% 36.18 34.25 6% ----------------------------------------------------------------------- Drilling Activity Gas 26 2 1200% 122 104 17% Oil 2 2 - 12 5 140% Other - - - - 2 - D & A 2 - - 10 9 11% ----------------------------------------------------------------------- Total Wells 30 4 650% 144 120 20% ----------------------------------------------------------------------- ----------------------------------------------------------------------- /T/ (1) Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items, dry hole, 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 the sum of accounts payable and accrued liabilities, shareholder loan, bank loans, drilling rig indebtedness and mortgage, less current assets. REVIEW OF OPERATIONS Kaybob Drilling, completion and construction activity in the Kaybob area increased dramatically in the third quarter compared to second quarter levels. Three drilling rigs and two service rigs have been kept active for most of the third quarter. Paramount participated in the drilling of 16 (12.7 net) wells in the third quarter resulting in 9 (7.3 net) gas wells, 2 (2.0 net) oil wells and 5 (3.4 net) standing wells. Construction of pipelines and lease facilities have kept pace with the drilling and completion rigs; as of November 1, 2003, ten of the wells drilled in the third quarter have been put on production. Capital spending increased from $4 million in the second quarter to $21 million in the third quarter. Gas volumes averaged 82 MMcf/d in the third quarter. This marginal increase in production over second quarter (80 MMcf/d) is the result of gas that was returned to production following plant maintenance and an increase in drilling and tie in activities which have added new gas wells to offset property declines. Current gas production from the Kaybob properties is approximately 90 MMcf/d. Oil and natural gas liquids production averaged 2,505 Bbl/d versus 2,111 Bbl/d in the second quarter 2003. This increase in production is due to the return of shut-in natural gas liquids, optimization at the Kaybob West oil property and two new oil wells that were drilled in the area. Construction was completed on Paramount's Kaybob North oil battery. This will significantly lower oil and condensate operating costs in the area. This facility provides an attractive alternative to third-party oil processing in the area, and will generate additional revenue to Paramount. Partner and regulatory approvals are being sought to expand the Kaybob North oil battery to include water disposal and heavy oil blending operations. Sour gas field compression was added in the Pine Creek area to permit the production of shut-in sour gas and increase the economic viability to develop sour gas plays in the area. Construction has started at the Clover gas plant to add plant inlet compression in order to be able to handle additional volumes of gas that we plan to place on production in the fourth quarter. Initial results from the wells drilled in the third quarter as part of our down-spacing program are very encouraging. Drilling activity will continue in the fourth quarter to exploit new gas reserves in existing gas pools. Paramount expects to have three drilling rigs active in this area for the remainder of the year, drilling an additional 17 net wells prior to year end. This activity is planned for the Pine Creek, Clover and Kaybob North properties. Operations will resume on two wells that were suspended in the second quarter due to the early spring break-up in 2003. Production volumes are now expected to exceed the year-end exit rate targets of 100 MMcf/d of gas and 2,500 Bbl/d of oil and natural gas liquids for the Kaybob Core Area. Grande Prairie The Sturgeon Lake/Mirage Core Area has been renamed the Grande Prairie Core Area following the sale of the Sturgeon Lake South assets, which was effective July 1, 2003, and closed October 1, 2003. The sale of Sturgeon Lake included daily production of 1,700 Bbl/d oil and 3.0 MMcf/d gas, and proven reserves at January 1, 2003 of 2.7 MMBbl oil and 4.2 Bcf gas, for a total consideration of $54.3 million. The Sturgeon Lake South property was our oldest oil property, having been developed in the late 1950's, and also incurred the highest per-unit operating costs of any Paramount property. The Grande Prairie area exited the third quarter with production rates of 15.1 MMcf/d of natural gas and 2,300 Bbl/d of oil and liquids (before the Sturgeon Lake sale). New drilling and tie ins before the end of the year are expected to increase natural gas exit rates for the year considerably despite the sale of the Sturgeon Lake assets. In Mirage, the shallow gas development program continued, with 13 (9.5 net) wells drilled during the quarter, nine of which were successful on initial completion and four are awaiting reworks. Production is presently at 6 MMcf/d from the program with five additional wells in the process of being tied in. At Saddle Hills, Paramount successfully drilled the 4-35 Wabamun well, which tested at rates in excess of 15 MMcf/d and 300 Bbl/d. The well is presently being tied in and will commence production in November 2003. The 6-25 Wabamun location spud November 3, 2003 as planned and should have results available prior to the end of the year. At Valhalla, production commenced through the newly constructed Paramount pipeline system; two wells are planned for the fourth quarter to take advantage of the new infrastructure. At Shadow and Goose River, three new wells were placed on production, opening up new properties, which will be areas of increased activity into the next drilling season. Budget planning has commenced for 2004, which will see continued high growth rates in this area. Already 65 potential locations have been identified with a projected budget tripling that of 2003. Northeast British Columbia and Liard, Northwest Territories All production in this area was adversely affected due to a 14-day turnaround at the Fort Nelson Plant. Net gas production has been relatively steady and we are exiting the third quarter at 11 MMcf/d Paramount has elected to participate in the Chevron Liard 3-K-29 and 2-M-25 wells anticipated to spud early next year. If successful this will be the fourth Chevron producing well in the Liard field. The Chevron Liard M-25 well workover was successfully recompleted for a current net daily production of 10 MMcf/d (0.2 MMcf/d net). The Clarke Lake c-15-J well was drilled and cased earlier in the third quarter and is still being evaluated. Paramount is currently participating in the Clarke Lake Petro-Canada b-57-I well. If successful, this well could be tied in before year end. Northwest Alberta / Cameron Hills, Northwest Territories No new drilling or construction projects were initiated in the Northwest Alberta Core Area during the third quarter due to seasonal access constraints. Activities have been focused on identifying opportunities and preparatory efforts required to execute those projects during the coming winter season. Some of the more prominent projects include the drilling and tie in of four gross wells targeting oil in Cameron Hills, N.W.T., and follow-up drilling to the Haro gas discovery of the first quarter of 2003. Net production for the third quarter averaged 21.5 MMcf/d and 900 Bbl/d . Operational challenges associated with wax have prevented Paramount from realizing the full oil production capabilities from Cameron Hills this quarter. A wax blockage in the Cameron K-74 gathering line is expected to be cleared late in the fourth quarter of 2003 and will result in an additional 500 Bbl/d of production. Southern Alberta / Saskatchewan / Montana / North Dakota Production in the third quarter of 2003 from the Southern Core Area averaged 9 MMcf/d and 2,179 Bbls/d reflecting the results of continued property dispositions started late last year. Production from the Southern Core Area to date in 2003 has averaged 9.5 MMcf/d and 2,618 Bbl/d. Operations during the third quarter were focused in the Alder Flats, Chain/Craigmyle and Long Coulee areas of Alberta and Lougheed, Saskatchewan. In Alder Flats, two Mannville gas wells were tied in and commenced production in September at a gross rate of 1.0 MMcf/d. In Chain/Craigmyle, four wells were drilled or recompleted in the Edmonton formation resulting in four new gas wells, three of which are currently producing with the fourth waiting on compression. Gas production additions were also made from the reconfiguration of the Delia 7-15 compressor station to lower the inlet suction pressure and from the tie in of solution gas at the Craigmyle 8-35 Battery. In Long Coulee one Mannville and one Bow Island well were put on production and a successful recompletion for a second Bow Island gas well was undertaken. In Lougheed, Saskatchewan several successful recompletions for increased Midale oil production were undertaken. The Southern Core Area has completed the process of consolidation and focus in the third quarter of 2003. This process has seen the Southern Core Area divest of smaller interest and non-operated/non-core properties to pursue the growth of fewer, higher interest core properties. FINANCIAL Petroleum and natural gas sales before hedging totaled $96.8 million for the three months ended September 30, 2003, as compared to $101.6 million for the comparable period in 2002. The decrease is due to lower production as a result of the disposition of properties to Paramount Energy Trust in the first quarter of 2003, offset somewhat by higher natural gas prices as compared to the third quarter of 2002. Cash flow from operations for the three months ended September 30, 2003 totaled $29.1 million or $0.47 per diluted common share as compared to $58.7 million or $0.98 per diluted common share for the third quarter of 2002. Paramount recorded a net loss for the current quarter of $7.9 million or $0.13 per diluted common share as compared to net income of $6.2 million or $0.10 per diluted common share for the comparable period in 2002. The decreases in cash flow and net income are due primarily to third quarter pre-tax commodity hedging losses of $10.4 million and a bad debt charge of $6 million relating to the bankruptcy of Mirant Canada Energy Marketing Ltd. as compared to $14.4 million pre-tax commodity hedging gains in the third quarter of 2002. The majority of the Company's natural gas hedging contracts expired at the end of October 2003. The Company had a natural gas sales contract with Mirant Canada Energy Marketing Ltd. ("Mirant"), which was assigned to a third party effective July 1, 2003, prior to the purchaser filing for bankruptcy protection under the Companies' Creditors Arrangement Act on July 15, 2003. The Company was owed approximately $8 million for June natural gas sales which has not yet been received. The $6 million bad debt provision recorded represents the Company's best estimate of the portion of the receivable which may not be collected. U.S. Notes Offering Paramount Resources Ltd. issued U.S. $175 million of 7 7/8 percent unsecured Senior Notes due 2010 in the United States on October 27, 2003, and the proceeds from the offering were used to repay senior bank debt. In addition, Paramount also closed a new Senior Credit facility with its existing banking syndicate totalling $203 million on the same day. The combined debt financing available is now approximately $430 million. At the end of the third quarter the Company had $272 million of loans drawn against its credit facility. The subsequent close of the Sturgeon Lake property sale has reduced this by a further $54.3 million. OUTLOOK Paramount has now completed the 18-month process of creating the Paramount Energy Trust while at the same time maintaining a significant, albeit lonely, intermediate-sized Canadian exploration and production company. The Company is now well financed with a balance sheet positioned to allow it to react to opportunities which may present themselves; a well defined short to medium-term growth platform in particular with the down-spacing program at Kaybob and the inventory of opportunities for growth in Grande Prairie, and Paramount has established long-term growth projects at Cameron Hills, Liard, and Colville Lake, all in the Northwest Territories, as well as significant opportunities for bitumen development in Northeast Alberta. Paramount has maintained its long-term perspective on the energy industry in Canada and looks forward to a period of renewed growth as it moves forward from this process to unlock shareholder value. MANAGEMENT'S DISCUSSION AND ANALYSIS Management's Discussion and Analysis ("MD&A") should be read in conjunction with the interim unaudited consolidated financial statements for the three and nine months ended September 30, 2003 and the audited consolidated financial statements and MD&A for the year ended December 31, 2002. /T/ Wells Drilled 2003 2002 ----------------------------------------------------------------------- Gross (1) Net (2) Gross (1) Net (2) ---------------------------------------------- Natural gas 122 84.5 104 80.6 Oil 12 10.5 5 3.9 Other - - 2 1.4 Dry 10 3.2 9 7.3 ----------------------------------------------------------------------- Total 144 98.2 120 93.1 ----------------------------------------------------------------------- ----------------------------------------------------------------------- (1) "Gross" wells means the number of wells in which Paramount has a working interest or a royalty interest that that may be converted 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. During the nine months ended September 30, 2003, Paramount participated in the drilling of 144 gross wells (98.2 net), compared to 120 gross wells (93.1 net) during the same period in 2002. CAPITAL EXPENDITURES Nine Months Ended September 30 ---------------------------------------------------------------------- (thousands of dollars) 2003 2002 2001 ---------------------------------------------------------------------- Land $ 12,523 $ 5,140 $ 31,507 Geological and geophysical 5,242 8,121 8,907 Drilling 74,993 115,373 99,345 Production equipment and facilities 46,495 74,515 85,634 ---------------------------------------------------------------------- Exploration and development expenditures 139,253 203,149 225,393 Summit Resources Limited acquisition (30,005) 437,933 - Dry hole and seismic costs expensed (26,224) (12,270) (17,569) Petroleum and natural gas property impairment (9,868) (49,136) - Property acquisitions - 28,595 12,566 Property dispositions (334,709) (2,423) (9,263) Other 802 1,998 (8,475) Depletion and depreciation expense (116,358) (108,327) (46,123) ---------------------------------------------------------------------- Net change in capital assets $ (377,109) $ 499,519 $ 156,529 ---------------------------------------------------------------------- ---------------------------------------------------------------------- /T/ Capital additions for the third quarter were concentrated in the Kaybob, Grande Prairie and Southern Alberta areas. For the nine months ended September 30, 2003, net exploration and development expenditures totaled $139.3 million. During the third quarter 2003, Paramount closed several minor non-core property dispositions for net proceeds of approximately $9 million. Total proceeds received to date for the minor non-core property dispositions is approximately $68 million. The proceeds received from the minor property dispositions have been applied against the Company's debt facilities. REVENUE Natural gas revenue before hedging totaled $267.3 million for the nine months ended September 30, 2003, as compared to $204.8 million during the same period in 2002. The increase in natural gas revenue results from higher commodity prices received during the period. Stronger natural gas demand resulted in an increase of 98 percent in Paramount's year-to-date average pre-hedged natural gas sales price to $6.25/Mcf as compared to $3.15/Mcf for the same period in 2002. Natural gas hedging losses for the nine months ended September 30, 2003 was $49.2 million. The 2003 year-to-date average natural gas price after hedging was $5.10/Mcf. For the three months ended September 30, 2003, natural gas revenue before hedging totaled $71.7 million as compared to $74.6 million for the same period in 2002. The 4 percent reduction in quarter-over-quarter sales was primarily due to the disposition of the Northeast Alberta assets to the Trust in March 2003. The Northeast Alberta assets contributed approximately $28 million of natural gas revenue in the third quarter of 2002. The decline in natural gas revenue as a result of the Northeast Alberta assets disposition was partially offset by the increase in the realized pre-hedged natural gas sales, which averaged $5.74/Mcf for the three months ended September 30, 2003 as compared to $3.04/Mcf for the same period in 2002. Natural gas sales volumes averaged 156.8 MMcf/d to September 30, 2003, as compared to 234.3 MMcf/d reported for the same period in 2002. Third quarter natural gas sales averaged 135.8 MMcf/d, a 48 percent decrease from 259.3 MMcf/d reported for the equivalent period in 2002. The decrease in natural gas sales is primarily the result of the disposition of the Northeast Alberta assets to the Trust and the minor non-core property dispositions. The Northeast Alberta assets contributed approximately 99 MMcf/d of natural gas sales volumes in the third quarter of 2002. /T/ Revenue Analysis Nine Months Ended September 30 ---------------------------------------------------------------------- (thousands of dollars) 2003 2002 2001 ---------------------------------------------------------------------- Natural gas and other $ 267,330 $ 204,766 $ 420,300 Crude oil and natural gas liquids 80,661 44,399 24,217 Commodity hedging gain (loss) (54,745) 45,920 (6,796) Gain (loss) on sale of short-term investments (1,020) 40,105 2,982 Other revenue 1,260 415 - ---------------------------------------------------------------------- Gross revenue 293,486 335,605 440,703 Royalties (71,848) (46,287) (87,268) ---------------------------------------------------------------------- Net revenue $ 221,638 $ 289,318 $ 353,435 ---------------------------------------------------------------------- ---------------------------------------------------------------------- /T/ Oil and natural gas liquids revenue before hedging for the nine months ended September 30, 2003 increased 82% to $80.7 million as compared to $44.4 million for the comparable period in 2002. The increase in oil and natural gas liquids revenue resulted from higher commodity prices, the addition of Summit's oil and natural gas liquids production and new oil production from Cameron Hills. Stronger oil and natural gas liquids demand resulted in an increase of 12 percent in Paramount's year-to-date average pre-hedged oil and natural gas liquids sales price to $38.86/Bbl as compared to $34.68/Bbl in the same period in 2002. Oil hedging losses for the nine months ended September 30, 2003 were $5.6 million. The 2003 year-to-date crude oil price after hedging was $36.18/Bbl. Oil and natural gas liquids production volumes increased 62 percent to average 7,605 Bbl/d for the nine months ended September 30, 2003 as compared to 4,690 Bbl/d for the comparable period in 2002. The increase was attributable to the combined impact of the acquisition of Summit, which at the time of acquisition produced approximately 5,000 Bbl/d of oil and natural gas liquids and the new oil production from Cameron Hills. Cameron Hills oil production contributed approximately 310 Bbl/d for the nine months ended September 30, 2003. For the three months ended September 30, 2003, oil and natural gas liquids revenue before hedging totaled $25.0 million as compared to $27.0 million for the same period in 2002. The average pre-hedged oil and natural gas liquids price received for the three months ended September 30, 2003 was $36.50/Bbl as compared to $37.45/Bbl for the same period in 2002. Oil and natural gas liquids production volumes totaled 7,461 Bbl/d in the third quarter of 2003, as compared to 7,832 Bbl/d for the comparable quarter of 2002. The 5 percent decrease in oil and natural gas liquids production was due primarily to minor non-core property dispositions closed during the year, offset somewhat by new oil production at Sturgeon Lake and Cameron Hills. /T/ Cash Netbacks Per Unit of Total Production Nine Months Ended September 30 ---------------------------------------------------------------------- ---------------------------------------------------------------------- ($/BOE@6:1) 2003 2002 2001 ---------------------------------------------------------------------- Sales price before hedging $ 37.78 $ 20.87 $ 40.60 Less: Royalties (7.80) (3.88) (7.97) Operating costs (6.40) (5.24) (3.97) ---------------------------------------------------------------------- Cash netback, before hedging 23.58 11.75 28.66 Commodity hedging gain (loss) (5.94) 3.85 (0.62) ---------------------------------------------------------------------- Cash netback, after hedging $ 17.64 $ 15.60 $ 28.04 ---------------------------------------------------------------------- ---------------------------------------------------------------------- /T/ ROYALTIES Alberta gas Crown royalties are a cash royalty calculated on the Crown's share of production using the Alberta Reference Price. The Alberta Reference Price is the monthly weighted average well head price for gas consumed in Alberta and gas exported from Alberta reduced by allowances for transportation and marketing. A subsequent cost of service credit is applied to account for the Crown's share of allowable capital and processing fees to arrive at the net royalty. Generally the Crown's share of production will increase in a higher price environment. Royalties for the nine months ended September 30, 2003 averaged $7.80/BOE or 21 percent of Paramount's average sales price of $37.78/BOE. This compares to $3.88/BOE or 19 percent of the average sales price reported for the same period in 2002. The increased rate results from the higher commodity prices received during the period, before hedging losses, as compared to prior year. For the three months ended September 30, 2003, royalties totaled $20.9 million as compared to $20.7 during the same period a year earlier. OPERATING COSTS For the nine months ended September 30, 2003, operating costs totaled $58.9 million compared to $62.6 million during the same period a year earlier. On a unit-of-production basis, average operating costs increased 22 percent to $6.40/BOE from $5.24/BOE in 2002. This increase is partially attributable to the higher operating costs of our mature Sturgeon Lake property, averaging $11.13/BOE for nine months ended September 30, 2003. The operational challenges that delayed Paramount in achieving full oil production from Cameron Hills also increased operating costs per unit in the third quarter of 2003. The cost optimization will be realized in the fourth quarter once the Cameron K-74 production is brought on-line. For the three months ended September 30, 2003, operating costs totaled $21.7 million as compared to $22.1 million for the same period in 2002. GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses totaled $14.1 million for the nine months ended September 30, 2003, as compared to $10.4 million recorded for the same period a year earlier. On a unit-of-production basis, 2003 year-to-date general and administrative expenses increased to $1.53/BOE as compared to $0.87/BOE for the period ended September 30, 2002. The increase from 2002 is due primarily to lower overhead recoveries related to lower capital spending levels compared to prior year. Paramount does not capitalize any general and administrative expenses. BAD DEBT The Company had a natural gas sales contract with Mirant Canada Energy Marketing Ltd. ("Mirant"), which was assigned to a third party effective July 1, 2003, prior to Mirant filing for bankruptcy protection under the Companies' Creditors Arrangement Act on July 15, 2003. The Company is owed approximately $8 million for June natural gas sales which has not yet been received. The $6 million bad debt provision recorded represents the Company's best estimate of the portion of the receivable which may not be collected. DRY HOLE COSTS The Company follows the Successful Efforts Method of accounting for petroleum and natural gas operations. Under this method the Company capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves. The cost of unproductive wells, abandoned wells and surrendered leases are charged to earnings in the year of abandonment or surrender. For the nine months ended September 30, 2003, $21.0 million in dry hole costs were recorded, as compared to $4.1 million in the same period of 2002. Of the dry hole expense recorded in 2003, approximately $16.7 million results from wells drilled in prior years, which were determined in the current year to be incapable of production in economic quantities. WRITE-DOWN OF US PETROLEUM AND NATURAL GAS PROPERTIES During the nine months ended September 30, 2003, the Company recorded a write-down of $9.9 million, representing the remainder of its petroleum and natural gas assets in California. INCOME TAXES At December 31, 2002, the Company had accumulated tax pools of approximately $796 million, which will be available for deduction in 2003 in accordance with Canadian income tax regulations at varying rates of amortization. Paramount does not expect to pay current income taxes in 2003. In 2003, the Alberta provincial and Canadian federal governments introduced legislation to reduce corporate taxes. The changes are considered substantively enacted for the purposes of Canadian GAAP and, accordingly, the Company's future income tax liability has been reduced by $33.4 million. The effect of this reduction has been recognized in the future income tax expense (recovery) for the nine-month period ended September 30, 2003. CASH FLOW AND EARNINGS Cash flow from operations for the nine months ended September 30, 2003 totaled $124.1 million or $2.06 per basic common share ($2.05 per fully diluted common share), representing a 37 percent decrease from the $197.8 million, or $3.33 per basic common share ($3.32 per fully diluted common share) reported for the corresponding period in 2002. The decrease is due to lower production levels, as well as commodity hedging losses, offset somewhat by higher natural gas and oil and natural gas liquids prices, as compared to prior year. Fully diluted weighted average shares outstanding totaled 60.5 million for the nine months ended September 30, 2003. Cash flow will continue to be directed towards the Company's capital expenditure program funding ongoing working capital requirements. Net loss for the nine months ended September 30, 2003 totaled $8.7 million or $0.14 per basic and fully diluted common share, compared to net earnings of $51.7 million, or $0.87 per basic common share ($0.86 per fully diluted common share) reported for the same period a year earlier. The net loss for the nine month period is primarily the result of a commodity hedging loss of $54.7 million, offset by a $33.4 million future tax gain due to changes in federal and provincial tax rates. A one-time loss on sale of property and equipment of $21.7 million was recorded as a result of the disposition of a non-core property in Alberta. SUBSEQUENT EVENTS On October 1, 2003, the Company sold its Sturgeon Lake properties in the Grande Prairie Core Area, including the associated oil batteries and gas plants, to an unrelated third party for proceeds of $54.3 million. The carrying value of this property included in property, plant and equipment was approximately $36 million, resulting in a pre-tax gain on sale of approximately $18 million. On October 27, 2003, the Company replaced its existing credit facility with a new $203 million committed revolving/non-revolving term facility with the same syndicate of Canadian chartered banks. Borrowings under the facility bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR rates plus applicable margins, ranging from 50 to 300 basis points, dependent on certain conditions. The revolving nature of the new facility expires on March 31, 2004. The Company 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 an extension, the amount due to those lenders will convert to a 1-year non-revolving term loan with principal due in full on March 31, 2005. Advances drawn on the facility are secured by a first floating charge over all the assets of the Company. The Company issued U.S. $175 million of 7 7/8 percent Senior Notes due 2010 on October 27, 2003. Interest on the notes is payable semi-annually, beginning in 2004. The Company may redeem some or all of the notes at any time after November 1, 2007 at redemption prices ranging from 100 percent to 103.938 percent of the principal amount, plus accrued and unpaid interest to the redemption date, depending on the year in which the notes are redeemed. In addition, the Company may redeem up to 35% of the notes prior to November 1, 2006 at 107.875 percent of the principal amount, plus accrued interest to the redemption date, using the proceeds of certain equity offerings. The notes are unsecured and rank equally with all of the Company's existing and future unsecured indebtedness. RECENT ACCOUNTING PRONOUNCEMENTS Variable Interest Entities The Canadian Institute of Chartered Accountants ("CICA") recently issued Accounting Guideline No. 15, Consolidation of Variable Interest Entities (the "Guideline"). The Guideline requires the consolidation of entities in which an enterprise absorbs a majority of the entity's expected losses, receives a majority of the entity's expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The Guideline applies to annual and interim periods beginning on or after November 1, 2004, except for certain disclosure requirements. Entities should provide disclosures about variable interest entities in which they hold significant variable interests for periods beginning on or after January 1, 2004. The Company does not expect the implementation of this Guideline to have a material impact on its financial statements. Asset Retirement Obligation The Canadian Institute of Chartered Accountants recently issued section 3110 - Asset Retirement Obligation which addresses statutory, regulatory, contractual and other legal obligations associated with the retirement of a tangible long-lived asset that results from its acquisition, construction, development or normal operation. Under Section 3110, asset retirement obligations are initially measured at fair value at the time the obligation is incurred with a corresponding amount capitalized as part of the asset's carrying value and depreciated over the asset's useful life using a systematic and rational allocation method. On initial recognition, the fair value of an asset retirement obligation is determined based upon the expected present value of future cash flows. In subsequent periods, the carrying amount of the liability would be adjusted to reflect (a) the passage of time, and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The change in liability due to the passage of time is measured by applying an interest method of allocation to the opening liability and is recognized as an increase in the carrying value of the liability and an expense. The expense must be recorded as an operating item in the income statement, not as a component of interest expense. A change in the liability resulting from revisions to either the timing or the amount of the original estimate of undiscounted cash flows is recognized as an increase or decrease in the carrying amount of the liability with an offsetting increase or decrease in the carrying amount of the associated asset. As of January 1, 2003, the amount to be recorded as the fair value of the liability was estimated to be $30.2 million. Stock-Based Compensation and Other Stock-Based Payments In December 2001, The Canadian Institute of Chartered Accountants issued Handbook Section 3870, Stock-Based Compensation and Other Stock-Based Payments, which requires fair value accounting for all stock-based payments to non-employees, and for employees awards that are direct awards of stock, or call for settlement in cash or other assets, and for stock appreciation rights. For all other employee awards, the present standard allows disclosure of pro forma net income and pro forma earnings per share in the income statement. In October 2003, the Canadian Institute of Chartered Accountants amended Handbook Section 3870 to require recognition of expense, based on the fair value method, for all employee stock-based compensation transactions for fiscal years beginning on or after January 1, 2004. The Recommendations of the Section should also be applied to the following awards that are outstanding at the start of the first fiscal year beginning on or after January 1, 2002 in which date of adoption of this Section is initially applied: (a) awards that call for settlement in cash or other assets; (b) stock appreciation rights that call for settlement by the issuance of equity instruments; and (c) any other award that is modified so as to become an award included in (a) or (b) above. The award should be accounted for as a new award, and not using modification accounting. The cumulative amount, applicable to (a) or (b) above, that would have been recognized in prior years had this Section been applied, less any amount previously recognized, should be recognized as the effect of a change in accounting policy and charged to opening retained earnings for the fiscal year in which this Section is initially applied, without restatement of prior periods. For awards other than those described above, this Section is adopted for fiscal years beginning on or after January 1, 2004. We plan to adopt the fair-value method of accounting for stock options in the fourth quarter of 2003. We plan to apply the fair-value based method prospectively, whereby compensation cost will be recognized for all options granted on or after January 1, 2003. This alternative is only available to companies that elect to adopt the fair-value method of accounting for stock-based compensation for fiscal years beginning before January 1, 2004. The impact of adopting the fair-value based method is expected to be immaterial in 2003. /T/ PARAMOUNT RESOURCES LTD. CONSOLIDATED BALANCE SHEETS September 30 December 31 --------------------------------------------------------------------- (thousands of dollars) 2003 2002 --------------------------------------------------------------------- (unaudited) ASSETS (note 4) Current assets Short-term investments (market value: $16,592; 2002 - $14,168) $ 16,292 $ 14,168 Accounts receivable 82,915 91,042 Prepaid expenses 14,871 19,213 --------------------------------------------------------------------- 114,078 124,423 Property, plant and equipment, net 1,034,852 1,411,961 Goodwill (note 2) 31,621 - --------------------------------------------------------------------- $ 1,180,551 $ 1,536,384 --------------------------------------------------------------------- --------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities $ 132,503 $ 140,396 Shareholder loan - 33,000 Bank loans (note 4) 272,041 498,097 --------------------------------------------------------------------- 404,544 671,493 --------------------------------------------------------------------- Drilling rig indebtedness 1,184 1,443 Mortgage 6,498 6,730 Provision for future site restoration and abandonment costs 20,097 22,954 Deferred revenue 741 7,804 Future income taxes (note 7) 252,116 279,855 --------------------------------------------------------------------- 280,636 318,786 --------------------------------------------------------------------- Commitments and contingencies (note 5) --------------------------------------------------------------------- Shareholders' equity Share capital (note 6) Issued and outstanding 60,168,600 common shares (2002- 59,458,600 common shares) 200,510 190,193 Retained earnings 294,861 355,912 --------------------------------------------------------------------- 495,371 546,105 --------------------------------------------------------------------- $ 1,180,551 $ 1,536,384 --------------------------------------------------------------------- --------------------------------------------------------------------- See accompanying notes to consolidated financial statements PARAMOUNT RESOURCES LTD. CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS (unaudited) Three Months Nine Months ended September 30 ended September 30 --------------------------------------------------------------------- (thousands of dollars except for per share amounts) 2003 2002 2003 2002 --------------------------------------------------------------------- Revenue Petroleum and natural gas sales $ 96,774 $101,627 $347,991 $249,165 Commodity hedging gain (loss) (note 5) (10,423) 14,425 (54,745) 45,920 Royalties (net of ARTC) (20,936) (20,687) (71,848) (46,287) Gain (loss) on sale of investments - - (1,020) 40,105 Other revenue 589 415 1,260 415 --------------------------------------------------------------------- 66,004 95,780 221,638 289,318 --------------------------------------------------------------------- Expenses Operating 21,738 22,051 58,906 62,593 Surmont compensation - net - 669 - (37,291) Interest on bank loans 3,017 8,979 14,313 14,216 General and administrative 4,709 4,692 14,066 10,444 Bad debt expense (note 8) 5,977 - 5,977 - Lease rentals 1,070 1,343 2,547 2,967 Geological and geophysical 1,071 1,238 5,242 8,121 Dry hole costs 1,533 979 20,982 4,149 Loss (gain) on sale of property and equipment (1,313) (3) 19,481 (133) Provision for future site restoration and abandonment costs 848 618 3,043 1,818 Depletion and depreciation 33,175 47,727 116,358 108,327 Write-down of US petroleum and natural gas properties - - 9,868 40,000 --------------------------------------------------------------------- 71,825 88,293 270,783 215,211 --------------------------------------------------------------------- Earnings (loss) before taxes (5,821) 7,487 (49,145) 74,107 Income and other taxes Large corporations tax and other 422 (54) 1,710 (1,284) Future income tax (recovery) (note 7) 1,608 (1,253) (42,192) (21,117) --------------------------------------------------------------------- Net earnings (loss) (7,851) 6,180 (8,663) 51,706 Retained earnings, beginning of period 302,712 391,131 355,912 346,064 Adjustment on disposition of assets to a related party (note 3) - - (1,388) - Dividends (note 3) - - (51,000) - Adoption of new accounting policy - - - (459) --------------------------------------------------------------------- Retained earnings, end of period $294,861 $397,311 $294,861 $397,311 --------------------------------------------------------------------- --------------------------------------------------------------------- Net earnings (loss) per common share -basic $ (0.13) $ 0.10 $ (0.14) $ 0.87 -diluted $ (0.13) $ 0.10 $ (0.14) $ 0.86 --------------------------------------------------------------------- Weighted average number of common shares outstanding (thousands) -basic 60,169 59,459 60,112 59,457 -diluted 60,287 59,616 60,520 59,524 --------------------------------------------------------------------- See accompanying notes to consolidated financial statements PARAMOUNT RESOURCES LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) Three Months Nine Months ended September 30 ended September 30 --------------------------------------------------------------------- (thousands of dollars) 2003 2002 2003 2002 --------------------------------------------------------------------- Operating activities Net earnings (loss) $ (7,851) $ 6,180 $ (8,663) $ 51,706 Add (deduct) non-cash items Write-down of Surmont assets - - - 9,136 Future income tax (recovery) 1,608 1,253 (42,192) 21,117 Depletion and depreciation 33,175 47,727 116,358 108,327 Write-down of US petroleum and natural gas properties - - 9,868 40,000 Provision for future site restoration and abandonment costs 848 618 3,043 1,818 Loss (gain) on sale of property and equipment (1,313) (3) 19,481 (133) Add items not related to operating activities Surmont compensation - 669 - (46,427) Dry hole 1,533 979 20,982 4,149 Geological and geophysical 1,071 1,238 5,242 8,121 --------------------------------------------------------------------- Cash flow from operations 29,071 58,661 124,119 197,814 (Decrease) increase in deferred revenue (2,223) (11,734) (7,063) 16,091 Change in non-cash operating working capital (3,900) (56,123) (12,850) 66,598 --------------------------------------------------------------------- 22,948 (9,196) 104,206 280,503 --------------------------------------------------------------------- Financing activities Bank loan - draws - (12,297) 10,000 209,168 Bank loan - repayments (2,849) - (236,056) - Shareholder loan - 33,000 (33,000) 33,000 Capital stock - (459) 10,317 414 Mortgage (79) - (232) - Drilling rig indebtedness (88) (3,070) (259) (926) --------------------------------------------------------------------- (3,016) 17,174 (249,230) 241,656 --------------------------------------------------------------------- Cash flow provided by (used in) operating and financing activities 19,932 7,978 (145,024) 522,159 --------------------------------------------------------------------- Investing activities Property, plant and equipment expenditures 34,623 25,923 134,070 195,233 Acquisition of Summit Resources Limited - - - 338,581 Petroleum and natural gas property acquisitions - 195 - 28,595 Geological and geophysical costs 1,071 1,238 5,242 8,121 Proceeds on sale of property and equipment (10,374) (1,374) (271,855) (4,707) Surmont compensation - 669 - (46,427) Change in non-cash investing working capital (5,388) 292 (12,481) 3,503 --------------------------------------------------------------------- Cash flow (provided by) used in investing activities 19,932 26,943 (145,024) 522,899 --------------------------------------------------------------------- Decrease in cash - (18,965) - (740) Cash, beginning of period - 18,965 - 740 --------------------------------------------------------------------- Cash, end of period $ - $ - $ - $ - --------------------------------------------------------------------- --------------------------------------------------------------------- Income taxes paid $ - $ - $ 5,466 $ 25,000 --------------------------------------------------------------------- Interest paid $ 3,169 $10,205 $13,798 $ 14,006 --------------------------------------------------------------------- See accompanying notes to consolidated financial statements /T/ NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (all tabular dollar amounts expressed in thousands of dollars) Paramount Resources Ltd. ("Paramount" or the "Company") is involved in the exploration and development of petroleum and natural gas primarily in western Canada. The interim consolidated financial statements are stated in Canadian dollars and have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Certain information and disclosures normally required to be included in notes to annual consolidated financial statements have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Paramount's Annual Report for the year ended December 31, 2002. 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, 2002, except as noted below: Goodwill Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is not amortized and is assessed by the Company for impairment at least annually. Impairment is assessed based on a comparison of the fair value of the net assets acquired to the carrying value of the net assets, including goodwill. Any excess of carrying value over and above fair value is the impairment amount, and is charged to earnings in the period identified. 2. ACQUISITION OF SUMMIT RESOURCES LIMITED On May 12, 2002, Paramount and Summit Resources Limited ("Summit") jointly announced that they had entered into an agreement pursuant to which Paramount made an offer to purchase all of the issued and outstanding common shares of Summit for cash consideration of $7.40 per share or approximately $249.6 million, including acquisition costs. This transaction has been accounted for using the purchase method and is being accounted for as of the date of substantial completion of the acquisition of June 28, 2002. The Company has finalized the purchase price equation for this acquisition. The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of acquisition: /T/ ----------------------------------------------------------- Assets Accounts receivable $ 13,997 Petroleum and natural gas properties 419,642 Goodwill 31,621 ----------------------------------------------------------- 465,260 ----------------------------------------------------------- Liabilities Accounts payable 21,946 Future income taxes 108,373 Debt 74,513 Other liabilities 10,866 ----------------------------------------------------------- 215,698 ----------------------------------------------------------- Net assets acquired $ 249,562 ----------------------------------------------------------- ----------------------------------------------------------- /T/ 3. DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST During the first quarter of 2003, the Company completed the formation and structuring of Paramount Energy Trust (the "Trust") through the following transactions: a) On February 3, 2003, Paramount transferred to the Trust natural gas properties in the Legend area of Northeast Alberta for net proceeds of $28 million and 9,907,767 units of the Trust. b) On February 3, 2003, Paramount declared a dividend-in-kind of $51 million, consisting of an aggregate of 9,907,767 units of the Trust. The dividend was paid to shareholders of Paramount's common shares of record on the close of business on February 11, 2003. c) On March 11, 2003, in conjunction with the closing of a rights offering by the Trust, Paramount disposed of additional natural gas properties in Northeast Alberta to Paramount Operating Trust for net proceeds of $175 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 Paramount. Details are as follows: /T/ Natural gas properties $ 240,326 Future income tax liability 11,039 Site restoration liability (5,900) Costs of disposition 9,516 Adjustment to retained earnings (1,388) ---------------------------------------------------------- Net proceeds on disposition $ 253,593 ---------------------------------------------------------- ---------------------------------------------------------- /T/ Associated with the creation and financing of the Trust and the transfer of natural gas properties to the Trust, the Company incurred costs of approximately $9.5 million. These costs have been included as a cost of disposition. 4. BANK LOAN In 2002, the Company negotiated a $600 million credit facility with a syndicate of Canadian chartered banks for general corporate use and to fund the Summit acquisition. The credit facility consisted of a $466 million production facility, a $109 million bridge facility and a $25 million working capital facility. The available borrowings were reduced to a total of $304.2 million as at September 30, 2003, reflecting the dispositions of the Trust and other minor non-core properties. The Company has provided a first floating charge over all the assets and a limited recourse guarantee from Paramount Oil and Gas Ltd., a related entity with a significant ownership interest in the Company. The facility bears interest at prime rates, bankers acceptance rates or libor rates plus a margin ranging from 62.5 to 162.5 basis points. In October, the Company negotiated a new committed term facility with the same syndicate of Canadian chartered banks (see note 9). 5. FINANCIAL INSTRUMENTS The Company's financial instruments included in the consolidated balance sheet are comprised of short-term investments, accounts receivable, accounts payable and accrued liabilities, shareholder loan, bank loans, mortgage and drilling rig indebtedness. (a) Commodity price hedges As at September 30, 2003, the Company has entered into financial forward hedging arrangements as follows: /T/ Price Term --------------------------------------------------------------------- AECO Sell 10,000 GJ/d $ 5.46 November 2002 - October 2003 Sell 20,000 GJ/d $ 5.06 November 2002 - October 2003 Sell 20,000 GJ/d $ 5.25 November 2002 - October 2003 Sell 15,000 GJ/d $ 7.55 November 2003 - March 2004 NYMEX Sell 20 MMcf/d U.S. $3.83 November 2002 - October 2003 Sell 20 MMcf/d U.S. $3.90 November 2002 - October 2003 Sell 10 MMcf/d U.S. $4.10 November 2002 - October 2003 Buy 10 MMcf/d U.S. $4.94 August 2003 - October 2003 Buy 10 MMcf/d U.S. $4.99 August 2003 - October 2003 WTI Sell 1,000 bbl/d U.S. $24.07 May 2002 - April 2004 Sell 1,000 bbl/d U.S. $24.33 January 2003 - December 2003 /T/ Had these financial contracts been settled on September 30, 2003, using prices in effect at that time, the mark-to-market before tax gain would have totaled $0.1 million. Subsequent to September 30, 2003, the Company entered into financial agreements as follows: /T/ Price Term --------------------------------------------------------------------- AECO Sell 15,000 GJ/d $6.42 November 2003 - March 2004 Sell 20,000 GJ/d $5.50-$7.80 (collar) November 2003 - March 2004 WTI Sell 1,000 bbl/d U.S. $25.00-$30.25 (collar) January 2004 - December 2004 /T/ (b) Foreign exchange hedges Foreign currency index swap transactions entered into by the Company are unchanged from those outstanding at December 31, 2002. At September 30, 2003, the estimated fair value of these hedges based on the Company's assessment of available market information was a gain of $2.4 million. (C) Fair values of financial assets and liabilities Borrowings under bank credit facilities are for short periods and are market rate based; thus, carrying values approximate fair values. Fair values for derivative instruments are determined based on the estimated cash repayment or receipt necessary to settle the contract at period-end. Cash payments or receipts are based on discounted cash flow analysis using current market rates and prices available to the Company. The fair values of other financial instruments, including accounts receivable, accounts payable and accrued liabilities, approximate their carrying values due to the short-term maturity of those instruments. The fair values of the mortgage and drilling rig indebtedness approximate their carrying values, as there have been no significant changes in long-term interest rates from the dates these liabilities were incurred to the balance sheet date. (d) Credit risk The Company is exposed to credit risk from financial instruments to the extent of non-performance by third parties, and non-performance by counterparties to swap agreements. The Company minimizes credit risk associated with possible non-performance by financial instrument counterparties by entering into contracts with only highly rated counterparties, and controls third-party credit risk with credit approvals, limits on exposures to any one counterparty, and monitoring procedures. The Company sells production to a variety of purchasers under normal industry sale and payment terms. The Company's accounts receivable are with customers and joint venture partners in the petroleum and natural gas industry and are subject to normal credit risks. 6. SHARE CAPITAL (a) Authorized capital The authorized capital of the Company consists 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. (b) Issued capital Common share transactions for the respective periods are as follows: /T/ ----------------------------------------------------------------------- Nine months ended Year Ended September 30, 2003 December 31, 2002 ----------------------------------------------------------------------- Common Common Shares Amount Shares Amount ----------------------------------------------------------------------- Balance, beginning of year 59,458,600 $ 190,193 59,453,600 $ 189,320 Stock options exercised for shares during the period 710,000 10,317 5,000 72 Expense recognized in respect of stock-based compensation during the period - - - 801 ----------------------------------------------------------------------- Balance, end of period 60,168,600 $ 200,510 59,458,600 $ 190,193 ----------------------------------------------------------------------- ----------------------------------------------------------------------- /T/ (c) Stock option plan/share appreciation rights plan During 2001, the Company replaced the Share Appreciation Rights Plan ("SARP") with the Employee Incentive Stock Option plan (the "plan"). Under the plan, stock options are granted at the current market price on the date of issuance. Participants in the plan, upon exercising their stock options, may request to receive either a cash payment equal to the difference between the exercise price and the market price of the Company's common shares or common shares issued from Treasury. Irrespective of the participant's request, the Company may choose, and has a history of doing so, to only issue common shares. Cash payments made in respect of the plan are charged to general and administrative expenses when incurred. Options granted vest over four years and have a four and a half year contractual life. The Company has reserved 5.9 million stock options for issuance pursuant to the plan. The recognized expenses in respect of the SARP for the three and nine month periods ended September 30, 2003 were $nil (September 30, 2002 - $113,000 and $342,000 respectively). As the remaining outstanding share appreciation rights were cancelled on February 6, 2003, no further expenses will be recorded in respect of the share appreciation rights plan. The Company accounts for its employee stock options using the intrinsic value method. Had compensation cost for the Company's stock-based compensation plans been determined based on the fair value at the grant date of these awards, the Company's net earnings (loss) and net earnings (loss) per share would have been adjusted to the pro forma amounts indicated below: /T/ ----------------------------------------------------------------------- Three months Nine months ended ended September 30 September 30 ----------------------------------------------------------------------- 2003 2002 2003 2002 ----------------------------------------------------------------------- Net earnings (loss) as reported (7,851) 6,180 (8,663) 51,706 pro forma (8,206) 6,159 (9,394) 51,669 Net earnings (loss) per common as reported (0.13) 0.10 (0.14) 0.87 share - basic pro forma (0.14) 0.10 (0.16) 0.87 Net earnings (loss) per common as reported (0.13) 0.10 (0.14) 0.86 share - diluted pro forma (0.14) 0.10 (0.16) 0.86 ----------------------------------------------------------------------- /T/ The fair value for these options was estimated at the date of granting using a Black-Scholes Option Pricing Model with the following assumptions: weighted-average risk-free interest rate of 5.8 percent; dividend yield of zero percent; weighted-average volatility factor of the expected market price of the Company's common shares of 39.5 percent; and a weighted-average expected life of the options of 4 years. During the nine months ended September 30, 2003, the Company issued 1,603,500 stock options at exercise prices ranging from $9.00 to $10.01 per option. Also during the period, 941,500 stock options issued in 2001, the majority of which were at exercise prices of $14.50 and $13.35 per option, were re-priced to exercise prices of $10.22 and $9.07 per option, respectively. The following table summarizes information about stock options outstanding at September 30, 2003: /T/ ---------------------------------------------------------------------- Exercise Number Weighted average Number price range outstanding remaining exercisable ($/share) at September contractual at September 30, 2003 life (years) 30, 2003 ---------------------------------------------------------------------- $ 9.00 1,417,500 4 69,000 $ 9.35 - 10.01 148,000 4 - $ 9.07 271,000 3 - $10.22 643,500 2 37,500 $12.02 571,000 2 571,000 ---------------------------------------------------------------------- $ 9.67 3,051,000 3 677,500 ---------------------------------------------------------------------- /T/ 7. INCOME TAXES In May 2003, the Government of Alberta introduced legislation to reduce its corporate income tax rate by 0.5% effective April 1, 2003. In June 2003, the Canadian federal government introduced legislation to change the taxation of resource income. The legislation reduces the corporate income tax rate on resource income from 28% to 21% over five years beginning January 1, 2003. Over the same period, the deduction for resource allowance is phased out and a deduction of actual crown royalties paid is phased in. The changes are considered substantively enacted for the purposes of Canadian GAAP and, accordingly, the Company's future income tax liability has been reduced by $33.4 million. The effect of this reduction has been recognized in the future income tax expense (recovery) for the nine month period ended September 30, 2003. 8. BAD DEBT The Company had a natural gas sales contract with Mirant Canada Energy Marketing Ltd. ("Mirant"), which was assigned to a third party effective July 1, 2003, prior to Mirant filing for bankruptcy protection under the Companies' Creditors Arrangement Act on July 15, 2003. The Company is owed approximately $8 million for June natural gas sales which has not yet been received. The $6 million bad debt provision recorded represents the Company's best estimate of the portion of the receivable which may not be collected. 9. SUBSEQUENT EVENTS (a) On October 1, 2003, the Company sold its Sturgeon Lake properties in the Grande Prairie core area, including the associated oil batteries and gas plants, to an unrelated third party for proceeds of $54.3 million. The carrying value of this property included in property, plant and equipment was approximately $36 million, resulting in a pre-tax gain on sale of approximately $18 million. (b) On October 27, 2003, the Company replaced its existing credit facility (described in note 4) with a new $203 million committed revolving/non-revolving term facility with the same syndicate of Canadian chartered banks. Borrowings under the facility bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR rates plus applicable margins, ranging from 50 to 300 basis points, dependent on certain conditions. The revolving nature of the new facility expires on March 31, 2004. The Company 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 an extension, the amount due to those lenders will convert to a one-year non-revolving term loan with principal due in full on March 31, 2005. Advances drawn on the facility are secured by a first floating charge over all the assets of the Company. (c) The Company issued U.S. $175 million of 7 7/8 percent Senior Notes due 2010 on October 27, 2003. Interest on the notes is payable semi-annually, beginning in 2004. The Company may redeem some or all of the notes at any time after November 1, 2007 at redemption prices ranging from 100 percent to 103.938 percent of the principal amount, plus accrued and unpaid interest to the redemption date, depending on the year in which the notes are redeemed. In addition, the Company may redeem up to 35 percent of the notes prior to November 1, 2006 at 107.875 percent of the principal amount, plus accrued interest to the redemption date, using the proceeds of certain equity offerings. The notes are unsecured and rank equally with all of the Company's existing and future unsecured indebtedness.
For further information: Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Operating Officer, (403) 290-3600 / Paramount Resources Ltd., B.K. (Bernie) Lee, Chief Financial Officer, (403) 290-3600, (403) 262-7994 (FAX), www.paramountres.com, Paramount Resources Ltd., C.H. (Clay) Riddell, Chairman and Chief Executive Officer, (403) 290-3600, (403) 262-7994 (FAX)