Paramount Resources Ltd. Annual Report 2004

Plain-text annual report

2004 Annual report President’s Message Core Producing Areas Review of Operations Areas of Interest Management’s Discussion & Analysis Management’s and Auditors’ Report Financial Statements Notes to Financial Statements Corporate Information Analyst supplement 03 06 11 20 26 44 45 48 68 ANNUAL AND SPECIAL MEETING Shareholders are cordially invited to attend the Annual Meeting to be held May 26, 2005, at 4:00 p.m. Calgary Petroleum Club Devonian Room 319 Fifth Avenue S. W. Calgary, Alberta LETTER TO SHAREHOLDERS CORE PRODUCING AREAS FINANCIAL HIGHLIGHTS ($ thousands except per share amounts and where stated otherwise) FINANCIAL Petroleum and natural gas sales, net of transportation costs Cash flow (1) From operations Per share - basic - diluted Earnings Net earnings (loss) Per share - basic - diluted Capital expenditures (2) Exploration and development Acquisitions, dispositions and other (3) Net capital expenditures Total assets Net debt (4) Shareholders’ equity Weighted average common shares outstanding (thousands) Common shares outstanding at year end (thousands) Common shares outstanding at March 8, 2005 (thousands) OPERATING Production Natural gas (MMcf/d) Crude oil and liquids (Bbl/d) Total production (Boe/d) @ 6:1 Average prices (5) Natural gas (pre-financial instruments) ($/Mcf) Natural gas ($/Mcf) (6) Crude oil and liquids (pre-financial instruments) ($/Bbl) Crude oil and liquids ($/Bbl) (6) Reserves (proved plus probable) Natural gas (Bcf) Crude oil and liquids (MBbl) Estimated present value before tax (discounted @ 10% using forecasted prices and costs) Proved ($ millions) Proved and probable ($ millions) Land (thousands of acres) Total net land holdings Net undeveloped land holdings Drilling activity (gross) Gas Oil Oilsands evaluation (7) D&A Total wells Success rate (7) Year Ended December 31 2004 2003 % Change 550,616 434,059 295,566 4.95 4.84 41,174 0.69 0.67 167,276 2.78 2.77 1,151 0.02 0.02 316,284 262,730 579,014 1,542,786 451,187 625,039 59,755 63,186 63,899 223,753 (368,731) (144,978) 1,177,130 297,055 496,033 60,098 60,095 173 7,297 36,150 6.72 6.86 46.80 44.13 568.6 20,461 1,156.0 1,659.3 4,082 3,442 229 12 17 13 271 95% 153 7,169 32,630 5.99 5.16 38.27 35.50 329.4 12,513 597.4 733.6 3,386 2,800 180 16 - 15 211 93% 27% 77% 78% 75% 3,477% 3,350% 3,250% 41% 171% 498% 31% 52% 26% (1)% 5% 13% 2% 11% 12% 33% 22% 24% 73% 64% 94% 126% 21% 23% 27% (25)% 100% (13)% 28% 2% (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 geo- physical 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) Excludes capital expenditures of discontinued operations and other minor accounting adjustments. (3) 2003 disposition proceeds include the $51 million related to Paramount Energy Trust units. (4) Net debt is equal to long-term debt including working capital, excluding discontinued operations. (5) Average prices are net of transportation costs. (6) Excludes non-cash gains and losses on financial instruments. (7) Success rate excludes oilsands evaluation wells. PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 1 2 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT LETTER TO SHAREHOLDERS LETTER to SHAREHOLDERS Paramount and its shareholders enjoyed an exceptional year in 2004 as the Company experienced one of the most active years in our 26 year history in virtually every aspect of our business. A review of the signiﬁcant events throughout the year will show that the Company’s exploration and development program was one of the largest ever undertaken by the Company. We also executed a series of signiﬁcant acquisitions which have added to the production base as well as the exploration and development inventory. Financing these activities was achieved through a combination of different debt and equity instruments which maximized Paramount’s return. Paramount is now poised on the brink of completing the spinout to its shareholders of its second distribution generating trust in as many years, (“Trilogy Energy Trust”), for the beneﬁts of its shareholders. We are executing the business plan we laid out and the results are providing shareholders with superior, if not extraordinary returns. The focus of Paramount’s activity is the exploration and development program which in 2004 totalled $316.3 million. The majority of the activities were spread amongst the ﬁve main operating units in Kaybob, Grande Prairie, Northwest Alberta/Cameron Hills, Northwest Territories, Northeast British Columbia/Liard, Northwest Territories, and Southern Alberta. Additional spending was directed to furthering the long-term projects Paramount is pursuing in the Colville Lake area in the northern part of the Northwest Territories, and in the Athabasca Oil Sands area of northeast Alberta. In Kaybob, Paramount started to see the results of years of work discovering, consolidating and developing the Lower Cretaceous Gething resource play. The initial program to downspace these gas pools, started in 2004, and the results of these inﬁll drilling programs into these Gething pools have been superior. Wells drilled into existing gas pools have for the most part found virgin, or near virgin, reservoir pressures conﬁrming Paramount’s vision that we would be ﬁnding new reserves and increasing substantially the recoveries of these pools. Paramount’s success rate for adding new producing gas wells was over 95 percent in 2004. It is this play type which will be the cornerstone of Trilogy Energy Trust. The extensive inventory of development opportunities is expected to provide stability and sustainability of reserves and production, and ultimately per unit distributions for the Trust. The extension of Paramount’s activities to the west of Kaybob into the Deep Basin play also occurred with material additions to the land and prospect inventory in 2004 in what is now referred to as the West Kaybob area. In the Grande Prairie Operating Unit, Paramount continued the development of our shallow Dunvegan discoveries at Mirage, extending this play substantially. As well, the tie in of the discovery at Marten Creek was completed in April, 2004 adding the ﬁrst production from this area to Paramount. The acquisition of assets in this area in July was complimentary to our original discovery and has established Marten Creek as an area of material value. This area in the Marten Creek asset will comprise close to 11 percent of the initial production base of Trilogy Energy Trust. The Northwest Alberta/Cameron Hills, Northwest Territories Operating Unit saw the follow-up development and tie in of the prior-year discovery at Haro, extending the pool boundary, increasing reserves and adding deliverability to the operating unit. Additional drilling and seismic activities in 2005 will build on this drilling success as well as further develop existing production in this area. In Northeast British Columbia/Liard, Northwest Territories, the acquisition of the majority of the working interest and assumption of operatorship at West Liard has made Paramount the dominant producer in the North. Paramount’s expertise is expected to provide the basis for leading development of the western Canadian Sedimentary Basin northward with Paramount realizing many of the opportunities in this new frontier. In the Southern Operating Unit, Paramount initiated and completed the ﬁrst delineation phase of the Coalbed Methane evaluation program. We drilled 20 wells for this resource at our Chain/Craigmyle property with results that have exceeded our expectations. Paramount is moving forward to fully develop Phase One of the Coalbed Methane program which includes up to an additional 88 wells and forecasts initial production of approximately 10 MMcf/d. PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 3 In the fall of 2004, Paramount released an update of the results of our exploration activities in the Colville Lake area of the Northwest Territories. Paramount’s two initial discovery wells at Nogha tested natural gas at rates of 3 to 5 MMcf/d and the pool has been independently estimated to contain some 250 Bcf of possible reserves. Paramount is continuing with exploration activities in 2005 at Nogha, Maunoir Ridge and a new prospect at Turton Lake. We are exploring our options for bringing this gas to market. In the Athabasca Oil Sands area, Paramount added a large amount of additional acreage and conducted a drilling program to reﬁne our understanding of the bitumen accumulations on our lands. This program has continued into the current year to the point where Paramount hopes to be in a position to select the location of the Company’s ﬁrst prototype plant for SAG-D development and to submit the application for this project. Acquisitions and divestitures played an important role in the growth of Paramount’s production base and added to future growth opportunities. The Kaybob acquisition added production, a large land base and seismic inventory which we believe will be instrumental in growing the remaining assets of the West Kaybob Operating Unit into a substantial entity of its own. Two separate transactions in the Liard area allowed Paramount to consolidate its interests in its current production as well as become the largest working interest owner and operator of the Liard Nahanni discovery from 2000. Finally, the Marten Creek acquisition added production to our original discovery which has grown the area to a signiﬁcant asset in itself. The acquisition also added some control to plant capacity and further drilling opportunities which will be pursued over the next several years. These combined activities of exploration, acquisitions and development provided Paramount with exceptional growth in both production and reserves. Paramount’s production in the fourth quarter of 2004 grew 43 percent when compared with the same period in the prior year. As well, Paramount replaced our 2004 production 4.6 times, and increased our overall reserves by 71 percent to 115 million barrels of oil equivalent for a cost of ﬁnding and development of $9.49 per barrel of oil equivalent. The net asset value of the Company, calculated using conservative estimates and historical costs, reﬂected these results with a 141 percent increase to $25.01 per share. To ﬁnance our capital spending program and acquisition activities, Paramount has been active on both debt and equity fronts. In late 2003, Paramount completed its ﬁrst debt issue raising US$175 million which gave us the ﬂexibility to initiate the inﬁll drilling program at Kaybob as well as repurchase approximately 1.6 million of common shares through our normal course issuer bid. A second debt issue was completed in June, 2004 raising US$ 125 million which was used to ﬁnance the acquisitions at Kaybob and Liard. Later in the year, Paramount completed an equity issue selling 4.5 million shares for gross proceeds of $116.5 million. Finally, the Company redeemed US$85.4 million of the Senior Notes debt under the equity claw provision of the debt indentures. Late in the year, after reviewing the options available to Paramount, the Directors of Paramount unanimously approved management’s recommendation to pursue the spinout of Trilogy Energy Trust. Upon completion of the Trust spinout, Paramount shareholders will own 100 percent of the post-reorganization Paramount and 81 percent of the outstanding units of Trilogy. Paramount will own the remaining 19 percent of the outstanding units of Trilogy. Shareholders will receive one trust unit for each existing common share. Based on the number of Paramount shares outstanding on February 25, 2005, there are expected to be approximately 63.9 million common shares of Paramount and 78.9 million units of Trilogy outstanding upon completion of the Trust spinout. Trilogy will indirectly own certain of Paramount’s existing assets with current production of approximately 25,000 Boe/d (80 percent natural gas). These assets, in the Kaybob and Marten Creek areas of Alberta, are primarily low-risk, high working interest, lower decline properties that are geographically concentrated with numerous inﬁll drilling opportunities and good access to infrastructure and processing facilities to be operated and controlled by Trilogy. The balance of Paramount’s assets, consisting of its predominantly growth-oriented assets, will remain with Paramount. Current production from these assets is approximately 20,000 Boe/d (75 percent natural gas). Through Paramount, shareholders will participate in the potential upside of its remaining predominantly growth-oriented assets. Through 4 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT LETTER TO SHAREHOLDERS Trilogy, unitholders will receive regular distributions of cash derived from the cash ﬂow produced by Trilogy’s low- risk development assets. The ﬁrst cash distribution of the Trust, expected to be $0.16 per Trust Unit, is expected to be paid on May 15, 2005 to unitholders of record on May 2, 2005. Due to Trilogy’s extensive development drilling portfolio, it is anticipated that Trilogy will retain approximately 35 percent of its cash ﬂow for capital expenditures with the remaining 65 percent of its cash ﬂow being distributed to unitholders in monthly distributions. This extensive development drilling portfolio is expected to make Trilogy less reliant on the competitive acquisition market for developed assets in order to maintain and grow distributions. If the necessary securityholder and court approvals are obtained and other conditions are satisﬁed, the Trust spinout is expected to be completed on or about April 1, 2005. Looking forward to 2005, we are striving for similar success to that which we enjoyed this past year. We continue to follow the business plan which we have developed, combining short-term growth from a lower risk prospect inventory and longer term larger developments which we expect to translate into material value for shareholders in the future. The current commodity environment for energy is very good and has easily kept pace with the increased costs in the business. Paramount has budgeted a total of $340 million for capital expenditures for 2005; of this, $100 million is to be directed to the Trilogy assets and the remaining $240 million will be directed to the properties retained by Paramount Resources Ltd. Trilogy’s capital program is intended to entirely replace production and reserves. Paramount’s capital program is designed to grow production to 25,000 Boe/d by the end of the year. Total cash ﬂow in 2005 of the combined entities is estimated to be approximately $425 million or approximately $6.66 per share. signed Jim Riddell President and Chief Operating Ofﬁcer March 24, 2005 PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 5 �� 6 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT �� CORE PRODUCING AREAS CORE PRODUCING AREAS KAYBOB The levels of drilling and completion activity continued to increase in the Kaybob area throughout the year. At its peak during the fourth quarter, ﬁve drilling rigs and eight service rigs were active. Paramount participated in 26 (16.9 net) wells in the fourth quarter bringing the 2004 total to 75 (52.2 net) wells for the year, resulting in 66 (45.7 net) gas wells, 7 (6.2 net) oil wells and 2 (0.3 net) dry holes. Capital expenditures in the Kaybob Operating Unit, including facility additions and optimization projects, were $111 million, up from $68 million in 2003. An additional $18.1 million was spent acquiring Crown lands in 2004, adding additional opportunities to Paramount’s prospect inventory. On June 30, 2004, Paramount completed the acquisition of additional interests in the Kaybob area. This acquisition initially added 6,600 Boe/d of production and a large undeveloped land base principally in the Deep Basin area west of the Kaybob core production area. These undeveloped lands are complementary to Paramount’s own land assets resulting in a large prospect inventory for future drilling. As well, a signiﬁcant amount of seismic data was included in the transaction providing Paramount with a competitive advantage for evaluating drilling prospects, Crown land sales and farm-in opportunities. Gas production in the Kaybob Operating Unit averaged 96 MMcf/d in 2004, up 20 percent from the 2003 average of 80 MMcf/d. Oil and natural gas liquids production was 4,091 Bbl/d for 2004, up 67 percent from the 2003 average of 2,451 Bbl/d. Kaybob production averaged 15,704 Boe/d in 2003 and grew to 20,157 Boe/d in 2004. In spite of average production declines of approximately 24 percent, we were able to increase production through our capital spending program, as well as through the acquisition. The properties acquired in the transaction averaged 6,130 Boe/d for the second half of 2004. Kaybob production for December 2004 averaged 108 MMcf/d and 5,600 Bbl/d of oil and natural gas liquids (23,600 Boe/d). Operating costs in the Kaybob area increased from a 2003 average of $6.05/Bbl to $6.96/Bbl. This increase in operating costs is due in part to higher per unit costs of the acquired properties. In addition, we performed a number of workovers on the acquired properties in the fourth quarter of 2004 and further workovers are planned in 2005. It is anticipated that the operating costs will be reduced to approximately $6.50/Bbl in 2005. Proved plus probable reserve additions in the Kaybob Operating Unit were 51.5 Bcf and 1.25 MMBbl (9.8 MMBoe) which replaces 2004 production of 35.3 Bcf and 1.5 MMBbl (7.38 MMBoe). Costs of ﬁnding and development, including future capital, for the proved plus probable reserve additions for the Kaybob area were $6.37/Boe in 2004 which is down from $9.66/Boe in 2003. The proposed reorganization involves spinning off a portion of the Kaybob Operating Unit assets into Trilogy Energy Trust. These assets will be combined with the Marten Creek assets from the Grande Prairie Operating Unit to form the basis of Trilogy Energy Trust. The Paramount-operated producing assets and lands that will be moved from the Kaybob Operating Unit to Trilogy are characterized by concentrated, high working interest, liquids-rich gas. The lands are in an area that can be characterized by multi-zone potential and a combination of conventional oil and gas and tight gas reservoirs. Paramount feels that a large portion of these lands can be further developed by drilling additional wells into these known tight gas reservoirs. Paramount believes that it can continue to develop these reserves using the expertise that it has gained over the past ten years in this area, and maintain both reserves and production rates for a number of years with the existing prospect inventory. GRANDE PRAIRIE The Grande Prairie Operating Unit grew signiﬁcantly in 2004. The Company drilled 57 (46.4 net) wells compared to 45 (29.9 net) wells drilled in 2003. Of the total wells drilled in 2004, 21.4 net wells have been tied in and are presently producing and 9.4 net gas wells have been tested and are currently waiting to be tied in. Capital expenditures totaled $58 million in 2004 as compared to $41 million in 2003. Gas production in 2004 increased 125 percent to average 27 MMcf/d as compared to 12 MMcf/d in 2003. The increase was the result of the Marten Creek acquisition in August 2004 which added approximately 12 MMcf/d of natural gas production and the signiﬁcant gas production growth in the Mirage area. Oil and natural gas liquids production decreased 67 percent to average 585 Bbl/d in 2004 as compared to 1,767 Bbl/d in 2003 as a result of the Sturgeon PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 7 Lake property disposition in October of 2003. The 2004 year-end production exit rate was 40 MMcf/d of natural gas and 400 Bbl/d of oil and natural gas liquids. The 2004 production rates were lower than expected primarily due to third-party infrastructure limitations and wet weather delaying operations. The delays postponed the addition of approximately 5 to 6 MMcf/d of natural gas production in the ﬁrst quarter of 2005. In 2004, Marten Creek was the most signiﬁcant growth area in the Grande Prairie Operating Unit. The ﬁrst seven wells of this new area were brought on production in March 2004 with initial rates of 5 MMcf/d. A facility expansion was completed in November 2004 to mitigate third-party facility limitations resulting in an increase in production to over 10 MMcf/d by year end. The acquisition in August added production resulting in a ﬁeld exit rate that was over 20 MMcf/d. Paramount is planning to drill up to 12 wells in 2005, add a ﬁeld compressor, expand the gathering system and add two water disposal wells to increase production. The Marten Creek project area will also be one of the initial properties to comprise the assets of Trilogy Energy Trust. The Mirage area was Grande Prairie’s most active area with 28 (25.1 net) wells drilled in 2004, two compressors installed and 44 sections of gross land added. Proved plus probable reserve additions at Mirage for 2004 were 4 Bcf. Mirage’s 2004 exit production rate was 14 MMcf/d of natural gas and 250 Bbl/d of oil and natural gas liquids. The drilling operations in 2004 were delayed two to four months by wet weather, which also delayed a third-party gathering system expansion. The current standing wells are expected to be tied in by the end of the ﬁrst quarter of 2005 and will initially produce approximately 6 MMcf/d. The growth in this ﬁeld has been the result of the ongoing development of the shallow Dunvegan formation, as well as the success in new, slightly deeper formations. NORTHWEST ALBERTA / CAMERON HILLS, NORTHWEST TERRITORIES During the year, Paramount participated in the drilling of 22 (14.5 net) wells of which only 1 (0.5 net) well was dry and abandoned. Due to restricted seasonal access, the vast majority of ﬁeld activities related to seismic acquisition, drilling, and construction were performed in the ﬁrst quarter. Capital expenditures for the year totaled $32.6 million which was evenly split between drilling and facility expenditures. For 2004, natural gas production averaged 20 MMcf/d of gas and 797 Bbl/d of oil and natural gas liquids, compared to 22 MMcf/d of natural gas and 448 Bbl/d of oil and NGLs in 2003. Signiﬁcant production increases were realized in the Haro area with the drilling of 12 gas wells (7.5 net), and the completion of the expansion in June of the existing natural gas production capacity from 1.4 MMcf/d to 5.9 MMcf/d. This increase was offset by declines at Cameron Hills and Bistcho. The planned focus of activity in Northwest Alberta in 2005 will be in the Bistcho-Zama-Larne area with potential participation in the drilling of 19 gross (9.5 net), operated and non-operated gas wells. In the Haro area, 6 (4 net) gas wells are expected to be drilled. The Company also plans to conduct two seismic programs on new lands acquired in 2004. Activity in Cameron Hills, Northwest Territories, will be limited as regulatory approvals for new drilling has not been received. NORTHWEST TERRITORIES / NORTHEAST BRITISH COLUMBIA Production from this operating area increased from 12 MMcf/d in 2003 to 16 MMcf/d in 2004. The increase was a result of both drilling activity and the acquisition of additional working interests in three of the four producing properties. A total of 18 (9.4 net) wells were drilled during 2004, and two separate property transactions were closed during the year. Development activity was focused on the West Liard ﬁeld with the drilling of 3K-29 and 2M-25 along with a workover on the shut-in well at M-25. Both 2M-25 and M-25 were brought on production during the fourth quarter. Paramount’s working interest in this ﬁeld increased from 3 percent to 67 percent as a result of the 2004 acquisitions. Also included in the asset acquisitions was the remaining 50 percent interest in the Tattoo and Maxhamish production facilities. Exploratory drilling continued at Colville Lake, Northwest Territories, where three wells were drilled with encouraging results. Two of these wells at K-14 and C-34 tested potential new pools while the third well at B-23 was 8 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT CORE PRODUCING AREAS drilled to delineate the Nogha discovery. Paramount will continue its exploration efforts in the Colville Lake area with the drilling of ﬁve wells this winter and further completion and testing of existing wells. Delineation and tie in of new discoveries in Northeast British Columbia should add between 2-5 MMcf/d in the ﬁrst quarter of 2005. Six wells were also drilled on various exploratory prospects in Northeast British Columbia with two of these encountering potential new pools that require further delineation, while a third discovery is slated to be on production in 2005. The upcoming winter program will include drilling and workover activity to maximize value from the higher working interests in the existing production facilities. SOUTHERN The Southern Operating Unit encompasses three different regulatory jurisdictions, southern Alberta, northern Montana and the southwest of North Dakota. The Company drilled 82 (40.8 net) wells in 2004 as compared to 20 (14.6 net) wells in 2003. The average production for the year was 11 MMcf/d of gas, with 1,798 Bbl/d of oil and natural gas liquids as compared to 10 MMcf/d of gas and 2,457 Bbl/d of oil and natural gas liquids in 2003. In the fourth quarter of 2004, the Southern Operating Unit produced 11 MMcf/d of gas, and 1,600 Bbl/d of oil and natural gas liquids. This was the most active quarter with 52 (21.8 net) wells drilled. Most of the activity was in the Chain region where 18 (14.6 net) Coalbed Methane (“CBM”) wells and 5 (4.0 net) Belly River wells were drilled. In the third quarter of 2004, Paramount divested all its operated properties in southeast Saskatchewan (for a gain of $14 million) to further focus the operations in the Southern Operating Unit core areas. The primary core areas of production are the gas-producing Chain/Craigmyle ﬁeld and the oil-producing area of the Williston Basin in the United States. The Chain region has seen a revival over the last two years and has doubled production from 3 MMcf/d to 6.2 MMcf/d. The 18 CBM wells were all successful and will form the base for a multi-year development program of the Horseshoe Canyon CBM play. These wells are drilled to a depth of 350 meters and produce natural gas at average rates of over 100 Mcf/d with no associated water production. The continuing Belly River drilling program has been very successful and has enabled existing infrastructure to operate at capacity. A re-evaluation of our facilities has shown the need for a new parallel low pressure production system on which we will start construction in the second quarter of 2005. The Chain region will be the focus of most of our activity in 2005 with 98 wells planned which consist of 88 CBM wells, eight wells for Belly River targets and two for Mannville targets. The North Dakota area is presently producing 564 Boe/d and will be the second area of focus for the Southern Operating Unit. Paramount will be drilling six wells for deep oil in the Knutson and Beavercreek Fields. HEAVY OIL During 2004 Paramount Resources increased its oil sands acreage by 70 percent with the acquisition of 51,000 acres of oil sands rights for a total cost of $2.7 million. The Company’s total oil sands acreage is approximately 120,000 acres and is located mainly in the Leismer and Surmont areas of northeast Alberta. During 2004 Paramount drilled 17 Oil Sands Evaluation (OSE) wells. The encouraging results of these wells are being followed-up with a 15 to 20 well OSE program in early 2005. The Company is optimistic that the results of the oil sands evaluation program will allow it to bring forward a 3,000 Bbl/d SAGD pilot application in 2005. GAS RE-INJECTION AND PRODUCTION EXPERIMENT Paramount made a signiﬁcant step towards a technical solution to the Gas over Bitumen issue with the approval of the Gas Re-Injection and Production Experiment to be conducted in the Surmont area of northeast Alberta. This pilot project involves the collection and re-injection of up to 3 MMcf/d of compressor exhaust gases, maintaining pressure, allowing a similar volume of natural gas production from previously shut-in gas pools. The experiment also enables the sequestration of up to 400 Mcf/d of carbon dioxide. This experimental pilot project is expected to start up in the second quarter of 2005. If successful, Paramount is hopeful that this experiment will offer some resolution at Surmont to the Gas over Bitumen issue as well as provide for sequestration opportunities for carbon dioxide. PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 9 10 PARAMOUNT RESOURCES LTD. 20 0 4 ANNUA L RE P ORT REVIEW OF OPERATIONS REVIEW of OPERATIONS PRODUCTION Paramount’s production proﬁle continued to be signiﬁcantly weighted to natural gas. Natural gas production made up 80 percent of the Company’s total production in 2004 compared to 78 percent in 2003. Paramount’s production for the year ended December 31, 2004 was 36,150 Boe/d, up 11 percent from 32,630 Boe/d in 2003. Natural gas production increased 13 percent from 152.8 MMcf/d in 2003 to 173.1 MMcf/d in 2004. Crude oil and natural gas liquids production increased 2 percent from 7,169 Bbl/d in 2003 to 7,297 Bbl/d in 2004. This increase in production is attributable to the 2004 acquisitions in the Kaybob, Fort Liard and Marten Creek areas and a successful capital program. The following table summarizes the average daily production per core area. Natural Gas Production (MMcf/d) East Kaybob Marten Creek Total Trust Properties West Kaybob Grande Prairie (excluding Marten Creek) Northwest Alberta / Cameron Hills, Northwest Territories Northwest Territories / Northeast British Columbia Southern Other Total Paramount (excluding Trust Properties) Total Paramount Crude Oil & NGL Production (Bbl/d) East Kaybob Marten Creek Total Trust Properties West Kaybob Grande Prairie (excluding Marten Creek) Northwest Alberta / Cameron Hills, Northwest Territories Northwest Territories / Northeast British Columbia Southern Other Total Paramount (excluding Trust Properties) Total Paramount Total Production (Boe/d) East Kaybob Marten Creek Total Trust Properties West Kaybob Grande Prairie (excluding Marten Creek) Northwest Alberta / Cameron Hills, Northwest Territories Northwest Territories / Northeast British Columbia Southern Other Total Paramount (excluding Trust Properties) Total Paramount 2004 89.7 8.6 98.3 6.7 18.2 20.2 16.2 10.8 2.7 74.8 173.1 3,874 - 3,874 217 585 797 12 1,798 14 3,423 7,297 18,817 1,432 20,249 1,340 3,621 4,165 2,710 3,596 469 15,901 36,150 2003 77.6 - 77.6 1.9 12.4 22.3 11.6 9.5 17.5 75.2 152.8 2,184 - 2,184 267 1,767 448 9 2,457 37 4,985 7,169 15,112 - 15,112 592 3,831 4,165 1,942 4,048 2,940 17,518 32,630 NATURAL GAS SALES (MMcf/d) 173 250 200 150 100 50 00 01 02 03 04 CRUDE OIL and LIQUIDS SALES (Bbl/d) 7,297 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 00 01 02 03 04 PRODUCTION (Boe/d @ 6:1) 50,000 40,000 30,000 20,000 10,000 36,150 00 01 02 03 04 PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 11 PROFITABILITY Paramount continues to focus its efforts on the control of factors directly related to proﬁtability. Production volumes, operating costs, general and administrative costs, and capital spending are all factors that are within our control and remain closely monitored. The mandate of every employee is to turn ideas into value. This strategy has resulted in a history of increased shareholder value. COMMODITY PRICES Stronger natural gas demand resulted in an increase of 12 percent in Paramount’s average natural gas sales price before ﬁnancial instruments to $6.72/Mcf as compared to $5.99/Mcf in 2003. Natural gas prices after ﬁnancial instruments in 2004 increased 33 percent to $6.86/Mcf from $5.16/Mcf in 2003. In 2004, Paramount recorded a $18.7 million gain on ﬁnancial instruments as compared to a loss of $53.2 million in 2003. The 2003 ﬁnancial instruments were initiated in order to reduce cash ﬂow risk with respect to the Summit acquisition as the bridge loan used to ﬁnance the acquisition was extended due to unexpected delays in closing the Paramount Energy Trust disposition. Oil and natural gas liquids (“NGL”) prices before ﬁnancial instruments increased 22 percent to average $46.80/Bbl in 2004, as compared to $38.27/Bbl in 2003. OPERATING COSTS Paramount’s total operating costs increased 18 percent to $95.8 million in 2004 as compared to $81.2 million in 2003. Costs on a unit-of-production basis increased 6 percent to $7.24/Boe from $6.82/Boe in 2003. The industry in general experienced increases in the costs of goods and services particularly higher labour and energy costs. In addition, properties acquired by the Company during the year have higher per unit operating costs than existing Paramount properties. Paramount constructs and operates plant facilities and gathering systems as a corporate strategy in order to control the ﬂow of its natural gas to market. These facilities incur ﬁxed costs, which are in addition to the costs incurred at the well level, thereby increasing total operating expenses and the relative magnitude of the per unit costs. ROYALTIES For 2004, net royalties increased to $105.0 million from $82.5 million in 2003 due to higher production and commodity prices. As a percentage of revenue, Paramount’s corporate royalty rate is substantially unchanged from the prior year, at 19.1 percent compared to 19.0 percent in 2003. GENERAL AND ADMINISTRATIVE COSTS General and administrative expenses, net of operating recoveries, increased to $25.2 million in 2004 as compared to $19.1 million in 2003. Paramount has increased its head-ofﬁce stafﬁng levels to enable the Company to identify and develop new core areas and build its production portfolio. This initiative has resulted in Paramount advancing its long-term projects such as Colville Lake, Northeast Alberta bitumen and Coalbed Methane, and developing 8.00 7.00 6.00 5.00 4.00 3.00 2.00 1.00 6.86 NATURAL GAS PRICE (after realized financial instruments) ($/Mcf) 50.00 40.00 30.00 20.00 10.00 44.13 CRUDE OIL and LIQUIDS PRICE (after realized financial instruments) ($/Bbl) 50.00 40.00 30.00 20.00 10.00 41.61 GROSS REVENUE (before financial instruments) ($/Boe) 00 01 02 03 04 00 01 02 03 04 00 01 02 03 04 12 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT REVIEW OF OPERATIONS successful new ﬁelds in existing core areas within Grande Prairie and Northwest Alberta. The Company has also increased administrative staff levels to ensure compliance with new corporate and reporting obligations in Canada and the United States; certain of these are a result of the US debt offerings closed in 2004. Paramount does not capitalize any general and administrative expenses with the exception of overhead recoveries. CASH FLOW AND EARNINGS Paramount’s cash ﬂow from operations increased 77 percent to $295.6 million in 2004 from $167.3 million in 2003. The increase in cash ﬂow was a result of a reduction in realized ﬁnancial instrument losses in 2004 as compared to 2003, and an increase in revenues due to higher commodity prices and production. Net earnings totaled $41.2 million as compared to net earnings of $1.2 million in 2003. The higher earnings in 2004 are primarily due to an increase in petroleum and natural gas sales resulting from higher production and commodity prices, ﬁnancial instrument gains as opposed to 2003 losses, and unrealized foreign exchange gains on US debt. This was partially offset by higher non-cash stock based compensation expense, depletion and depreciation expense, and future income tax expense. Cash Flow Reconciliation Volume (Boe) (1) Petroleum & natural gas revenue, net of transportation Gain (loss) on sale of investments Royalties (net of ARTC) Operating costs Operating netback Realized financial instruments Interest on long-term debt (excluding non-cash interest) General and administrative Bad debt recovery (expense) Lease rentals Current and Large Corporations Tax Cash flow from continuing operations Cash flow from discontinued operations Cash flow from operations Weighted average shares (millions) Cash flow per basic share ($/share) (1) Barrels of oil equivalent calculated on the basis of 1 barrel = 6 Mcf. ($ million) 550.6 - (105.1) (95.8) 349.7 (0.7) (24.1) (25.2) 5.5 (3.5) (6.8) 294.9 0.7 295.6 59.8 4.95 2004 2003 ($ million) 434.1 (1.0) (82.5) (81.2) 269.4 (53.2) (19.0) (19.1) (6.0) (3.6) (2.7) 165.8 1.5 167.3 $/Boe 36.45 (0.09) (6.93) (6.82) 22.61 (4.47) (1.60) (1.60) (0.50) (0.30) (0.23) 13.91 0.13 14.04 $/Boe 41.61 - (7.94) (7.24) 26.43 (0.05) (1.82) (1.91) 0.42 (0.27) (0.51) 22.29 0.05 22.34 60.1 2.78 26.43 OPERATING NETBACK ($/Boe) 30.00 25.00 20.00 15.00 10.00 5.00 6.00 5.00 4.00 3.00 2.00 1.00 4.95 CASH FLOW PER SHARE ($/share, basic) 2.00 1.50 1.00 0.50 EARNINGS PER SHARE ($/share, basic) 0.69 00 01 02 03 04 00 01 02 03 04 00 01 02 03 04 PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 13 NET CAPITAL EXPENDITURES During 2004, expenditures for exploration and development activities totaled $316.3 million as compared to $223.8 million in 2003. The increase in the capital expenditures program in 2004 resulted in a total of 271 gross (180 net) wells were drilled during the year, compared to 211 gross (139 net) wells in 2003. Net capital expenditures totaled of $579.0 million in 2004 as compared to a recovery of $145 million in 2003. The Company acquired a number of properties totaling $322.6 million in 2004 offset by the disposition of certain non-core properties. Capital Expenditures ($millions) Land Geological and geophysical Drilling Production equipment and facilities Exploration and development expenditures Property acquisitions Proceeds received on property dispositions Other Net capital expenditures 2004 37.9 8.7 184.5 85.2 316.3 322.6 (61.8) 1.9 579.0 $ $ 2003 22.3 8.4 123.5 69.6 223.8 0.9 (371.6) 1.9 (145.0) $ $ LAND The Company’s net land holdings increased 20 percent to 4,082 thousand acres from 3,386 thousand acres in 2003. Net undeveloped lands increased 23 percent to 3,442 thousand acres from 2,800 thousand acres in 2003. Paramount’s undeveloped land inventory was increased partially as a result of acquisition and as a result of $37.9 million spent at Crown land sales. The following table summarizes the Company’s acreage position at December 31, 2004: Land (thousand acres) Land assigned reserves Undeveloped land Total Fair market value of undeveloped land ($millions) Gross 1,098 5,536 6,634 $ 185.4 2004 Net 640 3,442 4,082 Average Working Interest 58% 62% 62% Gross 981 4,756 5,737 $ 98.20 2003 Net 586 2,800 3,386 Average Working Interest 60% 59% 350 300 250 200 150 100 50 316.3 37.9 EXPLORATION and DEVELOPMENT EXPENDITURES ($ millions) 85.2 184.5 8.7 2004 EXPLORATION and DEVELOPMENT EXPENDITURES ($ millions) 00 01 02 03 04 Drilling and completion Geological & geophysical Plant gathering equipment Land purchases 14 PARAMOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT REVIEW OF OPERATIONS DRILLING Paramount participated in the drilling of 271 (180.3 net) wells in 2004 with a success rate of 96 percent. A total of 229 (145.6 net) gas wells, 12 (9.5 net) oil wells, 17 (17.0 net) heavy oil wells and 13 (8.2 net) dry and abandoned wells were drilled. The highest number of net drills was in the Kaybob Operating Unit, 75 (52.2 net ) wells drilled. Grande Prairie Drilled 57 (46.4 net) wells, Northwest Alberta drilled 22, (14.5 Net) wells, Liard drilled 18 (9.4 net) wells and Southern Alberta drilled 82 (40.8 net) wells. The Company also drilled 17 (17.0 net) heavy oil evaluation wells in northeast Alberta. The following table summarizes the Company’s 2004 drilling results: Gas Oil D&A Heavy Oil Total Total All Wells Success 2004 2003 Development Exploration Development Exploration Gross 164 11 9 17 201 271 Net 102.8 8.6 4.9 17.0 133.3 180.3 Gross 65 1 4 - 70 95% Net 42.8 0.9 3.3 - 47.0 Gross 135 13 7 Net 90.0 10.4 3.5 Gross 45 3 8 Net 30.7 2.1 2.2 155 211 103.9 138.9 93% 56 35.0 RESERVES AND RESERVES REPLACEMENTS Paramount’s reserves for the year ended December 31, 2004, were evaluated by McDaniel and Associates Consultants Ltd. (“McDaniel”) and by Paddock Lindstrom and Associates Ltd. (“Paddock Lindstrom”). Paramount’s reserves have been calculated in compliance with the national Instrument 51-101. Natural gas reserves for the year ended 2004 were 568.6 Bcf as compared to 329.4 Bcf for the year ended 2003. This represents a 73 percent increase in natural gas reserves. The crude oil and natural gas liquids reserves for the year ended 2004 were 20,461 MBbl, a 64 percent increase over the year end 2003 reported 12,513 MBbl. Crude oil reserves increased from 8,106 MBbl to 12,031 MBbl while natural gas liquids reserves increased from 4,407 MBbl to 8,430 MBbl. DRILLING DISTRIBUTION 17 75 82 18 22 57 Kaybob Grande Prairie Northwest Alberta Liard Southern Alberta Heavy Oil 271 WELLS DRILLED (gross) 300 250 200 150 100 50 95 DRILLING SUCCESS RATE (%) 100 80 60 40 20 00 01 02 03 04 00 01 02 03 04 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 15 The following table summarizes the reserves evaluated as at December 31, 2004, using McDaniel’s and Paddock’s forecast prices and cost cases: Gross Proved and Probable Reserves Before Tax Net Present Value ($millions) Reserve Category Canada Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable Canada United States Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable US Total Proved Total Probable Total Reserves (Columns may not add due to rounding) Light and medium Natural Gas Liquids (MBbl) Crude Oil (MBbl) Natural Gas (Bcf) Boe (MBoe) Discount Rate 5% 0% 10% 254.5 52.4 39.9 346.9 221.3 568.2 0.4 - - 0.4 - 0.4 347.2 221.4 568.6 5,615 667 308 6,590 2,901 9,492 2,108 - - 2,108 431 2,539 8,698 3,332 12,031 5,552 501 289 6,342 2,087 8,430 - - - - - - 6,342 2,087 8,430 53,592 9,898 7,251 70,741 41,882 112,622 2,169 - - 2,169 437 2,606 72,910 42,319 115,230 1,266.6 205.7 142.8 1,615.2 950.6 2,565.8 1,063.9 166.1 91.2 1,321.2 663.5 1,984.7 929.5 140.8 64.0 1,134.3 500.7 1,635.0 29.8 (0.4) - 29.5 6.0 35.5 1,644.7 956.6 2,601.3 25.3 (0.3) - 25.0 3.9 28.8 1,346.2 667.4 2,013.6 21.9 (0.3) - 21.6 2.7 24.3 1,156.0 503.4 1,659.3 RESERVE RECONCILIATION FOR YEAR-END 2004 Total proved reserves at year end 2004 were approximately 347 Bcf and 15.0 MMBbl or 73 MMBoe and proved plus probable reserves were 569 Bcf and 20.5 MMBbl or 115.2 MMBoe. On a barrel equivalent basis, reserves increased approximately 71 percent or 48 MMBoe over year end 2003. This growth in reserves replaces 2004 production of 13 MBoe by over four times. 800 700 600 500 400 300 200 100 568.6 NATURAL GAS RESERVES PROVED and PROBABLE (gross before royalties) (Bcf) 25,000 20,000 15,000 10,000 5,000 20,461 CRUDE OIL and NGL RESERVES PROVED and PROBABLE (gross before royalties) (MBbl) 150,000 120,000 90,000 60,000 30,000 115,230 RESERVES (MBoe) 00 01 02 03 04 00 01 02 03 04 00 01 02 03 04 16 PARAMOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT REVIEW OF OPERATIONS The Company’s new reserves and extensions to existing proved plus probable reserves totaled 27.9 MMBoe, acquisitions increased reserves by 26.1 MMBoe. Further development and additional production information enabled positive reserve revisions of 8.4 MMBoe. The Company’s divestitures of certain non-core properties accounted for 1.2 MMBoe. The following table sets forth the reconciliation of Paramount’s gross reserves for the year ended December 31, 2004, as evaluated by McDaniel and Paddock Lindstrom using forecast prices and costs. Gross reserves include working interest reserves before royalties. Reserves (Company share before royalty) Gas Bcf Total Reserves Jan 1, 2004 241.7 Total 2004 Divestments(1) (0.2) Total 2004 acquisitions(1) 63.1 2004 Capital Program 83.3 Additions(1) (63.4) Total 2004 Production Technical Revisions(1) 22.6 Total Reserves Jan. 1, 2005 347.2 Proved Reserves Oil & Boe NGL MBbl MBoe 50,900 10,617 (1,042) (1,021) 15,951 5,426 Probable Reserves Oil & Boe NGL MBbl MBoe 16,513 1,896 (176) (176) 10,108 1,505 Gas Bcf 87.7 - 51.6 Proved + Probable Reserves Oil & Boe NGL MBbl MBoe 67,413 (1,224) 26,059 Gas Bcf 329.4 (0.2) 114.8 12,513 (1,196) 6,931 1,624 (2,671) 1,066 15,041 15,510 (13,231) 4,830 72,910 64.9 - 17.2 221.4 1,532 - 662 5,420 12,346 - 3,525 42,319 148.2 (63.4) 39.8 568.6 3,156 (2,671) 1,727 27,856 (13,231) 8,355 20,460 115,230 (Columns may not add due to rounding) (1) Paramount estimates. FINDING AND DEVELOPMENT COSTS Paramount has calculated the capital associated with the 2004 reserve additions and as such has excluded certain capital expenditures. The calculation excluded the $37.6 million of expenditures from the ﬁnding and development cost calculation associated with the exploration at Colville Lake and the Bitumen evaluation. This capital will be included in the ﬁnding and development calculation during the year in which reserves are ﬁrst booked for Colville Lake and Bitumen by the company. In addition, capital was reduced by $45.1 million to reﬂect the net increase in the value of our undeveloped acreage inventory. Future capital of $36.2 million to fully develop the booked proved reserves, and $103.2 million to fully develop the proved and probable reserves were included in the ﬁnding and development calculation. Paramount’s ﬁnding and development costs for new reserves additions were calculated to be $13.57/Boe for proved reserves and $9.48/Boe for proved plus probable reserves. Finding and Development Capital 2004 Working Interest Capital Expenditures ($ millions) Land Seismic Exploration and development Facilities Total net capital expenditures Less increase in value of undeveloped land Less 2004 Colville expenditures Less 2004 Bitumen evaluation expenditures 2004 F&D net capital expenditures 2004 Capital 38.0 8.9 184.5 91.4 322.8 (45.1) (29.3) (8.3) 240.1 Future Capital New Additions Total F&D Capital Proved - - 20.2 16.0 36.2 - - - 36.2 Proved Plus Probable - - 77.3 25.9 103.2 - - - 103.2 Proved 38.0 8.9 204.7 107.4 359.0 (45.1) (29.3) (8.3) 276.3 Proved Plus Probable 38.0 8.9 261.8 117.3 426.0 (45.1) (29.3) (8.3) 343.3 PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 17 Proved Capital ($MM) Proved Reserves (MBoe) Proved Plus Proved Plus Proved Plus Probable F&D ($/Boe) Probable Reserves (MBoe) Probable Capital ($MM) Proved F&D ($/Boe) Finding and Development Costs Extensions and discoveries (including technical revisions) 276.3 20,360 13.57 343.3 36,231 9.48 ACQUISITION AND DIVESTMENT ACTIVITIES (“A&D”) In 2004, Paramount acquired properties in Alberta and the Northwest Territories with 15,951 MBoe of proved reserves, or 26,059 MBoe proved plus probable reserves as well as undeveloped land valued at $35.0 million, at a total cost of $322.6 million. Paramount also divested of non-core properties in Alberta and Saskatchewan with reserves of 1,042 MBoe proved, or 1,224 MBoe proved plus probable reserves as well as undeveloped land valued at $1.0 million, for total divestment proceeds of $52.1 million. In aggregate, Paramount increased total proved reserves by 14,909 MBoe for a net unit cost of $15.86/Boe, and increased proved plus probable reserves by 24,835 MBoe for a net unit cost of $9.52/Boe through acquisition and divestment activity. 2004 Working Interest Capital Expenditures ($ millions) Capital Expenditures for Acquisitions Fair Market Value of Undeveloped Land Acquired Proceeds of Dispositions of P&NG assets Fair Market Value of Undeveloped Land Divested Net A&D Capital for Reserves 322.6 (35.0) (52.1) 1.0 236.5 Net 2004 A&D Expenditures Less: Net Value of A&D Undeveloped Land 2004 Net A&D Cost of Reserves Proved Capital ($MM) 270.5 34.0 236.5 Proved Reserves (MBoe) Proved Plus Proved Plus Proved Plus Probable A&D ($/Boe) Probable Reserves (MBoe) Proved A&D ($/Boe) Probable Capital ($MM) 270.5 14,909 15.86 34.0 236.5 24,835 9.52 TOTAL RESERVE GROWTH COST (F&D Cost plus Acquisitions and Divestments) Paramount’s 2004 F&D related activities, when combined with its acquisition and divestment program resulted in total reserve growth of 35,269 MBoe total proved reserves ($14.53/Boe unit cost) and 61,066 MBoe of proved plus probable reserves ($9.49/Boe unit cost). Total Reserve Growth (F&D + A&D) 512.8 35,269 14.53 579.8 61,066 9.49 18 PARAMOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT REVIEW OF OPERATIONS NET ASSET VALUE The net asset value of Paramount at year end has increased 141 percent from $10.38 in 2003 to $25.01 in 2004. One of the main components of the increase was the 126 percent increase in value of reserves and the 89 percent increase in the appraised value of undeveloped land. The following table summarizes the Company’s net asset value: Net Asset Value ($ millions of dollars as at December 31, 2004) Present value of appraised reserves (1) Value of short-term investments Appraised value of undeveloped land Seismic (at cost) Projects under evaluation (at cost) Building (at cost) Other Total assets Bank loans Senior notes Working capital deficiency (2) Drilling rig indebtedness Mortgage Total liabilities Net asset value Net asset value per basic common share (3) 2004 1,659.3 27.1 185.4 55.4 117.8 - 11.3 2,056.3 201.3 257.8 17.0 - - 476.1 1,580.2 25.01 $ $ $ $ $ $ 2003 733.6 17.3 98.2 37.6 42.1 8.5 10.6 947.9 60.4 226.9 25.7 4.6 6.7 324.3 623.6 10.38 (1) Proved plus probable reserves discounted at 10 percent before income tax used for 2004. (2) Excludes short-term investments. (3) Outstanding shares: 2004 – 63,185,600 (2003: 60,094,600). NOTES TO NET ASSET VALUE i) Reserve values were determined by McDaniel and Paddock Lindstrom as at December 31, 2004, using their forecast prices and costs cases. ii) No value has been assigned to tangible assets other than those associated with proved producing reserves. iii) Paramount’s hedging activities, which extend past December 31, 2004, have not been valued by McDaniel or Paddock Lindstrom. iv) Reserve values have been evaluated under a blow-down scenario. 25.01 NET ASSET VALUE ($/share) 30.00 25.00 20.00 15.00 10.00 5.00 00 01 02 03 04 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 19 Coalbed Methane, southern Alberta �� 20 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT AREAS OF INTEREST AREAS of INTEREST COALBED METHANE Coalbed Methane (CBM) or natural gas from Coal (NGC) is an ‘unconventional’ source of natural gas. In southern Alberta the Horseshoe Canyon coals of the Edmonton group has become one of the hottest land and drilling plays on the continent. Historically, CBM has been produced from wet coal seams, where huge amounts of water are removed to allow natural gas to desorb and produce from the coal. This is the case in the San Juan, Powder River and Black Warrior basins in the United States. In Southern Alberta however, the Horseshoe Canyon coals do not contain water, they are dry, and therefore the natural gas produces from the coal seams immediately after stimulation with no appreciable water production. The rates and reserves from these wells are similar to that from the Medicine Hat and Milk River formation wells which have been the mainstay of Alberta production for the last century. These wells typically produce at steady rates of natural gas with minimum declines and have a long reserve life. The producing region for the Horseshoe Canyon stretches along the central part of Alberta from Calgary to just south of Edmonton. Paramount’s land holdings in Chain/Craigmyle are located on the eastern edge of this fairway. In 2004 Paramount participated in 20 wells and completions targeting the Horseshoe Canyon coals. The wells produce gas from the zone at depths between 80 and 350 meters with rates of over 100 Mcf/d. Paramount will be drilling 88 wells in 2005 for CBM in what is the second year of a multi-year exploration and development program. Paramount will be drilling up to 4 wells per section depending on drainage and reserves from each well, and have applied to the Alberta Energy and Utility Board for reduced drill spacing to achieve this in 2005. As part of this program, we are also building a production system which will utilize large diameter pipelines and centrally located compressors to maximize deliverability and reserve recovery of the gas ﬁeld and reduce the proliferation of multiple small wellhead compressors. This is in keeping with the production philosophy we pioneered 26 years ago producing shallow gas in northeast Alberta. With a streamlined production system such as this, though up front costs may be higher, long term operating costs and environmental impact are kept to a minimum. This is an area which has seen oil and gas development in a variety of different plays for the last 60 years, as well as constituting the main agricultural region of Alberta. Paramount is well aware of the responsibility of operating in such an area, and is working with the surface land owners to achieve seamless operations to the beneﬁt of all. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 21 Colville Lake, Northwest Territories �� 22 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT AREAS OF INTEREST AREAS of INTEREST COLVILLE LAKE The Colville Lake development is situated at the Arctic Circle, 1850 kilometres north of Calgary, within the Sahtu settlement region in the Northwest Territories. The area was recognized by Paramount as having signiﬁcant potential for large scale hydrocarbon reserves within the Cambrian-aged Mount Clark and overlying Mount Cap sandstones. Previous National Energy Board (NEB) Signiﬁcant Discovery Licenses recognize over 400 Bcf in the area. In 2004 Paramount and its 50 percent partner, Apache Canada, increased our already signiﬁcant land position in the Sahtu, to over 940,000 acres (over 40 Alberta townships) in three distinct areas; the Nogha gas discovery, Maunoir Ridge, and Turton Lake. In 2003, Paramount and Apache drilled and cased two wells in the Nogha prospect, the Nogha C-49 discovery well and Nogha M-17 down structure. These wells were cased and tested, ﬂowing at between 3 and 5 MMcf/d. In 2004 wells K-14 and B-23 were drilled and cased, further delineating the discovery. McDaniel and Associates have independently reviewed the Nogha exploration results and assigned possible raw gas reserves of 250 Bcf to a 17,000 acre area deﬁned by the C-49 and M-17 wells. During the 2005 winter season Paramount and Apache will re-complete K-14 and B-23 to conﬁrm well deliverability. In 2004, Paramount and Apache drilled and cased Maunoir C-34 as part of the federal exploration commitments on Exploration License (EL) 399. During the 2005 winter drilling season we will drill three additional wells at Maunoir A-67, E-35 and L-80. Successful drilling at Maunoir would signiﬁcantly improve the economic viability of development in the Sahtu. Paramount and Apache will also drill the G-47 well at Turton Lake (on EL 414) to validate the Federal Exploration license acquired in 2003. In late 2004 Imperial Oil Resources Ventures Limited ﬁled application with the NEB to construct the Mackenzie Valley Pipeline (MVPL). If approved and completed on schedule, the pipeline would start up in 2009, delivering gas from the Mackenzie Delta and Valley to the existing pipeline infrastructure in northern Alberta. Several gathering and development scenarios are being considered to deliver Colville gas to the MVPL, and upon successful completion of this year’s program. Paramount will commence conceptual development planning. Paramount’s goal is to complete the area’s initial development in time to make gas deliveries at MVPL start-up. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 23 Oil Sands, northeast Alberta �� 24 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT AREAS OF INTEREST AREAS of INTEREST STEAM ASSISTED GRAVITY DRAINAGE (SAGD) OIL SANDS The Alberta Oil Sands are the largest single deposit of hydrocarbons in the world. The recoverable heavy oil from Alberta’s Oil Sands is second only to Saudi Arabia in terms of total proven crude oil reserves. Alberta’s Oil Sands underlie 140,800 square kilometers, an area larger than the state of Florida. Paramount Resources holds 120,000 acres of oil sands rights in the Athabasca Oil Sands area. The recoverable heavy oil, also called bitumen, is located in the Lower Cretaceous McMurray sands of the Manville group. During 2004 Paramount Resources increased our oil sands holdings by 70 percent, acquiring 51,000 acres of oil sands rights. Paramount now holds over 180 sections of oil sands centered in the areas of Surmont and Leismer of northeast Alberta. In 2004 Paramount drilled 10 Oil Sands Evaluation (OSE) wells to identify bitumen in place. An aggressive OSE program in 2005 is expected to lead to a SAGD prototype facility application in late 2005. Paramount will recover bitumen using Steam Assisted Gravity Drainage – also know as “SAGD”. In SAGD two parallel 800 meter horizontal wells are drilled in at the bottom of the reservoir, one 5 meters higher than the other. About 2000 Bbl/d of steam is injected in the upper well, the bitumen is heated, and then drains by gravity into the lower well at rates of about 750 Bbl/d. Conventional SAGD plants burn natural gas to generate the steam used to recover bitumen. Paramount Resources is committed to develop fuels other than natural gas for use in its commercial oil sands plants. Paramount is conducting an alternate fuel research and development program in 2005 to commercialize another fuel, which could signiﬁcantly lower our long term cost of bitumen recovery. Paramount’s development prospects are in four distinct areas. At Leismer Paramount holds 37 sections estimated to hold over a billion barrels of bitumen in place. In 2005 Paramount will drill about 15 wells in Leismer to identify an initial commercial development area. Upon conﬁrmation of commercial potential, Paramount will commence the design and regulatory process necessary to start-up a 3,000 Bbl/d prototype project in 2006. The successful demonstration project could lead to a 30,000 Bbl/d commercial project for start-up as early as 2008 or 2009. At Surmont Paramount has 11 sections of land directly offsetting the Surmont Commercial Project. In 2005 Paramount will continue OSE drilling and complete a conceptual design, leading to development of a commercial recovery scheme following Leismer. At Corner and Thornbury, Paramount holds additional potential resources which position the Company with heavy oil opportunities which extend through 2025. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 25 MANAGEMENT’S DISCUSSION and ANALYSIS (“MD&A”) Paramount Resources Ltd. (“Paramount” or the “Company”) is pleased to report its ﬁnancial and operating results for the year ended December 31, 2004. The following discussion of ﬁnancial position and results of operations should be read in conjunction with the consolidated ﬁnancial statements and related notes for the year ended December 31, 2004. The consolidated ﬁnancial statements have been prepared in Canadian dollars and in accordance with Canadian generally accepted accounting principles (“GAAP”). A reconciliation to United States GAAP is included in Note 17 to the consolidated ﬁnancial statements. This MD&A contains forward-looking statements within the meaning of applicable securities laws. Forward- looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. The forward-looking statements in this MD&A include statements with respect to, among other things: Paramount’s business strategy, Paramount’s intent to control marketing and transportation activities, the weighting of Paramount’s production toward natural gas, reserve estimates, production estimates, ﬁnancial instrument policies, asset retirement obligations, the size of available income tax pools, the renewal of the Company’s credit facility, the funding sources for the Company’s capital expenditure program, cash ﬂow estimates, environmental risks faced by the Company and compliance with environmental regulations, commodity prices, and the impact of the adoption of various Canadian Institute of Chartered Accountants Handbook Sections and Accounting Guidelines. Although Paramount believes that the expectations reﬂected in such forward-looking statements are reasonable, undue reliance should not be placed on them because the Company can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including known and unknown risks and uncertainties inherent in the Company’s business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate and interest rate ﬂuctuations, availability of services and supplies, market competition, uncertainties in the estimates of reserves, the timing of development expenditures, production levels and the timing of achieving such levels, the Company’s ability to replace and expand oil and gas reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected ﬁnancial requirements of the Company, the cost of future asset retirement obligations, 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. Early in 2003, the Company disposed of a signiﬁcant number of assets to Paramount Energy Trust. The net book value of the assets amounted to $244.4 million (17 percent) of total assets as of December 31, 2002, 94.8 Mcf/d (39 percent) of total natural gas production, and 15,807 Boe/d (34 percent) of total production. As such, the 2002 26 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A FINANCIAL STATEMENTS comparative ﬁgures shown in this MD&A report contains the results of these assets and should be read and interpreted with this understanding. As of March 8, 2005 Paramount had 63.9 million common shares outstanding. The date of this MD&A is March 9, 2005. Additional information on the Company, including the Annual Information Form, can be found on the SEDAR website at www.sedar.com. Paramount Resources Ltd. (Paramount” or the “Company”) is an independent Canadian energy company involved in the exploration, development, production, processing, transportation and marketing of natural gas and oil. The Company’s principal properties are located in Alberta, the Northwest Territories and British Columbia in Canada. The Company also has properties in Saskatchewan and offshore the East Coast in Canada, and in Montana and North Dakota in the United States. 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 REORGANI ZAT ION On December 13, 2004 Paramount announced that its Board of Directors had unanimously approved a proposed reorganization which would result in Paramount’s shareholders receiving units of a new energy trust (the “Trust”, now named Trilogy Energy Trust) which will indirectly own existing properties of Paramount with current production of approximately 25,000 Boe/d (the “Trust Spinout”). Under the Trust Spinout, Paramount’s shareholders will continue to be shareholders of Paramount, which will continue to operate as it has in the past. The Company has also announced that a special meeting of security holders to consider its previously announced trust spinout transaction is scheduled to be held on Monday, March 28, 2005. The Trust Spinout is expected to be effected through an arrangement under the Business Corporations Act (Alberta). The transaction is subject to approval by the shareholders and option holders of Paramount, the Court of Queen’s Bench of Alberta and regulatory authorities. At the meeting, holders of Paramount common shares and options will be asked to approve the Trust Spinout which would result in Paramount shareholders receiving units of a new energy trust, to be known as Trilogy Energy Trust (“Trilogy”). Upon completion of the Trust Spinout, Paramount shareholders will own 100 percent of post-reorganization Paramount and 81 percent of the outstanding units of Trilogy. Paramount will own the remaining 19 percent of the outstanding units of Trilogy. Shareholders will receive one trust unit for each existing common share. Based on the number of Paramount shares outstanding on February 25, 2005, there are expected to be approximately 63.9 million common shares of Paramount and 78.9 million units of Trilogy outstanding upon completion of the Trust Spinout. Trilogy will, subject to approval, indirectly own certain of Paramount’s existing assets with current production of approximately 25,000 Boe/d (80 percent natural gas). These assets, in the Kaybob and Marten Creek areas of Alberta, are primarily low-risk, high working interest properties that are geographically concentrated with numerous inﬁll drilling opportunities and good access to infrastructure and processing facilities to be operated and controlled by Trilogy. The balance of Paramount’s assets, consisting of its predominantly growth-oriented assets, will remain with Paramount. Current production from these assets is approximately 20,000 Boe/d (75 percent natural gas). Through Paramount, shareholders will participate in the potential upside of its remaining predominantly growth-oriented assets. Through Trilogy, unitholders will receive regular distributions of cash derived from the cash ﬂow produced by Trilogy’s low-risk development assets. Due to Trilogy’s extensive development drilling portfolio, it is anticipated that Trilogy will retain approximately 35 percent of its cash ﬂow for capital expenditures with the remaining 65 percent of its cash ﬂow being distributed to unitholders in monthly distributions. This extensive development drilling portfolio is expected to make Trilogy less reliant on the competitive acquisition market for developed assets to maintain and grow distributions. Paramount believes that the Trust Spinout will enhance value for shareholders by dividing Paramount’s assets into two speciﬁc groups, consisting of (i) the PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 27 higher free cash ﬂow Kaybob and Marten Creek assets which will be owned through Trilogy, and (ii) the predominantly growth oriented assets that will continue to be owned by Paramount. The Trust Spinout will allow shareholders to participate either separately or on a combined basis in the growth potential and low-risk development qualities of Paramount’s assets. Paramount believes that the post-transaction structure better aligns risks and returns from each asset class in a way that is both sustainable and tax effective. If the necessary securityholder and court approvals are obtained and other conditions are satisﬁed, the Trust Spinout is expected to be completed on or about April 1, 2005. NOTE REDEMPTION On December 30, 2004 the Company redeemed approximately US$41.7 million of the 7 7/8 percent Senior Notes due 2010 and US$43.7 million of the 8 7/8 percent notes due 2014. The indentures governing the notes permit the Company to redeem up to 35 percent of the aggregate principal amount of each series of notes outstanding. The redemptions were made pursuant to the rights offering arising from the Company’s October equity offerings. NOTE EXCHANGE On December 17, 2004, Paramount commenced the exchange offer and consent solicitation for its 7 7/8 percent Senior Notes due 2010 (the “2010 Notes”) and 8 7/8 percent Senior Notes due 2014 (the “2014 Notes”). On February 7, 2005, the Company completed the notes offer by issuing US$213.6 million principal amount of 2013 notes and paying aggregate cash consideration of approximately US$36.2 million in exchange for approximately 99.31 percent of the 2010 notes and 100 percent of the 2014 notes. The 2013 notes bear interest at a rate of 8 1/2 percent per annum and mature January 31, 2013. The notes are secured by approximately 80 percent of the Trust units that will be owned by Paramount following completion of the Trust Spinout (see Reorganization Announcement above). EQUITY I SSUANCE On October 26, 2004, Paramount completed its public offering of 2,500,000 common shares (including 500,000 common shares issued following the exercise in full of the underwriters’ option) at a price of $23.00 per share for gross proceeds of $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 were $59 million. DIS POSITIO N OF ASSET S 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. $8 7 MILLION ASSET ACQUIS IT ION On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for $86.9 million, after 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. The asset retirement associated with these assets is $2.1 million. In accounting for this acquisition, the Company recorded a future tax asset in the amount of $89.0 million. $1 85 MILLIO N ASSET A CQUISIT ION 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 were 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 (“NGLs”). The reserves attributable to the properties as of June 1, 2004 were estimated by Paramount to consist of proved reserves of approximately 47.2 Bcf of natural gas and 4.4 million Bbl of oil and NGLs, or a total of 12.3 million Boe; 28 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A proved plus probable reserves of approximately 93.6 Bcf of natural gas and 6.7 million Bbl of oil and NGLs, 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 L ON G- TER M S ENIO R 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. REVENUE & PRODUCTION Revenue (thousands of dollars) Natural gas, net of transportation Oil and natural gas liquids, net of transportation Petroleum and natural gas revenue Realized financial instrument gain (loss) Unrealized financial instrument gain Gain (loss) on investments Gross revenue before royalties 2004 $ 425,626 124,990 550,616 (683) 19,376 (34) $ 569,275 2003 $ 333,924 100,135 434,059 (53,204) - (1,020) $ 379,835 2002 $ 311,438 72,750 384,188 46,813 - 40,830 $ 471,831 Petroleum and natural gas revenue totaled $550.6 million in 2004, as compared to $434.1 million in 2003 (2002 - $384.2 million). The increase in revenue is due to increased production and higher commodity prices. Stronger natural gas demand resulted in an increase of 12 percent in Paramount’s average natural gas sales price before ﬁnancial instruments to $6.72/Mcf as compared to $5.99/Mcf in 2003 (2002 - $3.53/Mcf). The Company’s average natural gas price after ﬁnancial instruments was $6.86/Mcf as compared to $5.16/Mcf in 2003 (2002 - $4.08/Mcf). Natural gas production volumes averaged 173 MMcf/d in 2004, a 13 percent increase from the 153 MMcf/d produced in 2003 (2002 – 241 MMcf/d), primarily as a result of acquisitions made during the year. Oil and natural gas liquids (“NGLs”) production averaged 7,297 Bbl/d in 2004, a two percent increase from 2003’s average production of 7,169 Bbl/d. Paramount’s average oil and NGLs sales price before ﬁnancial instruments was $46.80/Bbl in 2004 compared to $38.27/Bbl in 2003, primarily due to stronger market prices. In addition, the Company’s average oil and NGLs price increased due to a change in product mix as a result of NGLs and light oil properties acquired in 2004 replacing medium grade properties disposed of in October 2003. Paramount’s 2004 production proﬁle continued to be signiﬁcantly weighted to natural gas. In 2004 natural gas production contributed 80 percent of Paramount’s total production compared to 78 percent in 2003 (2002 – 88 percent). Fourth quarter petroleum and natural gas revenue before ﬁnancial instruments totaled $165.8 million as compared to $86.1 million for the comparable quarter in 2003 (2002 - $135.0 million). The increase in revenue is due to increased production volumes and to higher commodity prices. Natural gas production volumes averaged 198 MMcf/d during the fourth quarter, an increase of 40 percent as compared to 141 MMcf/d for the comparable quarter in 2003 (2002 – 263 MMcf/d). The increase in natural gas production is primarily a result of production from acquired properties during the year. Oil and NGLs sales averaged 8,903 Bbl/d in the fourth quarter of 2004 as compared to 5,877 Bbl/d for the comparable quarter in 2003 (2002 – 8,552 Bbl/d). Increased oil and NGLs production during the fourth quarter of 2004 is mainly the result of increased NGLs production associated with the properties acquired combined with a decrease in oil and NGLs production resulting from the sale of Sturgeon Lake in October 2003. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 29 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. Commencing the fourth quarter of 2003 the Company adopted the Instrument prospectively. As such, fourth quarter 2003 and subsequent period natural gas production volumes are measured in marketable quantities, with adjustments for heat content and transportation reﬂected in the reported natural gas price. 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 commodity price hedges. The ﬁnancial instrument program is generally for periods of less than one year and would not exceed 50 percent of Paramount’s current production volumes. At December 31, 2004, Paramount had the following commodity price ﬁnancial instrument contracts in place: Amount Price Term Sales Contracts NYMEX Fixed Price NYMEX Fixed Price NYMEX Fixed Price AECO Fixed Price AECO Fixed Price AECO Fixed Price NYMEX Call Option AECO Fixed Price AECO Fixed Price AECO Fixed Price Purchase Contracts AECO Fixed Price 10,000 MMbtu/d 10,000 MMbtu/d 10,000 MMbtu/d 20,000 GJ/d 20,000 GJ/d 20,000 GJ/d 20,000 MMbtu/d 20,000 GJ/d 20,000 GJ/d 20,000 GJ/d 6.41 US$ 7.46 US$ 7.95 US$ 7.90 $ 8.03 $ $ 7.60 US$ 10.00 Strike 6.28 $ 6.30 $ 6.80 $ November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 December 2004 - March 2005 April 2005 - June 2005 April 2005 - June 2005 April 2005 - June 2005 20,000 GJ/d $ 6.76 November 2004 - March 2005 Had these ﬁnancial contracts been settled on December 31, 2004, using prices in effect at that time, the mark to market before tax gain would have totaled $14.2 million. As at December 31, 2004, the Company had entered into the following physical delivery contracts: Physical Delivery Contracts Station 2 Fixed Price Station 2 Fixed Price Amount 8,000 GJ/d 12,000 GJ/d Price $ $ 7.99 8.00 Term November 2004 - March 2005 November 2004 - March 2005 Subsequent to December 31, 2004, the Company has entered into the following ﬁnancial instrument contracts: Sales Contracts NYMEX Fixed Price NYMEX Fixed Price NYMEX Fixed Price AECO Fixed Price AECO Fixed Price Amount Price Term 1,000 Bbl/d 1,000 Bbl/d 1,000 Bbl/d 10,000 GJ/d 10,000 GJ/d US$ 46.77 US$ 47.30 US$ 53.26 7.06 7.10 $ $ March 2005 - December 2005 March 2005 - September 2005 April 2005 - September 2005 April 2005 - October 2005 April 2005 - October 2005 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 30 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A 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 year ended December 31, 2004 totaled $1.8 million for the deferred ﬁnancial instrument loss and $1.6 million for the deferred ﬁnancial instrument gain, for a net decrease in earnings before tax of $0.2 million. In addition, the Company recorded a net ﬁnancial instrument asset at December 31, 2004, with a fair value of $19.4 million. This amount reﬂects the unrealized changes in fair value of Paramount’s ﬁnancial instruments. The total gain on ﬁnancial instruments for the period of $18.7 million is comprised of unrealized gains of $19.4 million (change in fair value of contracts recorded on transition - $1.3 million gain, amortization of the fair value of contracts - $0.2 million loss, fair value of contracts entered into during the period - $18.3 million gain) less realized losses of $0.7 million. The $0.7 million realized cash losses on ﬁnancial instruments for the year ended December 31, 2004 is a 99 percent decrease from the $53.2 million of realized cash losses on ﬁnancial instruments for the 2003 comparative period. 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. During 2004, approximately 65 percent of Paramount’s natural gas sales were under long-term contracts to gas aggregators and direct-sales purchasers as compared to 75 percent and 43 percent for 2003 and 2002, respectively. The decrease in the percentage is due to decreased aggregator gas sales as well as termination of the Company’s Ventura northern border agreement. Paramount closed a transaction in March 2005 whereby it acquired an indirect 25 percent ownership interest in a gas marketing limited partnership. In conjunction with the acquisition of the ownership interest, Paramount will make available for delivery an average of 150 million GJ/d of natural gas over a ﬁve year term, to be marketed on Paramount’s behalf by the gas marketing limited partnership. Paramount and Summit Operating Partnership (which will become Trilogy Energy LP, subject to the completion of the Trust Spinout) have entered into a Call on Production Agreement. Under this agreement, Paramount will have the right to purchase all or any portion of Trilogy Energy LP’s available gas production at a price no less favourable than the price Paramount will receive on the resale of the natural gas to the gas marketing limited partnership. The term of the Call on Production Agreement will be no longer than ﬁve years. Paramount is not entitled to demand collateral securities from the gas marketing limited partnership to ensure payment for the gas volumes delivered, but is entitled to other means of protection in this regard including stringent credit and risk management restrictions. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 31 NETBACKS Netbacks ($/Boe) P&NG revenue, net of transportation Royalties Operating costs Operating netback Realized financial instrument loss (gain) General and administrative Bad debt expense (recovery) Lease rentals Interest on long-term debt (1) Current and Large Corporations Tax Cash flow netback (1) Net of non-cash interest expense. ROYALTIES Royalties (thousands of dollars) Crown royalties (net of ARTC) Other royalties Net royalties Average corporate royalty rate as a percentage of petroleum and natural gas revenue before financial instruments 2004 41.61 7.94 7.24 26.43 0.05 1.91 (0.42) 0.27 1.82 0.51 22.29 $ $ $ 2004 99,298 5,748 $ 105,046 2003 36.36 6.93 6.82 22.61 4.47 1.60 0.50 0.30 1.60 0.23 13.91 2003 78,996 3,516 82,512 $ $ $ $ 2002 25.50 4.44 5.14 15.92 (2.79) 0.95 - 0.27 1.43 0.55 15.51 2002 70,786 3,658 74,444 $ $ $ $ 19.1% 19.0% 19.4% For 2004, net royalties increased to $105.0 million from $82.5 million in 2003 (2002 – $74.4 million) due to higher production and commodity prices. As a percentage of revenue, Paramount’s corporate royalty rate is substantially unchanged from the prior year, at 19.1 percent compared to 19.0 percent in 2003. Fourth quarter royalties totaled $30.4 million as compared to $10.7 million for the fourth quarter in 2003 (2002 - $28.2 million). The increase in royalty costs reﬂects the increase in production volumes and higher commodity prices. OPERATING COSTS Operating Expenses (thousands of dollars) Operating expenses Net operating expenses per Boe 2004 95,767 7.24 $ $ 2003 81,193 6.82 $ $ 2002 86,067 5.14 $ $ Paramount’s 2004 operating expenses increased 18 percent to $95.8 million from $81.2 million in 2003 (2002 – $86.1 million). On a units-of-production basis, operating costs increased 6 percent to $7.24/Boe from $6.82/Boe in 2003 (2002 – $5.14/Boe). The industry in general experienced increases in the costs of goods and services particularly higher labour and energy costs. In addition, properties acquired by the Company during the year have higher per unit operating costs than existing Paramount properties. Paramount constructs and operates plant facilities and gathering systems as a corporate strategy in order to control the ﬂow of its natural gas to market. These facilities incur ﬁxed costs, which are in addition to the costs incurred at the well level, thereby increasing total operating expenses and the relative magnitude of the per unit costs. Fourth quarter operating costs increased to $30.9 million as compared to $22.3 million a year earlier. Fourth quarter operating costs decreased on a units-of-production basis to $8.02/Boe from $8.25/Boe for the comparable quarter in 2003. The 2004 fourth quarter operating costs included workovers related to acquired properties, while the fourth quarter of 2003 included the settlement of a dispute with a facility operator, as well as post-closing adjustments related to the Sturgeon Lake property sale incurred during the quarter. 32 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A GENERAL AND ADMINISTRATIVE EXPENSES General and Administrative Expenses (thousands of dollars) Gross general and administrative expenses Operating recoveries Net general and administrative expenses Net general and administrative expenses per Boe 2004 41,007 (15,760) 25,247 1.91 $ $ $ 2003 31,906 (12,855) 19,051 1.60 $ $ $ 2002 30,868 (15,238) 15,630 0.95 $ $ $ General and administrative expenses, net of operating recoveries, increased to $25.2 million in 2004 as compared to $19.1 million in 2003 (2002 - $15.6 million). Paramount has increased its head ofﬁce stafﬁng levels to enable the Company to identify and develop new core areas and build its production portfolio. This initiative has resulted in Paramount advancing its long-term projects such as Colville Lake, Northeast Alberta bitumen and coal bed methane, and developing successful new ﬁelds in existing core areas within Grande Prairie and Northwest Alberta. The Company has also increased administrative staff levels to ensure compliance with new corporate and reporting obligations in Canada and the United States; certain of these are a result of the US debt offerings closed in 2004. Paramount does not capitalize any general and administrative expenses with the exception of overhead recoveries. STOCK–BASED COMPENSATION Prior to 2004, the Company accounted for its stock option plan using the fair value method. In 2004, the Company prospectively adopted the intrinsic value method to account for the Company’s stock-based compensation plan. For 2004, the Company recorded a $41.2 million non-cash expense using the intrinsic value method compared to the $1.2 million non-cash expense recorded in 2003 (2002 - $0.6 million) using the fair value method. INTEREST EXPENSE Interest Expense (thousands of dollars) Interest expense Total debt, December 31 Average debt outstanding for the period 2004 $ 25,399 $ 459,141 $ 443,156 2003 $ 19,214 $ 287,237 $ 340,919 2002 $ 23,943 $ 539,270 $ 448,951 Interest expense increased to $25.4 million in 2004 from $19.2 million in 2003 (2002 – $23.9 million). The increase reﬂects higher average debt levels for the Company in 2004 as a result of acquisitions made in the current year. DRY HOLE COSTS Under the successful efforts method of accounting, costs of drilling exploratory wells are initially capitalized and, if subsequently determined to be unsuccessful, are charged to dry hole expense. Other exploration costs, including geological and geophysical costs and annual lease rentals, are charged to exploration expense as incurred. For 2004, dry hole costs amounted to $24.7 million as compared to $36.6 million in 2003 (2002 - $120.1 million). The 2004 provision includes $5.8 million of costs associated with wells drilled in the current year and $18.9 million associated with exploratory wells drilled in previous years. Geological and geophysical expenses increased during 2004 to $8.7 million from $8.5 million in the previous year (2002 - $9.3 million). DEPLETION, DEPRECIATION AND AMORTIZATION The current year provision for depletion and depreciation expense totaled $191.6 million as compared to $165.1 million in 2003 (2002 – $169.4 million). Depletion and depreciation expense includes expired lease costs of $12.9 million. On a units-of-production basis, depletion and depreciation costs averaged $14.48/Boe as compared to $13.86/Boe in 2003 (2002 - $10.11/Boe). Capital costs associated with undeveloped land of $164 million and non-producing petroleum and natural gas properties of $136 million totaling $300 million are excluded from capital costs subject to depletion in 2004 (2003 - $209 million). PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 33 ASSET RETIREMENT OBLIGATIONS Effective January 1, 2004, the Company retroactively adopted, with restatement, the Canadian Institute of Chartered Accountants (“CICA”) recommendation on Asset Retirement Obligations, which requires liability recognition for the fair value of retirement obligations associated with long-lived assets. Prior to January 1, 2004, the estimated future dismantlement and site restoration costs of natural gas and crude oil assets were provided for using the unit-of-production method. As a result of this change, net earnings for the year ended December 31, 2003 decreased by $1.5 million ($0.02 per share). The asset retirement obligations liability as at December 31, 2003 increased by $40.4 million, property, plant and equipment, net of accumulated depletion, increased by $31.1 million, and future income tax liability decreased $3.7 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 obligations, recorded retroactively. On an annual basis the Company reviews the liability for asset retirement obligations. For 2004, accretion expense for asset retirement obligations totaled $6.9 million as compared to $4.0 million in 2003. At December 31, 2004, the Company had recorded an asset retirement obligation liability for its petroleum and natural gas properties of $101.5 million (2003 - $61.6 million). The majority of the increase is due to the obligations associated with additional acquired properties purchased during the year. INCOME TAXES In 2004, Paramount recorded Large Corporations and other tax expense of $6.8 million as compared to $2.7 million in 2003. The future income tax expense recorded for 2004 totaled $40.7 million, as compared to $63.5 million recovery in 2003. Estimated Income Tax Pools (millions of dollars) Undepreciated capital costs (UCC) Canadian oil and gas property expenses (COGPE) Canadian development expenses (CDE) Canadian exploration expenses (CEE) Other Total estimated income tax pools $ $ December 31, 2004 December 31, 2003 215 25 166 68 21 495 257 422 203 158 33 1,073 $ $ Paramount has available approximately $1,073 million of unutilized tax pools at December 31, 2004. These tax pools will be available for deduction in 2005 in accordance with Canadian income tax regulations at varying rates of amortization. 34 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A CASH FLOW AND EARNINGS (thousands of dollars) Cash flow from operations Cash flow from operations per share Net earnings before discontinued operations Net earnings (loss) from discontinued operations Net earnings Earnings before discontinued operations per share Earnings per share - basic - diluted - basic - diluted - basic - diluted 2004 $ 295,566 4.95 $ 4.84 $ 34,895 $ 6,279 $ 41,174 $ 0.58 $ 0.57 $ 0.69 $ 0.67 $ 2003 167,276 2.78 2.77 1,208 (57) 1,151 0.02 0.02 0.02 0.02 $ $ $ $ $ $ $ $ $ $ 2002 $ 259,916 4.37 $ 4.36 $ 11,132 $ (825) $ 10,307 $ 0.19 $ 0.19 $ 0.17 $ 0.16 $ Paramount’s cash ﬂow from operations increased 77 percent to $295.6 million from $167.3 million in 2003. The increase in cash ﬂow was a result of a reduction in realized ﬁnancial instrument losses in 2004 as compared to 2003, and an increase in revenues due to higher commodity prices and production. This was partially offset by higher operating costs, general and administrative expenses and interest. Fourth quarter cash ﬂow totaled $92.1 million, an increase of 113 percent from $43.2 million during the same period in 2003 (2002 - $62.1 million). The increase in cash ﬂow is a result of higher production levels and increased commodity prices as compared to the fourth quarter of 2003. The Company recorded net earnings of $41.2 million for the year ended 2004, as compared to net earnings of $1.2 million in 2003. The higher earnings in 2004 are primarily due to an increase in petroleum and natural gas sales resulting from higher production and commodity prices, ﬁnancial instrument gains in 2004 as opposed to 2003 losses, and unrealized foreign exchange gains on US debt. This was partially offset by higher non-cash stock based compensation expense, depletion and depreciation expense, and future income tax expense. QUARTERLY INFORMATION Historical quarterly information, prepared by the Company in Canadian dollars and in accordance with GAAP, is as follows: (thousands of dollars, except per share amounts) Net revenues Net earnings (loss) before discontinued operations Net earnings (loss) from discontinued operations Net earnings (loss) Net earnings (loss) before discontinued operations per common share Net earnings (loss) per common share (thousands of dollars, except per share amounts) Net revenues Net earnings (loss) before discontinued operations Net earnings (loss) from discontinued operations Net earnings (loss) Net earnings (loss) before discontinued operations per common share Net earnings (loss) per common share - basic - diluted - basic - diluted - basic - diluted - basic - diluted Fiscal 2004 Three Months Ended Dec. 31 162,880 (18,873) 1,120 (17,753) (0.30) (0.29) (0.28) (0.28) $ $ $ $ $ $ $ $ Sep. 30 127,192 40,599 5,213 45,812 0.69 0.68 0.78 0.76 June 30 95,767 10,331 (395) 9,936 0.18 0.17 0.17 0.17 $ $ $ $ $ $ $ $ Fiscal 2003 Three Months Ended Dec. 31 76,945 10,899 209 11,108 0.18 0.18 0.18 0.18 Sept. 30 65,415 (8,491) 108 (8,383) (0.14) (0.14) (0.14) (0.14) $ $ $ $ $ $ $ $ June 30 65,101 (1,105) (783) (1,888) (0.02) (0.02) (0.03) (0.03) $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Mar. 31 79,179 2,838 341 3,179 0.05 0.05 0.05 0.05 Mar. 31 91,446 (95) 409 314 - - 0.01 0.01 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 35 Quarterly net revenues have continued to increase since June 30, 2003, primarily as a result of an increase in production levels and higher commodity prices. The decrease in net revenue between March 31, 2003 and June 30, 2003 is primarily due to lower production volumes resulting from the disposition of assets to Paramount Energy Trust in the ﬁrst quarter of 2003. The third and fourth quarter net revenues for 2004 reﬂect increased production resulting from the acquisition of assets in the Kaybob, East Liard, and Marten Creek areas. Quarterly net earnings are generally lower in 2003 due to lower production levels, combined with higher ﬁnancial instrument losses incurred during 2003. The net loss in the fourth quarter of 2004 is primarily due to the Company prospectively adopting the intrinsic value method to account for stock based compensation expense and an increase in future tax expense. CAPITAL EXPENDITURES Capital Expenditures (thousands of dollars) Land Geological and geophysical Drilling Production equipment and facilities Exploration and development expenditures Summit Resources Limited acquisition Property acquisitions Proceeds on property dispositions Other Net capital expenditures Property, plant and equipment, net, December 31 Total assets, December 31 $ 2004 37,919 8,728 184,466 85,171 316,284 - 322,598 (61,806) 1,938 $ 579,014 $ 1,345,806 $ 1,542,786 $ 2003 22,288 8,450 123,455 69,560 223,753 - 937 (371,601) 1,933 $ (144,978) $ 1,037,307 $ 1,177,130 $ 2002 6,410 9,303 124,076 77,407 217,196 251,422 28,610 (5,042) 2,349 $ 494,535 $ 1,411,961 $ 1,526,786 During 2004, expenditures for exploration and development activities totaled $316.3 million as compared to $223.8 million in 2003 (2002 – $217.2 million). The increase in the capital expenditures program in 2004 resulted in a total of 271 gross (180 net) wells drilled during the year, compared to 211 gross (139 net) wells in 2003 (2002 – 135 gross, 99 net). Net capital expenditures totaled $579.0 million in 2004 as compared to a recovery of $145 million in 2003 (2002 – $494.5 million). The Company acquired a number of properties totaling $322.6 million in 2004 offset by the disposition of certain non-core properties. Paramount has budgeted a total of $340 million for capital expenditures for 2005; $100 million of which is to be directed to the Trilogy assets and the remaining $240 million will be directed to the properties retained by Paramount Resources Ltd. The 2005 capital expenditure program is expected to be funded through the Company’s 2005 cash ﬂow. 36 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A INVESTMENTS The Company has the following short-term investments: Investments Fox Creek Petroleum Corp. Invertek (1) Trinidad Drilling Ltd. (1)(2) Arctos Petroleum Corp. (6) Harvest Energy Trust Jurassic Oil and Gas Ltd. (3) Jurassic Oil and Gas Ltd. - Demand Note (4) USD short-term deposits (5) Opening 2004 Shares 2,325,162 - - - 200,000 850,000 - - 3,375,162 Closing Acquired (Divested) 2004 Shares 2,325,162 - 820,513 - - 850,000 - - 3,995,675 - - 820,513 - (200,000) - - - 620,513 Investment $ 2,538,000 560,114 6,400,001 2,116,945 - - 100,000 13,268,200 $ 24,983,260 (1) Investment in Invertek and Trinidad Drilling Ltd. is through Wilson Drilling Ltd. (2) Investment is in the form of Exchangeable Shares which can be redeemed for trust units in Trinidad Energy Services Income Trust. (3) The Company wrote off its investment in Jurassic Oil and Gas Ltd. in 2003 but has retained the shares. (4) Bears interest at 6 percent per annum. (5) US$5 million matures January 4, 2005 and bears interest at 2.15 percent per annum. US$6 million matures January 14, 2005 and bears interest at 2.23 percent per annum. (6) Investment is in the form of convertible debentures maturing March 1, 2005 bearing interest at 8 percent per annum. LIQUIDITY AND CAPITAL RESOURCES Paramount’s capital structure as at December 31, 2004, was as follows: (thousands of dollars, except per share amounts) Debt US$ senior notes Credit facility Working capital surplus Net debt Shareholders’ equity Total capitalization (1) At December 31, 2004 – 63,185,600 basic common shares outstanding. DEBT Amount % $/Share(1) $ 257,836 201,305 (7,954) 451,187 625,039 $ 1,076,226 24 19 (1) 42 58 100% $ $ 4.08 3.19 (0.13) 7.14 9.89 17.03 US$ SENIOR NOTES The Company issued US$175 million of 7 7/8 percent Senior Notes due 2010 on October 27, 2003. Interest on the notes is payable semi-annually, beginning in 2004. The Company may redeem some or all of the notes at any time after November 1, 2007 at redemption prices ranging from 100 percent to 103.938 percent of the principal amount, plus accrued and unpaid interest to the redemption date, depending on the year in which the notes are redeemed. In addition, the Company may redeem up to 35 percent of the notes prior to November 1, 2006 at 107.875 percent of the principal amount, plus accrued interest to the redemption date, using the proceeds of certain equity offerings. The notes are unsecured and rank equally with all of the Company’s existing and future senior unsecured indebtedness. 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. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 37 On December 30, 2004, the Company redeemed US$41.7 million principal of its 7 7/8 percent Senior Notes due 2010 and US$43.8 million principal of its 8 7/8 percent Senior Notes due 2014. The aggregate redemption price was US$45.0 million and US$47.6 million plus accrued and unpaid interest for the 7 7/8 percent Senior Notes and 8 7/8 percent Senior Notes respectively. CR ED IT FACILITY As at December 31, 2004, the Company had a $270 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 has requested and received approval for an extension on the revolving credit facility of 364 days. Advances drawn on the facility are secured by a ﬁxed charge over the assets of the Company. In February 2005, the Company’s borrowing capacity under this facility was increased to $330 million as a result of the Company’s Senior Note redemption on December 31, 2004, and an increase in its oil and natural gas reserves. WO RKI NG CAPITAL The Company’s working capital surplus at December 31, 2004 was $8.0 million (2003 - $10.5 million deﬁciency). FU TUR E CO MMITMENTS Future commitments, as at December 31, 2004, are as follows: Contractual Obligations (thousands of dollars) US$ 7 7/8% Senior Notes due 2010 $ US$ 8 7/8% Senior Notes due 2014 Pipeline commitments Total $ Total 160,174 97,662 237,205 495,041 $ Less than 1 year - - 22,015 22,015 $ Expected Payment Date 2-3 years - - 42,504 42,504 $ $ 4-5 years - - 42,075 42,075 After 5 years 160,174 97,662 130,611 388,447 $ $ $ $ SH AR E CAPITAL As at December 31, 2004, the Company’s issued share capital consisted of 63,185,600 common shares (December 31, 2003 – 60,094,600 common shares). Changes in share capital were as follows: Common shares Balance December 31, 2002 Stock options exercised Expenses recognized in respect of stock-based compensation Balance December 31, 2003 Shares repurchased - at carrying value Stock options exercised Common shares issued Flow-through shares issued Tax adjustment on share issuance costs and flow-through share renunciations Balance December 31, 2004 Number 59,458,600 710,000 (74,000) 60,094,600 (1,629,500) 220,500 2,500,000 2,000,000 63,185,600 Consideration (thousands of dollars) $ 190,193 10,317 (236) $ 200,274 (5,322) 3,057 54,901 57,981 (7,959) $ 302,932 Between January 1 and May 14, 2004 the Company repurchased 1,629,500 shares at a carrying value of $5.3 million for $19.4 million. During the year, employees of the Company exercised 220,500 stock options for total consideration of $3.1 million. In October 2004, Paramount completed a public offering of 2.5 million common shares at $23.00 per share and a private placement of 2.0 million “ﬂow through” common shares at $29.50 per share. Aggregate gross proceeds from these two offerings were $116.5 million. As at December 31, 2004, the Company had made renunciations of $23.7 million. 38 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A STOCK OPTIONS The Company has an Employee Incentive Stock Option plan (the “plan”). Under the plan, stock options are granted at the current market price on the day prior to issuance. Participants in the plan, upon exercising their stock options, may request to receive either a cash payment equal to the difference between the exercise price and the market price of the Company’s common shares or common shares issued from Treasury. Irrespective of the participant’s request, the Company may choose to only issue common shares. Cash payments made in respect of the plan are charged to general and administrative expenses when incurred. Options granted vest over four years and have a four and a half year contractual life. As at December 31, 2004, 5.0 million shares were reserved for issuance under the Company’s Employee Incentive Stock Option Plan, of which 3.2 million options are outstanding, exercisable to May 31, 2009, at prices ranging from $8.91 to $26.29 per share. Stock options Balance, beginning of year Granted Exercised Cancelled Balance, end of year Options exercisable, end of year RISKS AND UNCERTAINTIES 2004 2003 Average Grant Price 9.64 $ 17.09 9.97 9.09 10.41 10.26 $ $ Options 3,632,000 348,000 (618,500) (149,000) 3,212,500 1,282,875 Average Grant Price 14.25 $ 9.66 14.29 10.30 9.64 10.72 $ $ Options 1,949,500 2,998,000 (791,000) (524,500) 3,632,000 1,087,875 Companies involved in the exploration for and production of oil and natural gas face a number of risks and uncertainties inherent in the industry. The Company’s performance is inﬂuenced by commodity pricing, transportation and marketing constraints and government regulation and taxation. Natural gas prices are inﬂuenced by the North American supply and demand balance as well as transportation capacity constraints. Seasonal changes in demand, which are largely inﬂuenced by weather patterns, also affect the price of natural gas. Stability in natural gas pricing is available through the use of short and long-term contract arrangements. Paramount utilizes a combination of these types of contracts, as well as spot markets, in its natural gas pricing strategy. As the majority of the Company’s natural gas sales are priced to US markets, the Canada/US exchange rate can strongly affect revenue. Oil prices are inﬂuenced by global supply and demand conditions as well as for worldwide political events. As the price of oil in Canada is based on a US benchmark price, variations in the Canada/US exchange rate further affect the price received by Paramount for its oil. The Company’s access to oil and natural gas sales markets is restricted, at times, by pipeline capacity. In addition, it is also affected by the proximity of pipelines and availability of processing equipment. Paramount attempts 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, royalties, 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 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 39 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. 2005 OUTLOOK AND SENSITIVITY ANALYSIS The Company’s earnings and cash ﬂow are highly sensitive to changes in commodity prices, exchange rates and other factors that are beyond the control of the Company. Current volatility in commodity prices creates uncertainty as to Paramount’s cash ﬂow and capital expenditure budget. The Company will therefore assess results throughout the year and revise estimates as necessary to reﬂect most current information. The following analysis assesses the magnitude of these sensitivities on the Company’s 2005 cash ﬂow using the following base assumptions: 2005 Average Production Natural gas Crude oil/liquids 2005 Average Prices Natural gas Crude oil (WTI) 2005 Exchange Rate (C$/US$) 210 MMcf/d 10,000 Bbl/d $6.50/Mcf US$42.00/Bbl $0.81 The following analysis assesses the estimated impact on cash ﬂow with variations in production, prices, interest and exchange rates: Sensitivity Gas sales change of 10 MMcf/d Gas price change of $0.10/Mcf Oil and natural gas liquids sales change of 100 Bbl/d Oil and natural gas liquids price change of $1.00/Bbl (WTI) Sensitivity to Canada/US exchange rate fluctuation of $0.01 CDN Average interest rate change of 1% CRITICAL ACCOUNTING ESTIMATES Cash Flow Effect (millions of dollars) 18.98 6.13 1.27 3.60 1.21 0.62 $ $ $ $ $ $ The MD&A is based on the Company’s consolidated ﬁnancial statements, which have been prepared in Canadian dollars in accordance with Canadian GAAP. The application of Canadian 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. AC C OUNTIN G FOR PET ROL EUM A ND NA T UR A L GA S O PER A TIONS Under the successful efforts method of accounting, the Company capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves, including acquisitions, successful exploratory wells, development costs and the costs of support equipment and facilities. Exploration expenditures, including geological and geophysical costs, lease rentals, and exploratory dry holes are charged to earnings in the period incurred. Certain costs of exploratory wells 40 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A 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 ESTIMATE S 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 entirely on estimates prepared by its independent petroleum consultants. Estimates prepared by others may be different than these estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve estimates may be different from the quantities of petroleum and natural gas that are ultimately recovered. In addition, the results of drilling, testing and production after the date of an estimate may justify revisions to the estimate. The present value of future net revenues should not be assumed to be the current market value of the Company’s estimated reserves. Actual future prices, costs and reserves may be materially higher or lower than the prices, costs and reserves used for the future net revenue calculations. The estimates of reserves impact depletion, dry hole and site restoration expenses. If reserve estimates decline, the rate at which the Company records depletion and site restoration expenses increases, reducing net earnings. In addition, changes in reserve estimates may impact the outcome of Paramount’s assessment of its petroleum and natural gas properties for impairment. IMPAI RMENT OF PETROLEUM A ND N A TUR A L GA S PR OP ER TIES The Company reviews its proved properties for impairment annually on a ﬁeld basis. For each ﬁeld, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is deﬁned as the present value of the estimated future net revenues from production of total proved and probable petroleum and natural gas reserves, as estimated by the Company on the balance sheet date. Reserve estimates, as well as estimates for petroleum and natural gas prices and production costs, may change and there can be no assurance that impairment provisions will not be required in the future. Unproved leasehold costs and exploratory drilling in progress are capitalized and reviewed periodically for impairment. Costs related to impaired prospects or unsuccessful exploratory drilling are charged to earnings. Acquisition costs for leases that are not individually signiﬁcant are charged to earnings as the related leases expire. Further impairment expense could result if petroleum and natural gas prices decline in the future 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. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 41 AS S ET RETIREM ENT OBLIGAT IONS The asset retirement obligations recorded in the consolidated ﬁnancial statements are based on estimated total costs of such obligations related to the Company’s petroleum and natural gas properties. This estimate is based on management’s analysis of production structure, reservoir characteristics and depth, market demand for equipment, currently available procedures and discussions with construction and engineering consultants. Estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology and political and regulatory environments. Beginning in 2004, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook section 3110 – Asset Retirement Obligation, which will result in changes in accounting for asset retirement obligations. See “Recent Accounting Pronouncements” section. I NCOME TAXES The Company records future tax assets and liabilities to account for the expected future tax consequences of events that have been recorded in its consolidated ﬁnancial statements and its tax returns. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash ﬂows and capital expenditures in current and future periods. We periodically assess the realizability of our future tax assets. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset will be reduced by a valuation allowance. RECENT ACCOUNTING PRONOUNCEMENTS I MPA IRMENT OF LO NG-LIVED A S S ET S The CICA recently issued Handbook Section 3063 - Impairment of Long-Lived Assets. This new section establishes standards for the recognition, measurement and disclosure of the impairment of long-lived assets by proﬁt-oriented enterprises. The section is effective for ﬁscal years beginning on or after April 1, 2003. Under the new section, impairment of long-lived assets held for use is determined by a two-step process, with the ﬁrst step determining when an impairment is recognized and the second step measuring the amount of the impairment. To test for and measure impairment, long-lived assets are grouped at the lowest level for which identiﬁable cash ﬂows are largely independent. An impairment loss is recognized when the carrying amount of a long-lived asset exceeds the sum of the undiscounted cash ﬂows expected to result from its use and eventual disposition. An impairment loss is measured as the amount by which the long-lived asset’s carrying amount exceeds its fair value. This represents a signiﬁcant change to Canadian GAAP, which previously measured the amount of the impairment as the difference between the long-lived asset’s carrying value and its net recoverable amount (i.e. undiscounted cash ﬂows plus residual value). DIS POSAL OF LONG-LIVED A S S ET S A ND D IS C ON TINUE D OPER A TIONS The CICA recently issued Handbook Section 3475 - Disposal of Long-Lived Assets and Discontinued Operations, which establishes standards for the recognition, measurement, presentation and disclosure of the disposal of long-lived assets by proﬁt-oriented enterprises. It also establishes standards for the presentation and disclosure of discontinued operations. Although earlier adoption is encouraged, Section 3475 applies to disposal activities initiated by a company’s commitment to a plan on or after May 1, 2003. VA RIA BLE IN TEREST ENTITIE S The CICA recently issued Accounting Guideline 15 - Consolidation of Variable Interest Entities. The guideline requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other ﬁnancial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling ﬁnancial interest through ownership of a majority voting interest in the entity. The guideline applies to annual and interim periods beginning on or after November 1, 2004, except for certain disclosure requirements. Entities should provide disclosures about variable interest entities in which they hold signiﬁcant interests for periods beginning on or after January 1, 2004. 42 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT MD&A ASSET RETIREMENT OBLIGAT IONS The CICA recently issued Handbook Section 3110 – Asset Retirement Obligation which addresses statutory, regulatory, contractual and other legal obligations associated with the retirement of a long-lived asset that results from its acquisition, construction, development or normal operation. Under Section 3110, asset retirement obligations are initially measured at fair value at the time the obligation is incurred with a corresponding amount capitalized as part of the asset’s carrying value and depreciated over the asset’s useful life using a systematic and rational allocation method. On initial recognition, the fair value of an asset retirement obligation is determined based upon the expected present value of future cash ﬂows. In subsequent periods, the carrying amount of the liability would be adjusted to reﬂect (a) the passage of time, and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash ﬂows. The change in liability due to the passage of time is measured by applying an interest method of allocation to the opening liability and is recognized as an increase in the carrying value of the liability and an expense. The expense must be recorded as an operating item in the income statement, not as a component of interest expense. A change in the liability resulting from revisions to either the timing or the amount of the original estimate of undiscounted cash ﬂows is recognized as an increase or decrease in the carrying amount of the liability with an offsetting increase or decrease in the carrying amount of the associated asset. FINANCIAL INS TRUMENTS, OT H ER C OM P R EH EN S IV E I NC OM E A ND EQU ITY The CICA is expected to adopt a new standard in 2005 that sets-out comprehensive requirements for recognition and measurement of ﬁnancial instruments. Under this new standard, an entity would recognize a ﬁnancial asset or liability only when the entity becomes a party to the contractual provisions of the ﬁnancial instrument. Financial assets and ﬁnancial liabilities would, with certain exceptions, be initially measured at fair value. After initial recognition, the measurement of ﬁnancial assets would vary depending on the category of the asset: ﬁnancial assets held for trading (at fair value with the unrealized gains and losses on assets recorded in income), held-to-maturity investments (at amortized cost), loans and receivables (at amortized cost), and available-for-sale ﬁnancial assets (at fair value with the unrealized gains and losses on assets recorded in comprehensive income). Financial liabilities held for trading would be subsequently measured at fair value while all other ﬁnancial liabilities would be subsequently measured at amortized cost using the effective interest method. In conjunction with the proposed new standard on ﬁnancial instruments as discussed above, a new standard on reporting and display of comprehensive income is also expected. A statement of comprehensive income would be included in a full set of ﬁnancial statements for both interim and annual periods under this new standard. Comprehensive income is deﬁned as the change in equity (net assets) of an enterprise during a period from transactions and other events and circumstances from non-owner sources. The new statement would present net income and each component to be recognized in other comprehensive income. Likewise, the CICA is expected to adopt a new standard on Equity that would require the separate presentation of: the components of equity (retained earnings, accumulated other comprehensive income, the total of retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves); and the changes in equity arising from each of these components of equity. These new standards are expected to be effective for the year ending December 31, 2006 for the Company. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 43 MANAGEMENT’S REPORT The accompanying consolidated ﬁnancial statements of Paramount Resources Ltd. and all the information in this Annual Report are the responsibility of management and have been approved by the Board of Directors. The consolidated ﬁnancial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated ﬁnancial statements are presented fairly, in all material respects. The ﬁnancial information contained elsewhere in this report has been reviewed to ensure consistency with the consolidated ﬁnancial statements. Management maintains systems of internal accounting and administrative controls of high quality, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the ﬁnancial information is relevant, reliable and accurate and that the Company’s assets are appropriately accounted for and adequately safeguarded. The Audit Committee of the Board of Directors is comprised of non-management directors. The Audit Committee meets quarterly with management as well as the external auditors to discuss auditing matters and ﬁnancial reporting issues and to satisfy itself that each party is properly discharging its responsibility. The Audit Committee also meets with management and the external auditors to discuss internal controls over the ﬁnancial reporting process and to review the Annual Report. The Audit Committee reports its ﬁndings to the Board of Directors for consideration when approving the consolidated ﬁnancial statements for issuance to the shareholders. The Audit Committee also considers, for review by the Board of Directors and approval by the shareholders, the engagement or re-appointment of the external auditors. The consolidated ﬁnancial statements have been audited by Ernst & Young LLP, the external auditors. Ernst & Young LLP have full and free access to the Audit Committee and management. signed Clayton H. Riddell Chief Executive Ofﬁcer signed Bernard K. Lee Chief Financial Ofﬁcer AUDITORS’ REPORT March 7, 2005 To the Shareholders of Paramount Resources Ltd. We have audited the consolidated balance sheets of Paramount Resources Ltd. as at December 31, 2004 and 2003 and the consolidated statements of earnings and retained earnings and cash ﬂows for the years then ended. These ﬁnancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these ﬁnancial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the ﬁnancial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the ﬁnancial statements. An audit also includes assessing the accounting principles used and signiﬁcant estimates made by management, as well as evaluating the overall ﬁnancial statement presentation. In our opinion, these consolidated ﬁnancial statements present fairly, in all material respects, the ﬁnancial position of the Company as at December 31, 2004 and 2003 and the results of its operations and its cash ﬂows for the years then ended in accordance with Canadian generally accepted accounting principles. We also report that, in our opinion, these principles have been applied, except for the change in the method of accounting for Asset Retirement Obligations, Financial Instruments, and Stock-Based Compensation and Other Stock-Based Payments as explained in note 2 to the consolidated ﬁnancial statements, on a basis consistent with that of the preceding year. Ernst & Young LLP Chartered Accountants Calgary, Canada March 7, 2005 44 PARAMOUNT RESOURCE S LTD. 20 04 ANNUAL REPORT CONSOLIDATED BALANCE SHEETS FINANCIAL STATEMENTS As at December 31 (thousands of dollars) ASSETS (note 8) Current Assets Short-term investments (market value: 2004 - $27,149; 2003 - $17,265) Accounts receivable Financial instruments (note 11) Prepaid expenses Assets of discontinued operations (note 5) Property, Plant and Equipment Property, plant and equipment, at cost (note 6) Accumulated depletion and depreciation (note 6) Assets of discontinued operations, net (note 5) Goodwill Other assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable and accrued liabilities Financial instruments (note 11) Liabilities of discontinued operations (note 5) Long-term debt (note 8) Asset retirement obligations (note 7) Deferred revenue Stock based compensation liability (note 9) Future income taxes (note 10) Liabilities of discontinued operations (note 5) Commitments and Contingencies (note 11 and 14) Shareholders’ Equity Share capital (note 9) Issued and outstanding 63,185,600 common shares (2003 - 60,094,600 common shares) Contributed surplus Retained earnings See accompanying notes to consolidated financial statements. On behalf of the Board signed C.H. Riddell Director signed J.B. Roy Director 2004 2003 (restated - notes 2 and 5) $ 24,983 107,843 21,564 3,260 - 157,650 1,933,104 (587,298) - 1,345,806 31,621 7,709 $ 1,542,786 $ 16,551 80,710 - 2,255 1,680 101,196 1,444,139 (418,225) 11,393 1,037,307 31,621 7,006 $ 1,177,130 $ 147,508 2,188 - 149,696 459,141 101,486 - 41,044 166,380 - 768,051 $ 109,334 - 2,455 111,789 287,237 61,554 3,959 - 206,684 9,874 569,308 302,932 - 322,107 625,039 $ 1,542,786 200,274 746 295,013 496,033 $ 1,177,130 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN NUAL REP ORT 45 CONSOLIDATED STATEMENTS of EARNINGS and RETAINED EARNINGS Year Ended December 31 (thousands of dollars except per share amounts) Revenue Petroleum and natural gas sales Transportation costs (note 2) Gain (loss) on financial instruments (note 11) Royalties (net of Alberta Royalty Tax Credit) Loss on sale of investments Expenses Operating Interest General and administrative Stock based compensation expense (note 9) Bad debt expense (recovery) Lease rentals Geological and geophysical Dry hole costs (note 6) (Gain) loss on sales of property, plant and equipment Accretion of asset retirement obligations Depletion and depreciation Writedown of petroleum and natural gas properties (note 6) Unrealized foreign exchange gain on US debt Realized foreign exchange gain on US debt (note 8) Premium on redemption of US debt (note 8) Earnings (loss) before income taxes Income and other taxes (note 10) Large Corporations Tax and other Future income tax expense (recovery) Net earnings from continuing operations Net earnings (loss) from discontinued operations (note 5) Net earnings Retained earnings, beginning of period Adjustment on disposition of assets to Paramount Energy Trust (note 4) Dividends declared (note 4) Purchase and cancellation of share capital (note 9) Change in accounting policy (note 2) Retained earnings, end of the year Net earnings from continuing operations per common share - basic - diluted Net earnings (loss) from discontinued operations per common share - basic - diluted Net earnings per common share - basic - diluted Weighted average common shares outstanding (thousands) - basic - diluted See accompanying notes to consolidated financial statements. 46 PARAMOUNT RESOURCES LTD. 20 04 A NNUAL R EP ORT 2004 2003 (restated - notes 2 and 5) $ 581,901 (31,285) 18,693 (105,046) (34) 464,229 $ 464,558 (30,499) (53,204) (82,512) (1,020) 297,323 95,767 25,399 25,247 41,195 (5,523) 3,546 8,728 24,676 (16,255) 6,920 191,578 - (24,188) (7,161) 11,950 381,879 82,350 81,193 19,214 19,051 1,214 5,977 3,574 8,450 36,600 3,640 4,044 165,098 10,418 (1,566) - - 356,907 (59,584) 6,795 40,660 47,455 34,895 6,279 41,174 295,013 - - (14,080) - $ 322,107 2,689 (63,481) (60,792) 1,208 (57) 1,151 355,912 (6,923) (51,000) - (4,127) $ 295,013 $ $ $ $ $ $ 0.58 0.57 0.11 0.10 0.69 0.67 $ $ $ $ $ $ 0.02 0.02 - - 0.02 0.02 59,755 61,026 60,098 60,472 CONSOLIDATED STATEMENTS of CASH FLOWS Year Ended December 31 (thousands of dollars except per share amounts) Operating activities Net earnings from continuing operations Add (deduct) Depletion and depreciation Writedown of petroleum and natural gas properties (Gain) loss on sales of property, plant and equipment Accretion of asset retirement obligations Future income tax (recovery) expense Amortization of other assets Non-cash stock based compensation expense Non-cash gain on financial instruments Unrealized foreign exchange gain on US debt Realized foreign exchange gain on US debt Premium on redemption of US debt Dry hole costs Geological and geophysical costs Cash flow from continuing operations Cash flow from discontinued operations Cash flow from operations Decrease in deferred revenue Asset retirement obligations expenditures Increase in other assets Change in non-cash operating working capital from continuing operations (note 12) Change in non-cash operating working capital from discontinued operations Financing activities Bank loans - draws Bank loans - repayments Shareholder loan Proceeds from US debt offering, net of issuance costs Redemption of US debt Premium on redemption of US debt Realized foreign exchange gain on US debt Capital stock - issued, net of issuance costs Capital stock - purchased and cancelled Discontinued operations Cash flow (used in) provided by operating and financing activities Investing activities Property, plant and equipment expenditures Petroleum and natural gas property acquisitions Proceeds on sale of property, plant and equipment Change in non-cash investing working capital (note 12) Discontinued operations Cash flow used in investing activities Increase (decrease) in cash Cash, beginning of the year Cash, end of the year See accompanying notes to consolidated financial statements. FINANCIAL STATEMENTS 2004 2003 (restated - notes 2 and 5) $ 34,895 $ 1,208 191,578 - (16,255) 6,920 40,660 1,277 41,195 (19,376) (24,188) (7,161) 11,950 24,676 8,728 294,899 667 295,566 (3,959) (1,214) - (27,320) - 263,073 431,951 (298,173) - 162,917 (105,686) (8,864) 7,161 115,043 (19,401) (11,301) 273,647 536,720 (315,698) (322,598) 61,939 27,349 12,288 (536,720) - - - $ 165,098 10,418 3,640 4,044 (63,481) 161 1,214 - (1,566) - - 36,600 8,450 165,786 1,490 167,276 (3,845) - (161) (33,582) 201 129,889 42,933 (477,338) (33,000) 221,447 - - - 10,317 (705) (190) (236,536) (106,647) (224,229) (228) 317,792 14,828 (1,516) 106,647 - - - $ PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 47 NOTES to CONSOLIDATED FINANCIAL STATEMENTS (all tabular amounts expressed in thousands of dollars) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Paramount Resources Ltd. (“Paramount” or the “Company”) is an independent Canadian energy company involved in the exploration, development, production, processing, transportation and marketing of natural gas and oil. The Company’s principal properties are located in Alberta, the Northwest Territories and British Columbia in Canada. The Company also has properties in Saskatchewan and offshore the East Coast in Canada, and in Montana and North Dakota in the United States. The consolidated ﬁnancial statements are stated in Canadian dollars and have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP), which differ in some respects from GAAP in the United States. These differences are quantiﬁed in note 17. The timely preparation of the ﬁnancial statements in conformity with GAAP requires that Management make estimates and assumptions and use judgment regarding assets, liabilities, revenue and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the ﬁnancial statements. Accordingly, actual results could differ from those estimates. (A ) PRI NCI PLES OF CONSOL ID A TION The Consolidated Financial Statements include the accounts of Paramount Resources Ltd. and its subsidiaries, and are presented in accordance with Canadian generally accepted accounting principles. Investments in jointly controlled companies, jointly controlled partnerships (collectively called “afﬁliates”) and unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby the Company’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts. Investments in companies and partnerships in which the Company does not have direct or joint control over the strategic operating, investing and ﬁnancing decisions, but does have signiﬁcant inﬂuence on them, are accounted for using the equity method. (B) J OINT O PERATIONS Certain of the Company’s exploration, development and production activities related to petroleum and natural gas are conducted jointly with others. These consolidated ﬁnancial statements reﬂect only the Company’s proportionate interest in such activities. (C) REVENUE RE COGNITION Revenues associated with the sale of natural gas, crude oil, and natural gas liquids (“NGLs”) owned by the Company are recognized when title passes from the Company to its customer. Revenues from oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest. (D ) SHORT-TERM INVES TMENTS Short-term investments are carried at the lower of cost and market value. Included in short-term investments are short- term deposits bearing interest between 2.15 percent to 2.23 percent, debentures and convertible debentures bearing interest between 6 percent to 8 percent and investments in the common shares and Trust units. (E) PRO PERTY, PLANT AND EQUIP ME NT COST Property, plant and equipment are recorded at cost. The Company follows the successful efforts method of accounting for petroleum and natural gas operations. Under this method the Company capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found of a sufﬁcient quantity to justify completion of the ﬁnd as a producing well. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of well completion. This determination of the success of drilling results corresponds with the time period of reporting proved oil and gas reserves for the ﬁnd. Exploratory wells 48 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS that discover economic reserves that are in areas where a major infrastructure capital expenditure (e.g., a pipeline) would be required before production could begin, or where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory drilling work in the area, remain capitalized as long as the additional exploratory drilling work is under way or ﬁrmly planned. In these situations, the well is considered to have found economic reserves if recoverable reserves have been found of a sufﬁcient quantity to justify completion of the ﬁnd as a producing well, assuming that the major infrastructure capital expenditure had already been made. Once all additional exploratory drilling and testing work has been completed on projects requiring major infrastructure capital expenditures, the economic viability of the overall project is evaluated within one year of the last exploratory well completion. If considered to be economically viable, internal company approvals are then obtained to move the project into the development stage. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond the Company’s control. Exploratory well costs remain suspended as long as the Company is actively pursuing such approvals and permits, and believes they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into development stage, which corresponds with the time period of reporting proved oil and gas reserves for the ﬁnd. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while the Company performs additional drilling work on the potential oil and gas ﬁeld, or seeks government or co-venturer approval of development plans or environmental permitting. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Exploration expenses, including geological and geophysical costs, lease rentals and exploratory dry hole costs, are charged to earnings as incurred. Leasehold acquisition costs, including costs of drilling and equipping successful wells, are capitalized. The net costs of unproductive exploratory wells, abandoned wells and surrendered leases are charged to earnings in the year of abandonment or surrender. Gains or losses are recognized on the disposition of property, plant and equipment. DEPLETION AND DEPRECIATION Capitalized costs of proved oil and gas properties are depleted using the unit of production method. For purposes of these calculations, production and reserves of natural gas are converted to barrels on an energy equivalent basis. Successful exploratory wells and development costs are depleted over proved developed reserves while acquired resource properties with proved reserves are depleted over proved reserves. Acquisition costs of probable reserves are not depleted or amortized while under active evaluation for commercial reserves. Costs are transferred to depletable costs as proved reserves are recognized. At the date of acquisition, an evaluation period is determined after which any remaining probable reserve costs associated with producing ﬁelds are transferred to depletable costs. Costs associated with signiﬁcant development projects are not depleted until commercial production commences. Depreciation of production equipment, gas plants and gathering systems is provided on a straight-line basis over their estimated useful life varying from 12 years to 40 years. Depreciation of other equipment is provided on a declining balance method at rates varying from 4 percent to 30 percent. IMPAIRMENT Producing areas and signiﬁcant unproved properties are assessed annually or as economic events dictate for potential impairment. Any impairment loss is the difference between the carrying value of the asset and its discounted net recoverable amount. (F) ASSET RETIREMENT OB LIGA TION S 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. 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 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 49 liability to the extent of the liability recorded. Differences between the actual costs incurred upon settlement of the asset retirement obligations and the liability recorded are recognized in the Company’s earnings in the period in which the settlement occurs. (G) GOODWILL Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is not amortized and is assessed by the Company for impairment at least annually. Goodwill has been allocated to reporting units within the Company. Impairment is assessed based on a comparison of the fair value of the reporting units compared to the carrying value of the reporting units, including goodwill. Any excess of the carrying value of the reporting units, including goodwill, over and above its fair value is the impairment amount, and is charged to earnings in the period identiﬁed. (H ) F OREIGN CURR ENCY TRA NSL A T ION The Company’s foreign operations are considered integrated and are translated into Canadian dollars using the temporal method. Monetary assets and liabilities denominated in US dollars are translated into Canadian dollars at exchange rates in effect at the balance sheet date. Other assets and liabilities are translated at the rates prevailing at the respective transaction dates. Revenues and expenses are translated at the average monthly rates prevailing during the year. Translation gains and losses are reﬂected in income when incurred. F INANCI AL INSTRUMENT S (I) 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. 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, 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. (J ) MEASUREMENT UNC ER T A INTY The amounts recorded for depletion and depreciation and impairment of petroleum and natural gas properties and equipment, and for asset retirement obligations are based on estimates of reserves, future costs, petroleum and natural gas prices and other relevant assumptions. By their nature, these estimates and those related to the future cash ﬂows used to assess impairment are subject to measurement uncertainty, and the impact on the consolidated ﬁnancial statements of future periods could be material. INCOME T AXES (K) The Company follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between ﬁnancial reporting and income tax basis of assets and liabilities, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net earnings in the period in which the change occurs. F LOW-THROUGH S HARE S (L ) Share capital includes ﬂow-through shares issued pursuant to certain provisions of the Income Tax Act (Canada) (the “Act”). Under the Act, where the proceeds are used for eligible expenditures, the related income tax deductions may be renounced to subscribers. 50 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS As the eligible expenditures are renounced, share capital is reduced by an amount equal to the estimated future income taxes payable by the Company, and the estimated future income tax payable is recorded as an increase to the future income tax liability. (M) STOCK OPTION PL AN The Company has a stock-based compensation plan consisting of a stock option plan that is described in note 9. Options granted under the Company’s employee stock option plan are issued at the current market price on the day prior to issuance. The Company uses the intrinsic value method to account for its stock-based compensation. Applying the intrinsic value method to account for stock-based compensation, a liability for expected cash settlement under the stock-based compensation plan is accrued over the vesting period of the options, based on the difference between the exercise price of the options and the market price of the Company’s common shares. The liability is revalued at the end of each reporting period to reﬂect changes in the market price of the Company’s common shares and the net change is recognized in earnings. When options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When options are exercised for common shares, consideration paid by the option holders and the previously recognized liability associated with the options are recorded as share capital. (N) AMORTIZATION OF OTH E R A S SE TS Amortization of deferred items included in Other Assets is provided for where applicable, on a straight-line basis over their estimated useful life. (O) PER COMMON SH AR E A MOUNT S The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. This method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price during the period. 2. CHANGES IN ACCOUNTING POLICIES ASSET RETIREMENT OBLIGAT IONS Effective January 1, 2004, the Company retroactively adopted, with restatement, the Canadian Institute of Chartered Accountants (“CICA”) recommendation on Asset Retirement Obligations, which requires liability recognition for the fair value of retirement obligations associated with long-lived assets. Prior to January 1, 2004, the estimated future dismantlement and site restoration costs of natural gas and crude oil assets were provided for using the unit-of-production method. As a result of this change, net earnings for the year ended December 31, 2003 decreased by $1.5 million ($0.02 per share). The asset retirement obligations liability as at December 31, 2003 increased by $40.4 million, property, plant and equipment, net of accumulated depletion, increased by $31.1 million, and future income tax liability decreased $3.7 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 obligations, recorded retroactively. FINANCIAL INS TRUMENTS 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. Prior to January 1, 2004, Paramount had designated its derivative ﬁnancial instruments as hedges. As at January 1, 2004, the Company had elected not to designate any of its ﬁnancial instruments as hedges under AcG 13 and has fair-valued the derivatives and recognized the gains and losses on the consolidated balance sheet and statement of earnings. The impact PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 51 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 11). TRA NS PO RTATION COS TS Effective for ﬁscal years beginning on or after October 1, 2003, the CICA issued Handbook Section 1100 “Generally Accepted Accounting Principles”, which deﬁnes the sources of GAAP that companies must use and effectively eliminates industry practice as a source of GAAP. In prior years, it had been industry practice for companies to net transportation charges against revenue rather than showing transportation as a separate expense on the income statement. Beginning January 1, 2004, the Company has recorded revenue gross of transportation charges and a transportation expense on the statement of earnings. Prior periods have been reclassiﬁed for comparative purposes. This adjustment has no impact on net income or cash ﬂow. STO CK -BASED COMPENSATION A ND OTH E R S TOC K -B A SED PA Y M ENTS The Company has an Employee Incentive Stock Option plan (the “plan”). Prior to 2004, the Company applied the fair value method to account for its stock based compensation plan. During 2004, the Company reviewed its historical practices and determined that the Company has generally settled in cash when the option holder requested cash upon exercise of their options. Accordingly, in 2004, the Company has prospectively adopted the intrinsic value method to account for its stock- based compensation (see note 9). 3. ACQUISITION OF OIL AND GAS PROPERTIES $1 85 MILLIO N ASSET A CQUISIT ION 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 asset retirement obligation liability related to those properties. The following table summarizes the fair value of the net assets acquired: Property, plant and equipment Less: Asset retirement obligations $ 211,947 26,847 $ 185,100 $8 7 MILLION ASSET ACQUIS IT ION On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for $86.9 million, after adjustments. The asset retirement obligations associated with these assets is $2.1 million. In accounting for the acquisition, the Company recorded a future tax asset in the amount of $89.0 million. 4. DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST During the ﬁrst quarter of 2003, the Company completed the formation and structuring of Paramount Energy Trust (the “Trust”) through the following transactions: a) b) 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. 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. 52 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS As the transfer of the Initial Assets and the Additional Assets (collectively the “Trust Assets”) represented a related party transaction not in the normal course of operations involving two companies under common control, the transaction has been accounted for at the net book value of the Trust Assets as recorded in the Company. Details are as follows: Natural gas properties Future income tax liability Site restoration liability Costs of disposition Charge to retained earnings Net proceeds on disposition $ 244,433 4,070 (5,900) 10,430 (6,638) $ 246,395 In connection with the creation and ﬁnancing of the Trust and the transfer of natural gas properties to the Trust, the Company incurred costs of approximately $10.4 million. These costs have been included as a cost of disposition. During 2003, the Company disposed of a minor non-core property to the Trust. The related party transaction was accounted for at the net book value of the assets, with a charge 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 percent interest in Shehtah Wilson Drilling Partnership for approximately $1.0 million. For reporting purposes, the drilling partnership has been accounted for as discontinued operations. On December 13, 2004, Paramount completed the disposition of a building acquired as part of the Summit acquisition, for approximately $10.5 million, inclusive of the mortgage assumed by the purchaser of $6.4 million. Selected ﬁnancial information of the discontinued operations for the year ended December 31: Shehtah Wilson Wilson Drilling Ltd. Drilling Partnership 2003 2003 2004 2004 Building Total 2004 2003 2004 2003 $ 908 $ 1,390 $ 327 $ 622 $ - $ - $ 1,235 Revenue Other Income Expenses Interest General and administrative Depreciation 250 642 655 319 270 898 (Gain) loss on sale of property and equipment (6,659) (5,112) 20 1,507 - 384 6 (27) 363 - 496 6 367 (308) 278 383 (1,133) 300 617 718 939 $ 2,012 - 702 (367) 1,204 - 502 (2,569) (2,232) - (450) (9,255) (6,981) 20 1,559 Net earnings (loss) before income tax Large Corporation Tax and other Future income tax expense Net earnings (loss) from discontinued operations 6,020 (117) (36) 120 2,232 450 8,216 1,857 94 - 324 - - - - (34) 20 186 - 1,823 114 453 186 324 $ 4,069 $ (441) $ (36) $ 120 $ 2,246 $ 264 $ 6,279 $ (57) PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 53 Shehtah Wilson Wilson Drilling Ltd. Drilling Partnership Dec-31 Dec-31 2003 2004 Dec-31 2004 Dec-31 2003 Building Total Dec-31 2004 Dec-31 2003 Dec-31 2004 Dec-31 2003 Current Assets Accounts Receivable Prepaid Expenses Property, plant and equipment, net Current Liabilities Accounts payable and accrued liabilities Current portion of long-term debt Long-term debt $ $ - - - - - - $ $ - - 3,234 - 1,138 $ 3,456 $ - - - - - - $ 1,653 27 $ 62 1,005 - - $ $ - - - - - - $ $ - - 8,097 - - - $ 1,653 27 11,393 - - 1,005 312 $ 6,418 $ - - 1,450 $ 9,874 6. PROPERTY PLANT AND EQUIPMENT Petroleum and natural gas properties Gas plants, gathering systems and production equipment Other Assets held for sale Net book value 2004 Cost Accumulated Depletion and Depreciation 2003 Cost $ 1,351,950 $ 450,518 (restated - notes 2 and 5) 986,919 $ Accumulated Depletion and Depreciation (restated - notes 2 and 5) 307,156 $ 548,838 32,316 - 1,933,104 $ $ 127,724 9,056 - 587,298 436,772 20,448 14,865 1,459,004 $ $ 1,037,307 101,120 9,949 3,472 421,697 $ $ 1,345,806 Capital costs associated with non-producing petroleum and natural gas properties totaling approximately $300 million (2003 – $209 million) are currently not subject to depletion. For the year ended December 31, 2004, the Company expensed $24.7 million in dry hole costs (2003 - $36.6 million). A portion of the dry hole costs expensed related to prior year capital projects that were determined in the current year to have no future economic value. For the year ended December 31, 2004, the Company recorded a provision of $ nil (2003 - $10.4 million) in respect of impairment of petroleum and natural gas properties. 54 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS 7. ASSET RETIREMENT OBLIGATIONS The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of the Company’s oil and gas properties. Year Ended December 31 Asset retirement obligation, beginning of year Liabilities incurred Liabilities settled Accretion expense Asset retirement obligation, end of year 2004 2003 (restated - notes 2 and 5) $ 61,554 36,812 (3,800) 6,920 $ 101,486 $ 53,625 3,885 - 4,044 $ 61,554 The undiscounted asset retirement obligations at December 31, 2004 are $136.2 million (December 31, 2003 - $104.8 million). The Company’s credit-adjusted risk-free rate is 7.875 percent. These obligations will be settled based on the useful life of the underlying assets, the majority of which are not expected to be paid for several years, or decades, in the future and will be funded from general company resources at the time of removal. 8. LONG-TERM DEBT As at December 31, long-term debt was comprised of: 7 7/8% US Senior Notes due 2010 (US$133.3 million) 8 7/8% US Senior Notes due 2014 (US$81.3 million) Credit facility – current interest rate of 3.8% (2003 - 4.5%) 2004 $ 160,174 97,662 201,305 $ 459,141 2003 (restated - notes 2 and 5) $ 226,887 - 60,350 $ 287,237 SENIOR N OTES The Company issued US$175 million of 7 7/8 percent Senior Notes due 2010 on October 27, 2003. Interest on the notes is payable semi-annually, beginning in 2004. The Company may redeem some or all of the notes at any time after November 1, 2007 at redemption prices ranging from 100 percent to 103.938 percent of the principal amount, plus accrued and unpaid interest to the redemption date, depending on the year in which the notes are redeemed. In addition, the Company may redeem up to 35 percent of the notes prior to November 1, 2006 at 107.875 percent of the principal amount, plus accrued interest to the redemption date, using the proceeds of certain equity offerings. The notes are unsecured and rank equally with all of the Company’s existing and future senior unsecured indebtedness. The Company incurred $7.4 million of ﬁnancing charges related to the issuance of the Senior Notes. The ﬁnancing charges are capitalized to other assets and amortized straight line over the term of the notes. 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 Company incurred $4.8 million of ﬁnancing charges related to the issuance of the Senior Notes. The ﬁnancing charges related to the issuance of the Senior Notes are capitalized to other assets and amortized straight line over the term of the notes. On December 30, 2004, pursuant to Paramount’s 7 7/8 percent and 8 7/8 percent Senior Notes, Paramount redeemed US$41.7 million aggregate principal amount of its 7 7/8 percent Senior Notes due 2010 and US$43.8 million aggregate principal amount of its 8 7/8 percent Senior Notes due 2014. The redemption price was US$1,078.75 per US$1,000 principal amount of the 7 7/8 percent Senior Notes and US$1,088.75 per US $1,000 principal amount of the 8 7/8 percent Senior Notes plus, in each case, accrued and unpaid interest on the amount being redeemed to the redemption date. The PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 55 premium paid on redemption of the notes of US$7.2 million was charged to earnings. The realized foreign exchange gain on redemption was $7.2 million. Other assets decreased by $3.1 million to reﬂect the reduction in deferred ﬁnancing costs upon redemption of the Senior Notes. CR ED IT FACILITY As at December 31, 2004, the Company had a $270 million committed revolving/non-revolving term facility with a syndicate of Canadian 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 has requested and received approval for an extension on the revolving credit facility of 364 days. Advances drawn on the facility are secured by a ﬁxed charge over the assets of the Company. In February 2005, the Company’s borrowing capacity under this facility was increased to $330 million as a result of the Company’s Senior Notes redemption on December 30, 2004, and an increase in the value of its oil and natural gas reserves. The Company has letters of credit totaling $28.1 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. 9. SHARE CAPITAL AUTH ORIZED 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. Common Shares Balance December 31, 2002 Stock options exercised during the year Shares repurchased - at carrying value Balance December 31, 2003 Shares repurchased - at carrying value Stock options exercised Common shares issued, net of issuance costs Flow through shares issued, net of issuance costs Tax adjustment on share issuance costs and flow-through share renunciations Balance December 31, 2004 Number Consideration $ 190,193 10,317 (236) $ 200,274 (5,322) 3,057 54,901 57,981 (7,959) $ 302,932 59,458,600 710,000 (74,000) 60,094,600 (1,629,500) 220,500 2,500,000 2,000,000 - 63,185,600 I SSUE D CAPIT AL 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 year ended December 31, 2004, $14.1 million has been charged to retained earnings related to the share repurchase price in excess of the carrying value of the shares. 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 were $59 million. As at December 31, 2004, the Company had made renunciations of $23.7 million. On October 26, 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 were $57.5 million. Between January 1, 2005 and March 7, 2005, 101,050 stock options exercised for cash consideration of $1.8 million. Another 707,200 stock options were exercised for shares which will reduce the stock based compensation liability by approximately $10.4 million. 56 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS STOCK OPTION PL AN The Company has an Employee Incentive Stock Option plan (the “plan”). Under the plan, stock options are granted at the current market price on the day prior to issuance. Participants in the plan, upon exercising their stock options, may request to receive either a cash payment equal to the difference between the exercise price and the market price of the Company’s common shares or common shares issued from Treasury. Irrespective of the participant’s request, the Company may choose to only issue common shares. Cash payments made in respect of the plan are charged to general and administrative expenses when incurred. Options granted vest over four years and have a four and a half year contractual life. As at December 31, 2004, 5.0 million shares were reserved for issuance under the Company’s Employee Incentive Stock Option Plan, of which 3.2 million options are outstanding, exercisable to May 31, 2009, at prices ranging from $8.91 to $26.29 per share. Stock options 2004 2003 Balance, beginning of year Granted Exercised Cancelled Balance, end of year Options exercisable, end of year Average Grant Price 9.64 17.09 9.97 9.09 10.41 10.26 $ $ $ Options 3,632,000 348,000 (618,500) (149,000) 3,212,500 1,282,875 Average Grant Price 14.25 9.66 14.29 10.30 9.64 10.72 $ $ $ Options 1,949,500 2,998,000 (791,000) (524,500) 3,632,000 1,087,875 The formation of Paramount Energy Trust (note 4) resulted in the Company re-pricing stock options. 941,500 stock options issued in 2001, the majority of which were at exercise prices of $14.50 and $13.35 per option, were re-priced to exercise prices of $10.22 and $9.07 per option, respectively. The following summarizes information about stock options outstanding at December 31, 2004: Exercise Prices $8.91-9.80 $10.01-12.02 $12.51-26.29 Total Outstanding Number 2,088,000 820,500 304,000 3,212,500 Weighted Average Weighted Average Exercise Price 9.02 11.04 18.01 $ 10.41 Contractual Life 3 1 4 2 $ Exercisable Exercisable Weighted Average Exercise Price 9.00 11.25 - $ 10.26 Number 561,375 721,500 - 1,282,875 $ During 2004, the Company paid $2.9 million (2003 – less than $0.1 million) related to stock options exercised for cash. FAIR VALUES In 2004, the Company prospectively adopted the intrinsic value method to account for its stock-based compensation. The Company recognized compensation costs related to stock options issued and outstanding of $41.2 million (2003 - $1.2 million). Prior to 2004, the fair values of common share options granted were estimated as at the grant date using the Black- Scholes option pricing model. The weighted average fair value of the options granted during 2003 was $3.42, calculated using a risk-free rate of 5.8 percent, an estimated life of 4 years and an estimated volatility of 39 percent. PER SHARE INFORMATION Basic earnings per share are calculated based on a weighted average number of common shares of 59,755,480 (2003 – 60,098,447). There are no anti-dilutive options at December 31, 2004. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 57 10. INCOME TAXES The income tax provision differs from the expected income taxes obtained by applying the Canadian corporate tax rate to earning (loss) before taxes as follows: Corporate tax rate Calculated income tax expense (recovery) Increase (decrease) resulting from: Non-deductible Crown charges, net of Alberta Royalty Tax Credit Federal resource allowance Federal and provincial income tax rate adjustment Attributed Canadian Royalty Income recognized Large Corporations Tax and other Non-taxable portion of gain on sale of investments Stock based compensation Recognition of tax pools not previously recognized Other Income tax expense (recovery) COMPONENTS OF FUTURE INC OME TA X E S The net future tax liability comprises: Differences between tax base and reported amounts of depreciable assets Asset retirement obligations Stock-based compensation liability Other 2004 39.04% 32,150 $ 2003 40.67% (24,233) $ 25,455 (21,787) 481 (1,469) 6,795 (4,301) 3,205 - 6,926 47,455 $ 21,991 (17,124) (30,257) (5,228) 2,875 - - (3,343) (5,473) (60,792) $ 2004 $ 215,583 (34,281) (12,405) (2,517) $ 166,380 2003 $ 227,697 (23,486) - 2,473 $ 206,684 11. FINANCIAL INSTRUMENTS As disclosed in note 2, on January 1, 2004, the fair value of all outstanding ﬁnancial instruments that were no longer designated as accounting hedges, were recorded on the consolidated balance sheet with an offsetting net deferred gain. The net deferred gain is recognized into net earnings over the life of the associated contracts. 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. The estimated fair value of all ﬁnancial instruments is based on quoted prices or, in the absence of quoted prices, 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 December 31, 2004. December 31 Financial instrument asset Financial instrument liability Net financial instrument asset 2004 21,564 (2,188) 19,376 $ $ 58 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS Year Ended December 31, 2004 Fair value of contracts, January 1, 2004 Change in fair value of contracts recorded on transition, still outstanding at December 31, 2004 Amortization of the fair value of contracts as at December 31, 2004 Fair value of contracts entered into during the period Unrealized gain (loss) on financial instruments Realized loss on financial instruments for the year ended December 31, 2004 Net gain on financial instruments for the year ended December 31, 2004 Net Deferred Amounts on Mark-to Market Transition Gain (Loss) 1,450 $ (1,450) $ Total - $ - (196) - (1,646) 1,301 - 18,271 $ 21,022 1,301 (196) 18,271 $ 19,376 $ (683) $ 18,693 INTEREST RATE CONTRA C TS (A) On June 6, 2004, the Company entered into a ﬁxed to ﬂoating interest rate swap. The fair value of this contract as at December 31, 2004, was a gain of $3.3 million. Description of Swap Transaction Swap of 7 7/8% US$ Senior Notes Maturity Date November 1, 2010 Notional Amount US$175 million Indenture Interest US$ fixed Swap to US$ floating Effective Rate US$ LIBOR plus 320 Basis Points (B) FOREIGN EXC HANGE CONTR A C TS The Company has entered into the following currency index swap transactions, ﬁxing the exchange rate on receipts of US$1 million each month at CDN$1.4337, expiring December 31, 2005. The US$/CDN$ closing exchange rate was 1.2020 as at December 31, 2004 (December 31, 2003 – 1.2965). Year of settlement 2005 US dollars 12,000 Weighted average exchange rate 1.4337 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 December 31, 2004, was a gain of $2.7 million. The change in fair value, a $0.6 million loss, and $1.6 million amortization of the deferred gain have been recorded in the consolidated statement of earnings. During November 2004, the Company entered into a series of US$/CDN$ put/call options. The fair value of these contracts as at December 31, 2004 was a gain of $0.8 million. Put/Call Put Call Put Call Strike 1.2048 1.1765 1.1976 1.1628 Foreign Exchange Option Currencies USD/CDN USD/CDN USD/CDN USD/CDN Notional - CDN$ $ 60,240,000 $ 58,825,000 $ 59,880,000 $ 58,140,000 Expiry Date January 12, 2005 January 12, 2005 January 10, 2005 January 10, 2005 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 59 (C) COMMO DITY PRICE CONT R A C T S At December 31, 2004, the Company has entered into ﬁnancial forward contracts as follows: Sales Contracts NYMEX Fixed Price NYMEX Fixed Price NYMEX Fixed Price AECO Fixed Price AECO Fixed Price AECO Fixed Price NYMEX Call Option AECO Fixed Price AECO Fixed Price AECO Fixed Price Purchase Contracts AECO Fixed Price Amount Price Term 10,000 MMbtu/d 10,000 MMbtu/d 10,000 MMbtu/d 20,000 GJ/d 20,000 GJ/d 20,000 GJ/d 20,000 MMbtu/d 20,000 GJ/d 20,000 GJ/d 20,000 GJ/d 6.41 US$ 7.46 US$ 7.95 US$ 7.90 $ 8.03 $ $ 7.60 US$ 10.00 Strike 6.28 $ 6.30 $ 6.80 $ November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 November 2004 - March 2005 December 2004 - March 2005 April 2005 - June 2005 April 2005 - June 2005 April 2005 - June 2005 20,000 GJ/d $ 6.76 November 2004 - March 2005 The fair values of these contracts as at December 31, 2004 was a $14.2 million gain. 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 deferred loss has been fully amortized as at December 31, 2004. (D ) F AI R VALUES OF FINANCIA L A SS ET S A ND L IA B IL ITI ES Borrowings under bank credit facilities and the issuance of commercial paper are for short periods and are market rate based, thus, carrying values approximate fair value. Fair values for derivative instruments are determined based on the estimated cash payment or receipt necessary to settle the contract at year-end. Cash payments or receipts are based on discounted cash ﬂow analysis using current market rates and prices available to the Company. (E) CREDI T 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 risk. INTEREST RATE RISK (F ) The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company’s debts that have a ﬂoating interest rate. 60 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT 12. CHANGE IN NON-CASH WORKING CAPITAL Change in non-cash working capital: Short-term investments Accounts receivable Prepaid expenses Accounts payable and accrued liabilities Discontinued operations Operating activities Investing activities FINANCIAL STATEMENTS 2004 2003 $ $ (10,532) (25,480) (978) 37,019 - 29 (27,320) 27,349 29 $ $ (283) 6,859 1,829 (26,958) (201) (18,754) (33,582) 14,828 (18,754) Certain changes in non-cash working capital which were incurred as a result of asset dispositions during the year have been excluded from the above amounts. Amounts paid during the year related to interest and Large Corporations and other taxes were as follows: Interest paid Large Corporations and other taxes paid, including settlements 13. RELATED PARTY TRANSACTIONS 2004 18,951 31,021 $ $ 2003 17,497 2,395 $ $ DISPOSITION OF ASSET S TO P A RA MOU NT E NER G Y T R US T On December 13, 2004, the Company completed the disposition of a building to Paramount Energy Trust. The transaction has been recorded at the exchange amount. The Company received proceeds of $10.5 million, inclusive of the mortgage assumed by the purchaser of $6.4 million. In the ﬁrst quarter of 2003, the Company sold certain natural gas assets in Northeast Alberta to the Trust, a related party. The transaction (see note 4), was accounted for at the net book value of the assets as recorded in the Company. 14. CONTINGENCIES AND COMMITMENTS CONT ING ENCIES The Company is party to various legal claims associated with the ordinary conduct of business. The Company does not anticipate that these claims will have a material impact on the Company’s ﬁnancial position. The Company indemniﬁes its directors and ofﬁcers against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law. The Company has acquired and maintains liability insurance for its directors and ofﬁcers. COMM ITMENTS As at December 31, 2004, the Company has the following pipeline transportation commitments: Year 2005 2006 2007 2008 2009 Thereafter $ Commitment 22,015 21,252 21,252 21,252 20,823 130,611 $ 237,205 PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 61 At December 31, 2004, the Company has entered into the following physical delivery natural gas contracts: Sales Contracts Station 2 Fixed Price Station 2 Fixed Price 15. COMPARATIVE FIGURES Amount Price Term 8,000 GJ/d 12,000 GJ/d $ $ 7.99 8.00 November 2004 - March 2005 November 2004 - March 2005 Certain comparative ﬁgures have been reclassiﬁed to conform to the current year’s ﬁnancial statement presentation. 16. SUBSEQUENT EVENTS TRU ST SPINOUT On September 27, 2004, the Board of Directors of Paramount authorized management of Paramount to undertake an examination of possible corporate restructuring alternatives available to Paramount to increase shareholder value, 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. On December 13, 2004, Paramount announced that its board of directors had unanimously approved a proposed reorganization which would result in Paramount’s shareholders receiving in exchange for their Common Shares, one New Common Share of Paramount and one Trust Unit of the Trust, Trilogy Energy Trust (“Trilogy”). Trilogy will indirectly own certain of Paramount’s existing assets. The assets intended to become indirectly owned by Trilogy, referred to as the “Spinout Assets,” are located in the Kaybob and Marten Creek areas of Alberta. In order to implement any proposed reorganization of Paramount, the Company required the consent of the majority holders of each of its 2010 Notes in the aggregate principal amount of US$175 million and its 2014 Notes in the aggregate principal amount of US $125 million. Consent from note holders was obtained on February 7, 2005. A special meeting of securityholders required for approval of the spinout transaction has been scheduled on March 28, 2005. The Trust Spinout is to be effected through an arrangement under the Business Corporations Act (Alberta) and Paramount obtained an interim order from the Court of Queen’s Bench of Alberta regarding the meeting on February 28, 2005. NOTES OFFERING On February 7, 2005, Paramount completed the Notes Offer, as amended, issuing US$213,593,000 principal amount of 2013 Notes and paying aggregate cash consideration of approximately US$36.2 million in exchange for approximately 99.31 percent of the outstanding 2010 Notes and 100 percent of the outstanding 2014 Notes. As a result, US$913,000 principal amount of the 2010 Notes and no 2014 Notes remain outstanding. The 2013 Notes bear interest at a rate of 8 1/2 percent per year and mature on January 31, 2013. The 2013 Notes will be secured by approximately 80 percent of the Trust Units that will be owned by Paramount following the completion of the Trust Spinout; however, Paramount may sell such Trust Units provided it makes an offer to the holders of the 2013 Notes to purchase 2013 Notes with the next proceeds of any sales at par plus a redemption premium of up to 4 1/4 percent depending on when the offer is made. The 2013 Notes cannot be redeemed with proceeds of equity offerings, but Paramount may, at its option, redeem all or part of the 2013 Notes after January 31, 2007 at par plus a redemption premium up to 4 1/4 percent depending on when the notes are redeemed. If holders of a majority in aggregate principal amount of the 2013 Notes provide notice on September 30, 2005 that they elect to increase the interest rate on the 2013 Notes to 10 1/2 percent per year, Paramount may, at its option, at any time on or prior to January 31, 2006, redeem all of the 2013 Notes at par. GAS MARKETING LIMITED PA R TNER SH IP Paramount closed a transaction in March 2005 whereby it acquired an indirect 25 percent ownership interest in a gas marketing limited partnership for US$5 million. In conjunction with the acquisition of the ownership interest, Paramount will make available for delivery an average of 150 million GJ/d of natural gas over a ﬁve year term, to be marketed on Paramount’s behalf by the gas marketing limited partnership. 62 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS 17. RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED PRINCIPLES The consolidated ﬁnancial statements have been prepared in accordance with Canadian GAAP. Any differences in accounting principles as they pertain to the accompanying ﬁnancial statements are not material except as described below. The application of US GAAP would have the following effects on the Company’s historical net earnings (loss) as reported: Year ended December 31 Net earnings for the year as reported Adjustments, net of tax Forward foreign exchange contracts and other financial instruments (a) Impairments and related change in depletion (c) General and administrative (i) Short-term investments (f) Future income taxes (b) Earnings from discontinued operations (e) Earnings before discontinued operations and change in accounting policy Earnings from discontinued operations (e) Change in accounting policy - Asset Retirement Obligation (d) Net earnings for the year - US GAAP Net earnings per common share before discontinued operations and change in accounting policy - US GAAP Basic Diluted Net earnings per common share - US GAAP Basic Diluted 2004 $ 41,174 2003 (restated - notes 2 and 5) 1,151 $ (1,053) 5,385 - 929 (5,633) - 40,802 - - 40,802 0.68 0.67 0.68 0.67 3,411 11,546 703 428 - (8,593) 8,646 8,593 (4,127) 13,112 0.14 0.14 0.22 0.22 $ $ $ $ $ $ $ $ $ $ $ $ The application of US GAAP would have the following effect on the balance sheet at December 31: Assets Short-term investments (f) Financial instrument assets (a) Property, plant and equipment (c)(d) Liabilities Accounts payable and accrued liabilities (b) Deferred hedging loss (a) Financial instrument liability (a) Deferred revenue (a) Future income taxes (a)(b)(c)(f) Shareholders’ equity Common shares (b) Retained earnings 2004 2003 As Reported US GAAP $ 24,983 21,564 1,345,806 $ 27,149 18,271 1,350,286 As Reported (restated - notes 2 and 5) 16,551 - 1,037,307 $ US GAAP $ 17,265 - 1,033,373 147,508 - 2,188 - 166,380 152,893 - 542 - 167,587 109,334 - - 3,959 206,684 109,334 1,726 - - 206,570 302,932 322,107 303,180 324,253 $ $ 200,274 295,013 200,274 298,295 $ $ PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 63 (A ) F ORWARD FOREIGN EX C H A NGE C ONT R A C TS A ND OTHER FINAN CIAL INST RUME NT S Prior to January 1, 2004, Paramount had designated, for Canadian GAAP purposes, its derivative ﬁnancial instruments as hedges of anticipated revenue and expenses. In accordance with Canadian GAAP, payments or receipts on these contracts were recognized in income concurrently with the hedged transaction. Accordingly, the fair value of contracts deemed to be hedges was not previously reﬂected in the balance sheet, and changes in fair value were not reﬂected in earnings. As disclosed in note 2 of the consolidated ﬁnancial statements as at and for the year ended December 31, 2004, effective January 1, 2004, the Company has elected not to designate any of its ﬁnancial instruments as hedges for Canadian GAAP purposes, thus eliminating this US/Canadian GAAP difference in future periods. For US purposes, the Company has adopted Statement of Financial Accounting Standards (‘‘SFAS’’) No. 133, as amended, “Accounting for Derivative Instruments and Hedging Activities”. With the adoption of this standard, all derivative instruments are recognized on the balance sheet at fair value. The statement requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless speciﬁc hedge accounting criteria are met. Under US GAAP for the year ended December 31, 2004, the deferred ﬁnancial instrument asset of $3.3 million and the deferred ﬁnancial instrument liability of $1.8 million described in note 2 of the consolidated ﬁnancial statements as at December 31, 2004 would not be recorded for US GAAP purposes. Amortization of the deferred ﬁnancial instrument asset and liability would be recognized in earnings under Canadian GAAP. The remaining unamortized amount of $1.6 million (net of tax - $1.1 million) has been reﬂected as a retained earnings adjustment as this has been reﬂected in earnings in prior years US GAAP reconciliations. Under US GAAP for the year ended December 31, 2004, an additional expense of $1.6 million (net of tax - $1.1 million) would have been recorded to adjust for the deferred ﬁnancial instruments assets and liabilities amortization. Under US GAAP for the year ended December 31, 2003, additional income of $5.7 million (net of tax - $3.4 million) would have been recorded. (B) F UTU RE INCOME TAXES The Canadian liability method of accounting for income taxes is similar to the United States Statement of Financial Accounting Standard No. 109 ‘‘Accounting for Income Taxes’’, which requires the recognition of future tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s ﬁnancial statements or tax returns. Pursuant to US GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates. For the years ended December 31, 2004 and 2003, this difference did not impact the Company’s ﬁnancial position or results of operations except for the Company’s accounting for a ﬂow-through share issuance in October 2004. For Canadian GAAP, upon renunciation of tax pools, an adjustment is made to share capital and future income tax liabilities. Under SFAS 109, the proceeds from the issuance of ﬂow through shares should be allocated between the offering of shares and the sale of tax beneﬁts. The allocation is made based on the difference between the quoted price of the existing shares and the amount the investor pays for the shares. A liability is recognized for this difference. The liability is reversed when tax beneﬁts are renounced and a deferred tax liability is recognized at the time. Income tax expense is the difference between the amount of the future tax liability and the liability recognized on issuance. As at and for the year ended December 31, 2004, share capital would increase by $0.2 million, accounts payable and accrued liabilities would increase $5.4 million, and future income tax expense would increase $5.6 million. (C) PRO PERTY, PLANT AND EQUIP ME NT Under both US and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under US GAAP, if the sum of the expected future cash ﬂows (undiscounted and without interest charges) is less than the carrying amount of the asset, then an impairment loss (the amount by which the carrying amount of the asset exceeds the fair value of the asset) should be recognized. Fair value is calculated as the present value of estimated expected future cash ﬂows. Prior to January 1, 2004, under Canadian GAAP, the impairment loss was the difference between the carrying value of the asset and its net recoverable amount (undiscounted). Effective January 1, 2004, the CICA implemented a new pronouncement on impairment of long-lived assets, which eliminated the US/Canadian GAAP difference going forward. For the year ended December 31, 2004, no impairment change would be recorded and a reduction in depletion expense of $8.4 million (net of tax - $5.4 million) would be recorded due to impairment charges recorded in ﬁscal 2002 and 2001. 64 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS For the year ended December 31, 2003, no impairment charge would be recorded and a reduction in depletion expense of $19.2 million (net of tax - $11.5 million) would be recorded due to impairment charges recorded in ﬁscal 2002 and 2001 under US GAAP. The resulting differences in recorded carrying values of impaired assets result in further differences in depreciation, depletion and amortization expense in subsequent years. SUSPENDED WELLS In September 2004, the EITF discussed Issue No. 04-9, “Accounting for Suspended Well Costs,” as it relates to SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” SFAS No. 19 requires that the costs of exploratory wells be capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered. The discussion centered on whether certain circumstances would permit the continued capitalization of the costs for an exploratory well beyond one year, in the absence of plans for another exploratory well. The EITF removed the issue from its agenda, and requested that the FASB consider an amendment to SFAS No. 19 to clarify when it is permissible to continue to capitalize exploratory well costs beyond one year if (a) the well had found a sufﬁcient quantity of reserves to justify its completion as a producing well, assuming the required capital expenditures would be made, and (b) the company was making sufﬁcient progress assessing the reserves and the economic and operating viability of the project. In February 2005, the FASB posted FASB Staff Position (FSP) FAS No. 19-a, “Accounting for Suspended Well Costs,” on its Web site for comment. The proposed FSP provides for continued capitalization past one year if a company is making sufﬁcient progress on assessing the reserves and the economic and operating viability of the project. The proposed FSP also provides disclosure requirements about capitalized exploratory well costs. We estimate that if the proposed FSP were adopted prospectively on January 1, 2003, net income would not have changed in 2004 or 2003. We believe that the adoption of the FSP as proposed would not result in the write-off of any well suspended as of December 31, 2004. We plan to continue to monitor the deliberations of the FASB on this issue. The following table reﬂects the net changes in suspended exploratory well costs during 2004 and 2003. (millions of dollars) Beginning balance at January 1 Additions pending the determination of proved reserves Reclassifications to proved properties Charged to dry hole expense Wells sold during the period Ending balance at December 31 2004 46 110 (24) (14) - 118 $ $ 2003 99 15 (18) (23) (27) 46 $ $ The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. (millions of dollars) Capitalized exploratory costs that have been capitalized for a period of one year or less Capitalized exploratory costs that have been capitalized for a period of greater that one year Balance at December 31 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year $ $ 2004 86 32 118 23 $ $ 2003 19 27 46 29 Included in total suspended well costs at year-end 2004 were 23 wells totaling $32 million related to areas where major capital expenditures and further exploratory drilling is required to classify the reserves as proved. These costs were suspended between 1999 and 2003. At December 31, 2004, $12 million of the costs related to Colville Lake in the Northwest Territories. The commerciality of the gas is being evaluated in conjunction with the upcoming drilling program and the completion of the Mackenzie Valley Gas Pipeline. The remaining $20 million relate to projects where infrastructure decisions are dependent on environmental permitting and production capacity, or where we are continuing to assess reserves and their potential development. At December 31, 2004, we did not have any amounts suspended that were associated with areas not requiring major capital expenditures before production could begin, where more than one year had elapsed since the completion of drilling. PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 65 (D ) A SSET RETIREMENT OB LIGA TIONS Effective January 1, 2004, the Company has retroactively adopted, with restatement, the CICA recommendations on Asset Retirement Obligations. For US GAAP purposes, the Company has adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, effective January 1, 2003. For US GAAP, the cumulative impact upon adoption of SFAS No. 143 for the year ended December 31, 2003, is a $6.9 million (net of tax - $4.1 million) charge to earnings (loss) or $0.07 per basic and diluted common share. For Canadian GAAP purposes, upon adoption on January 1, 2004, the retroactive effect of this pronouncement on prior years was reﬂected in opening retained earnings for the earliest period presented. (E) D ISCONTINUED OPERA T IONS Under US GAAP, the transaction resulting in the disposal of the Trust Assets to Paramount Energy Trust as described in note 4 of the consolidated ﬁnancial statements for the year-ended December 31, 2003 would be accounted for as discontinued operations as the applicable criteria set out in SFAS 144, ‘‘Accounting for Impairment or Disposal of Long-Lived Assets’’ had been met. Accordingly, the carrying value of the Trust Assets is separately presented in the consolidated balance sheet. Net income from discontinued operations for the year ended December 31, 2003 would have been $12.9 million (net of tax - $8.6 million), or $0.14 per basic and diluted common share. (F ) SHORT-TERM INVES TMENTS Under US GAAP, equity securities that are bought and sold in the short term are classiﬁed as trading securities. Unrealized holding gains and losses related to trading securities are included in earnings as incurred. Under Canadian GAAP, these gains and losses are not recognized in earnings until the security is sold. As at December 31, 2004, the Company had unrealized holding gains of $2.2 million (net of tax - $1.4 million). As at December 31, 2003, the Company had unrealized holding gains of $0.7 million (net of tax - $0.4 million). (G) OTHER COM PREHENS IV E INC OME Under US GAAP, certain items such as the unrealized gain or loss on derivative instrument contracts designated and effective as cash ﬂow hedges are included in other comprehensive income. In these ﬁnancial statements, there are no comprehensive income items other than net earnings. (H ) STATEMENT S OF CASH F LOW The application of US GAAP would change the amounts as reported under Canadian GAAP for cash ﬂows provided by (used in) operating, investing or ﬁnancing activities. For US GAAP, dry hole costs of $24.7 million (2003 - $36.6 million) are not added back in calculating cash ﬂow from operations. For Canadian GAAP, the consolidated statements of cash ﬂow include, under investing activities, changes in working capital for items not affecting cash, such as accounts payable related to the non-cash elements of property and equipment. For US GAAP, for the year ended December 31, 2004, there would be a reduction of $27.3 million (2003 – reduction of $14.8 million). The presentation of cash ﬂow from operations is a non US GAAP terminology. STO CK-BASED COMPENSA T ION (I) The Company has granted stock options to selected employees, directors and ofﬁcers. For US GAAP purposes, SFAS 123, “Accounting for Stock-Based Compensation”, requires that an enterprise recognize, or at its option, disclose the impact of the fair value of stock options and other forms of stock-based compensation cost. 66 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT FINANCIAL STATEMENTS The following table summarizes the pro forma effect on earnings had the Company recorded the fair value of options granted: Year ended December 31 Net earnings for the period – US GAAP Stock-based compensation expense determined under the fair value based method for all awards, net of related tax effects Pro forma net earnings – US GAAP Net earnings per common share Basic - as reported - pro forma Diluted - as reported - pro forma 2003 13,112 (703) 12,409 0.22 0.21 0.22 0.21 $ $ $ $ $ $ Under APB Opinion 25, the re-pricing of outstanding stock options under a ﬁxed price stock option plan results in these options being accounted for as variable price options from the date of the modiﬁcation until they are exercised, forfeited or expire. For the year ended December 31, 2004, there would be no impact as the Company has prospectively applied the intrinsic value method to account for its stock based compensation. For the year ended December 31, 2003, an additional income of $0.7 million would have been recorded as general and administrative expense related to the re-pricing of outstanding stock options and for the year ended December 31, 2003, $1.2 million of general and administrative expenses related to stock options under Canadian GAAP would be reversed as the Company has chosen not to fair value account for its options using the fair value method under SFAS 123. (J) BUY/SEL L AR RA NGE ME NT S For US GAAP, buy/sell arrangements are reported on a gross basis. For the year ended December 31, 2004, the Company had sales of $22.2 million (2003 - $57.5 million) and purchases of $22.0 million (2003 - $63.1 million), related to buy/sell arrangements. The net gain of $0.2 million (2003 - $5.6 million loss) has been reﬂected in revenue for Canadian GAAP purposes PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 67 CORPORATE INFORMATION OFFICERS C. H. Riddell Chairman of the Board and Chief Executive Ofﬁcer B. K. Lee Chief Financial Ofﬁcer J. H. T. Riddell President and Chief Operating Ofﬁcer C. E. Morin Corporate Secretary L. M. Doyle Corporate Operating Ofﬁcer C. G. Folden Corporate Operating Ofﬁcer J. S. McDougall Corporate Operating Ofﬁcer G. W. P. McMillan Corporate Operating Ofﬁcer J. B. Williams Corporate Operating Ofﬁcer L. A. Friesen Assistant Corporate Secretary DIRECTORS C. H. Riddell(3) Chairman of the Board and Chief Executive Ofﬁcer Paramount Resources Ltd. Calgary, Alberta J. H. T. Riddell President and Chief Operating Ofﬁcer Paramount Resources Ltd. Calgary, Alberta J. C. Gorman(1) (4) Retired Calgary, Alberta D. Jungé, C.F.A(4) Chairman of the Board Pitcairn Financial Group Jenkintown, Pennsylvania Calgary, Alberta D. M. Knott General Partner Knott Partners, L.P. Syosset, New York Calgary, Alberta W. B. MacInnes, Q.C.(1) (2) (3) (4) Retired Calgary, Alberta V. S. A. Riddell Business Executive Calgary, Alberta S. L. Riddell Rose President and Chief Operating Ofﬁcer Paramount Energy Trust Calgary, Alberta J. B. Roy(1) (2) (3) (4) Independent Businessman Calgary, Alberta A. S. Thomson(1) (4) President Touche, Thomson & Yeoman Investment Consultants Ltd. Calgary, Alberta B. M. Wylie(2) Business Executive Calgary, Alberta (1) Member of Audit Committee (2) Member of Environmental, Health and Safety Committee (3) Member of Compensation Committee (4) Member of Corporate Governance Committee HEAD OFFICE 4700 Bankers Hall West 888 Third Street S. W. Calgary, Alberta Canada T2P 5C5 Telephone: (403) 290-3600 Facsimile: (403) 262-7994 www.paramountres.com CONSULTING ENGINEERS McDaniel & Associates Consultants Ltd. Calgary, Alberta Paddock Lindstrom & Associates Ltd. Calgary, Alberta AUDITORS Ernst & Young LLP Calgary, Alberta BANKERS Bank of Montreal Calgary, Alberta Canadian Imperial Bank of Commerce Calgary, Alberta The Bank of Nova Scotia Calgary, Alberta UBS AG Canada Branch Toronto, Ontario REGISTRAR AND TRANSFER AGENT Computershare Investor Services Canada Calgary, Alberta Toronto, Ontario STOCK EXCHANGE LISTING The Toronto Stock Exchange (‘POU’) 68 PARAMOUNT RESOURCES LTD. 20 04 A NNUAL R EP ORT ANALYST SUPPLEMENT ANALYST SUPPLEMENT This handbook has been prepared by Paramount Resources Ltd. to address the special information needs of the investment community and the sophisticated investor. The handbook provides detailed performance data and key ratios. For additional information please contact: B.K. (Bernard) Lee, Chief Financial Officer Paramount Resources Ltd. Suite 4700 Bankers Hall West, 888 Third Street S.W. Calgary, Alberta, Canada T2P 5C5 Tel (403) 290-3600 Fax (403) 262-7994 www.paramountres.com C O R P O R AT E P R O F I L E C O N S O L I D AT E D E A R N I N G S & C A S H F L O W D ATA Paramount Resources Ltd. is a Canadian energy company with its revenue derived primarily from natural gas sales. The Company explores for, develops, produces and markets natural gas, crude oil and natural gas liquids. Paramount has an aggressive, focused exploration and development strategy, concentrated on acquiring land and establishing reserves throughout the Western Canadian Sedimentary Basin. 26 years old 277 employees (171 head office, 106 field) Listed on the Toronto Stock Exchange; symbol “POU” Part of the S&P/TSX Composite Index 63.2 million shares outstanding at December 31, 2004 Market capitalization: $1.7 billion (December 31, 2004) Year 2002 2003 2004 Basic Cash Flow per Share $ 4.37 $ 259.9 million $ 2.78 $ 167.3 million $ 4.95 $ 295.6 million Basic Earnings per Share $ 0.17 $ 0.02 $ 0.69 $ 10.3 million $ 1.1 million $ 41.2 million Average number of common shares outstanding for 2004 was 59.8 million. U N I Q U E T R A I T S 80 percent of 2004 production is natural gas. “Successful efforts” accounting policy results in conservative net earnings. High management ownership (53 percent). Successful full cycle exploration and development creates shareholder value. Proven performance record through 26 years of commodity price cycles. Exposure to high impact exploration plays in Colville Lake and Northeast Alberta bitumen project. 1 PARAMOUNT RESOURCES LTD. 20 0 4 ANNUA L RE P ORT ($ millions except per share amounts) Year ended December 31 2004 2003 Change (%) Revenue Natural gas, net of transportation $ 425.6 Crude oil and liquids, net of transportation 124.9 18.7 Gain (loss) on financial instruments Royalties (net of Alberta Royalty Tax Credit) (105.0) - Loss on sale of investments 464.2 Net revenue Expenses Operating Interest General and administrative Stock based compensation expense Bad debt expense (recovery) Lease rentals Geological and geophysical Dry hole costs (Gain) loss on sales of property, land and equipment Accretion of asset retirement obligations Depletion and depreciation Write-down of petroleum and 95.8 25.4 25.2 41.2 (5.5) 3.5 8.7 24.7 (16.3) 6.9 191.6 $ 333.9 100.1 (53.2) (82.5) (1.0) 297.3 81.2 19.2 19.1 1.2 6.0 3.6 8.5 36.6 3.6 4.0 165.1 27 25 (135) 27 (100) 56 18 32 32 3,333 (192) (3) 2 (33) (553) 73 16 natural gas properties Unrealized foreign exchange gain on US debt Realized foreign exchange gain on US debt Premium on redemption of US debt Large Corporation Tax and other Future income tax (recovery) expense Net earning from continuing operations Net earnings (loss) from discontinued operations Net earnings - 10.4 (100) (24.2) (1.6) 1,413 (7.2) 12.0 6.8 40.7 429.3 34.9 - - 2.7 (63.5) 296.1 - - 152 (164) 45 1.2 2,808 6.3 $ 41.2 (0.1) 1.1 $ (6,400) 3,645 Net earnings per common share - basic $ 0.69 $ 0.02 3,350 C A S H F L O W R E C O N C I L I AT I O N ($ millions) Year ended December 31 Net revenue (1) Operating costs Interest on long-term debt (excluding non-cash interest) General and administrative Bad debt recovery (expense) Lease rentals Current and Large Corporation Tax Cash flow from continuing operations Cash flow from discontinued operations Cash flow from operations 2004 444.8 (95.8) (24.1) (25.2) 5.5 (3.5) (6.8) 249.9 0.7 295.6 2003 297.4 (81.2) (19.0) (19.1) (6.0) (3.6) (2.7) 165.8 1.5 167.3 Cash flow per common share – basic 4.95 2.78 (1) Net of realized financial instrument gains and losses, royalties, transportation costs, and gains on sale of investments. ANALYST SUPPLEMENT M A J O R P R O D U C I N G P R O P E R T I E S C A P I TA L E X P E N D I T U R E S ($ millions) Drilling Seismic Facilities and equipment Land acquisitions Property acquisitions Other Property dispositions Net capital expenditures 2004 2003 $ 184.5 8.7 85.2 37.9 322.6 1.9 $ 123.4 8.5 69.6 22.3 0.9 1.9 640.8 (61.8) 226.6 (371.6) $ 579.0 $ (145.0) The following table summarizes average production volumes from Paramount’s major producing properties, for each of the last five fiscal years. Natural Gas (MMcf/d) Kaybob Grande Prairie Northwest Alberta Liard – Northeast BC/NWT Southern Northeast Alberta Other Total Crude Oil and Liquids (Bbl/d) Kaybob Grande Prairie Northwest Alberta Liard - Northeast BC/NWT Southern Other Total Total Production (Boe/d @ 6:1) Kaybob Grande Prairie Northwest Alberta Liard - Northeast BC/NWT Southern Northeast Alberta Other Total 2004 96.4 26.8 20.2 16.2 10.8 1.6 1.1 173.1 4,091 585 797 12 1,798 14 7,297 2003 79.5 12.4 22.3 11.6 9.5 16.2 1.3 152.8 2,451 1,767 448 9 2,457 37 7,169 2002 87.5 7.0 30.4 12.3 5.4 96.9 1.9 241.4 2.291 1.353 35 15 1,732 237 5,663 2001 65.3 3.1 29.2 9.3 – 108.7 9.4 225.0 1,855 – – 21 130 159 2,165 2000 63.7 – 26.1 5.4 – 119.0 5.8 220.0 1,258 – – 95 218 – 1,571 20,157 15,704 16,874 12,738 11,875 – 2,520 3,831 4,350 5,102 4,165 995 2,065 1,942 4,048 218 2,632 2,700 16,150 18,117 19,833 967 36,150 32,630 45,898 39,665 38,238 5,053 4,165 2,710 3,596 252 217 517 4,867 1,571 130 1,725 240 555 C O R E P R O D U C I N G P R O P E R T I E S �� PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 2 ANALYST SUPPLEMENT B A L A N C E S H E E T I N F O R M AT I O N NET ASSET VALUE PER COMMON SHARE As at December 31 ($ millions) 2004 2003 Change (%) As at December 31, 2004 ($ millions except per share amount) Assets Current assets Property, plant and equipment, net Other assets $ $ 158 1,346 39 $ 1,543 $ Liabilities and Shareholders’ Equity $ Current liabilities Long-term debt Asset retirement obligations Deferred revenue Stock based compensation liability Future income taxes Liabilities of discontinued operations Shareholders’ equity 150 459 102 – 41 166 – 625 101 1,037 39 1,177 112 287 62 4 – 207 10 496 $ 1,543 $ 1,177 56 30 2 31 34 60 65 (100) – (19) (100) 26 31 Discount rate Present value of reserves (1,2) Market value of short-term investments Fair market value of undeveloped land Other assets (3) Subtotal Working capital deficiency (4) Debt 10% $ 1659.3 27.1 185.4 184.5 2056.3 (17.0) (459.1) Net asset value Net asset value per common share (5) (1) Proved plus probable discounted at 10 percent, includes benefit of ARTC with $ 1580.2 $ 25.01 no allowance for income tax. (2) Based on Forecast Prices and Costs Assumptions. (3) Includes seismic, projects under evaluation and other assets (all at cost). (4) Excludes short-term investments. (5) Based on outstanding common shares of 63,185,600 at December 31, 2004. C A P I TA L S T R U C T U R E The following table outlines Paramount’s capital structure since 2000. ($ thousands) Debt Common share equity Retained earnings 2004 2003 2002 2001 2000 $ 459,141 302,932 322,107 $ 287,237 200,274 295,013 $ 539,270 190,193 355,912 $ 316,600 189,320 346,064 $ 315,000 189,320 228,934 $ 1,084,180 $ 782,524 $ 1,085,375 $ 851,984 $ 733,254 N E T D E B T At December 31 ($ thousands) Current assets (1) Current liabilities (1) Working capital (surplus) deficiency Debt (1) Net debt (1) Excludes discontinued operations. 2004 2003 $ 157,650 149,696 (7,954) 459,141 $ 99,516 109,334 9,818 287,237 $ 451,187 $ 297,055 K E Y R AT I O S The following key ratios to “fundamental analysis” have been calculated to accompany the Cash Flow Reconciliation. Cash Flow per Share Share Price to Cash Flow Multiple Debt to Cash Flow Ratio Debt to Equity Ratio Earnings per Share E S T I M AT E D F U T U R E P R E - TA X C A S H F L O W Rate of Return on Shareholders’ Equity Reserves Present Value of Estimated Pre-tax Before Royalty Cash Flow Discounted at: Gas Oil/liquids (MBbl) (Bcf) 347.2 221.4 15,042 5,419 568.6 20,461 (millions of dollars) 15% 10% 1,156 503 1,022 398 1,659 1,420 Per share amounts for 2004 utilize the weighted average number of common shares outstanding of 59,755,480. Cash Flow Paramount calculates its cash flow; net of all lease rentals of both producing and non-producing properties net of all cash general and administrative costs net of all marketing costs which are currently expensed net of all interest expenses, none of which are capitalized Proved Probable Total The discounted net present values of the estimated pre-tax cash flow expected during the economic life of all reserves are based on estimates using escalating price assumptions at rates of 10 percent and 15 percent per annum compounded annually. They are calculated prior to the consideration of income taxes but include ARTC, and are not to be construed as representing the fair market value of properties. The fair market value of the properties and such net present values will depend upon the subjective considerations inherent to each property. Net Earnings Paramount further calculates its net earnings; net of dry hole costs net of geological and geophysical costs PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 3 ANALYST SUPPLEMENT C A S H F L O W R E C O N C I L I AT I O N E A R N I N G S P E R S H A R E ($ millions) Gross revenue (1) Net royalties (2) Net revenue Expenses Operating 2004 549.9 (105.1) December 31 2002 2003 2001 2000 379.9 (82.5) 473.9 (74.4) 528.4 (99.7) 391.5 (80.6) 444.8 297.4 399.5 428.7 310.9 Cash G&A 95.8 25.2 3.5 Lease rentals Cash interest 24.1 Bad debt expense (recovery) (5.5) Current income taxes and other Discontinued operations 6.8 (0.7) 81.2 19.1 3.6 19.0 6.0 2.7 (1.5) 86.1 15.9 4.6 23.9 – 9.1 – 61.1 12.4 4.3 19.3 – 27.7 – 48.0 9.7 5.2 22.3 – 2.3 – Cash flow 295.6 167.3 259.9 303.9 223.4 (1) Includes realized financial instrument gains and losses on sale of investments, and net of transportation. (2) Net of ARTC. C A S H F L O W A N D C A S H F L O W / S H A R E Fiscal year 2000 2001 2002 2003 2004 Cash Flow ($ 000s) 223,446 303,937 259,916 167,276 295,566 Trend(1) 100 136 116 75 132 Shares(2) (000s) 59,454 59,454 59,458 60,098 59,755 Cash Flow per Share ($) Trend(1) 3.76 5.11 4.37 2.78 4.95 100 136 116 74 132 (1) Trend with base year 2000, with a nominal value of 100. (2) Weighted average shares outstanding. S H A R E P R I C E T O C A S H F L O W M U LT I P L E Fiscal Year 2000 2001 2002 2003 2004 Share Low 10.50 12.00 13.00 8.51 10.50 Price ($) High 20.00 18.75 17.60 16.95 27.00 Cash Flow per Share ($) 3.76 5.11 4.37 2.78 4.95 Multiple Low High 2.8x 2.3x 3.0x 3.1x 2.1x 5.3x 3.7x 4.0x 6.1x 5.5x N E T D E B T T O C A S H F L O W R AT I O Fiscal year 2000 2001 2002 2003 2004 Net Debt ($ 000s) Cash Flow ($ 000s) Debt/cash Flow Ratio Flow Trend(1) 292,360 290,698 555,243 297,055 451,187 223,446 303,937 259,916 167,276 295,566 1.3:1 1.0:1 2.1:1 1.8:1 1.5:1 100 73 163 136 117 (1) Trend with base year 2000 with a nominal value of 100. D E B T T O E Q U I T Y R AT I O Fiscal Year 2000 2001 2002 2003 (2) 2004 (2) Operating Shareholders’ Equity ($ 000s) 418,254 535,384 546,105 496,033 625,039 Debt ($ 000s) 315,000 316,600 539,270 287,237 459,141 Debt/ Equity Ratio 0.75:1 0.59:1 0.99:1 0.60:1 0.73:1 Trend(1) 100 79 131 77 98 (1) Trend with base year 2000 with a nominal value of 100. (2) Excludes discontinued operations. Paramount’s earnings are net of dry hole costs, geological/ geophysical costs and all lease rentals. Fiscal year 2000 2001 2002 2003 2004 Net Earnings ($ 000s) 86,062 118,902 10,307 1,151 41,174 Net Shares(2) Earnings per Trend(1) 100 138 12 1 48 (000s) 59,454 59,454 59,458 60,098 59,755 Share ($) Trend(1) 1.45 2.00 0.17 0.02 0.69 100 138 12 1 48 (1) Trend with base year 2000 with a nominal value of 100. (2) Weighted average shares outstanding. R ATE OF RE T UR N ON SHAR E HO LDE R ’S E Q UIT Y Paramount has earned a weighted average after-tax rate of return of 11.5 percent as computed on a book basis, based upon the weighted average shareholders’ equity invested over the past five years. ($ thousands) 2004 2003 2002 2001 2000 Net earnings Weighted average Shareholders’ equity After-tax rate 41,174 1,151 10,307 118,902 86,062 560,536 521,069 540,745 476,819 373,623 of return (%) 7.3 0.2 1.9 24.9 23.0 U N D E V E L O P E D L A N D (thousands of acres) Alberta British Columbia Saskatchewan Northwest Territories Montana, North Dakota Other Total Undeveloped Land Net land Proved Undeveloped Total net land Gross Net 2,190 348 17 1,235 102 1,644 1,649 258 13 661 39 822 5,536 3,442 2004 2003 640 3,442 586 2,800 4,082 3,386 Appraised value of undeveloped land (1) $ 185.4 $ 98.2 (1) Millions of dollars. Appraised value is an estimate of the fair market value of acreage based upon current analogous sales. Approximately 84 percent of the total net 2004 land inventory of 4.1 million acres is undeveloped. PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 4 ANALYST SUPPLEMENT O I L & G A S S A L E S A N D G R O S S P R O F I T This illustrates oil and gas sales since 2000 and converts the oil sales into barrels of equivalent (Boe) on an industry standard basis of one barrel of crude oil/liquids equals 6 Mcf of natural gas. P&NG Revenue (after financial instruments and transportation costs) Fiscal year(1) ($ 000s) Trend 2000 2001 2002 2003 2004 391,470 525,686 431,001 380,855 569,309 100 134 110 97 145 Oil & Liquids Gas Production (MMcf) Trend 80,520 82,125 88,111 55,760 63,360 100 102 109 69 79 (1) Trend with base year 2000, with nominal value of 100 O P E R AT I N G C A S H N E T B A C K S Production (Bbl) Trend 574,986 790,225 2,066,995 2,616,706 2,670,794 100 137 359 455 464 Average Price (after realized financial instruments) Gas ($) Oil ($) 4.59 6.12 4.08 5.16 6.86 37.80 35.48 34.64 35.50 44.13 Barrel of Equivalent Production (MBoe) Trend 13,995 14,478 16,753 11,910 13,231 100 103 120 85 95 Fiscal Year(1) 2000 2001 2002 2003 2004 Royalties (net ARTC) ($/Boe) Trend ($ 000s) Operating Costs Operating Cash Netback(2) ($ 000s) ($/Boe) Trend ($ 000s) ($/Boe) Trend % of Revenue 80,541 99,706 74,444 82,512 105,046 5.75 6.89 4.44 6.93 7.94 100 124 92 102 130 47,974 61,045 86,067 81,193 95,767 3.43 4.22 5.14 6.82 7.24 100 127 179 169 200 262,955 18.79 351,814 24.29 266,618 15.92 269,334 22.60 349,769 26.44 100 129 85 120 141 67.2 66.9 61.9 70.7 61.4 (1) Trend with base year 2000, with nominal value of 100. (2) Operating cash netback = oil & gas and other revenue – royalty – operating cost. R E V E N U E / E X P E N S E S / C A S H F L O W N E T B A C K / N E T E A R N I N G S The table calculates revenue, expenses and net earnings converted into dollars per thousand cubic feet gas equivalent (1 barrel = 6 Mcf). ($/Boe) Annual production (MBoe) Gross revenue before financial instruments, net of transportation Gain (loss) on sale of investments Royalties Operating costs Operating netback Realized financial instruments gain (loss) General and administrative Bad debt recovery (expense) Cash interest Lease rentals Current income tax Large corporation tax and other Other Cash flow netback Unrealized financial instrument gain (loss) Stock based compensation expense Non-cash interest Depletion and depreciation Accretion of asset retirement obligations Surmont compensation Gain (loss) on sale of properties Dry hole costs Write-down of petroleum and natural gas properties Geological and geophysical Unrealized foreign exchange gain on US debt Realized foreign exchange gain on US debt Premium on redemption of US debt Other Future income taxes recovery (expense) Net earnings Net earnings trend (1) (1) Trend with base year 2000, with nominal value of 100. H I S T O R I C A L S U M M A R Y Gas production (MMcf/d) Crude oil and liquids production (Bbl/d) Gas proved reserves (Bcf) Crude oil and liquids proved reserves (MBbl) Total proved and probable reserves (MMBoe) 6:1 Cash flow ($ millions) Cash flow per share (basic) Net earnings ($ millions) Net earnings per share (basic) 2004 13,231 41.61 – (7.94) (7.24) 26.43 (0.05) (1.91) 0.42 (1.82) (0.27) – (0.51) 0.05 22.34 1.46 (3.11) (0.10) (14.48) (0.52) – 1.23 (1.87) – (0.66) 1.83 0.54 (0.90) 0.42 (3.07) 3.11 50 2004 173.1 7,297 568.6 20,461 115.2 295.6 4.95 41.2 0.69 $ $ $ $ $ $ 2003 2002 2001 2000 11,910 $ 36.45 (0.09) (6.93) (6.82) 22.61 (4.47) (1.60) (0.50) (1.60) (0.30) – (0.23) 0.13 14.04 – (0.10) (0.01) (13.86) (0.34) – (0.31) (3.07) (0.87) (0.71) 0.13 – – (0.13) 5.33 0.10 2 $ 2003 152.8 7,169 241.7 10,617 67.4 $ 167.3 $ 2.78 1.1 $ $ 0.02 16,753 $ 23.06 2.44 (4.44) (5.14) 15.92 2.79 (0.95) – (1.43) (0.27) – (0.55) – 15.51 – (0.02) – (10.11) (0.21) 2.23 – (7.17) (1.87) (0.56) – – – – 2.80 0.60 10 $ 14,478 $ 35.20 0.20 (6.89) (4.22) 24.29 1.09 (0.85) – (1.33) (0.30) (1.73) (0.19) – 20.98 – – – (7.28) (0.17) – (0.11) (0.62) – (0.74) – – – – (3.87) 8.19 133 $ 2002 241.4 5,663 446.5 17,545 125.9 2001 225.0 2,165 437.7 6,339 101.9 $ 259.9 4.37 $ 10.3 $ 0.17 $ $ 303.9 5.11 $ 118.9 $ 2.00 $ 13,995 $ 27.97 – (5.75) (3.43) 18.79 – (0.69) – (1.59) (0.37) – (0.16) – 15.98 – – – (3.61) (0.12) – 0.05 (0.50) – (0.48) – – – – (5.14) $ 6.18 100 2000 220.0 1,571 518.1 4,709 115.5 $ 223.4 $ 3.76 $ 86.1 1.45 $ 5 PARAMOUNT RESOURCES LTD. 20 04 A N N UAL R EP ORT ANALYST SUPPLEMENT C O M P A N Y F O R E C A S T 2 0 0 5 D I R E C T O R S A N D O F F I C E R S Production / Pricing Gas (MMcf/d) ($/Mcf) Oil/liquids (Bbl/d) ($/Bbl) Cash flow ($MM) Cash flow per share Capital budget ($MM) 210 @ $ 6.50 10,000 @ US$ 42.00 425 6.66 340 C O M M O N S H A R E D ATA Shares of Paramount Resources Ltd. trade on The Toronto Stock Exchange under the symbol “POU” (Oil and Gas Producers Sub Index) and is part of the S&P/TSX Composite Index. At December 31 2004 2003 Outstanding shares (000s) Public float(1) – shares (000s) – % of total shares Trading volume (000s) Trading value (000s) Trading range High Low Close Weighted average trading price Market capitalization at year end ($ millions) 63,186 29,697 47% 38,489 $ 719,743 $ $ $ $ 27.90 10.41 26.90 18.70 1,700 60,095 27,818 46% 34,335 $ 431,533 $ $ $ $ $ 16.95 8.51 10.45 12.57 628.0 (1) Public float is all outstanding shares less shares owned/controlled by officers/directors. C.H. (Clay) Riddell (3) Director, Chairman and Chief Executive Officer B.K. (Bernard) Lee Chief Financial Officer J.H.T. (Jim) Riddell Director, President and Chief Operating Officer C.E. (Chuck) Morin Corporate Secretary L.M. (Lloyd) Doyle Corporate Operating Officer C.G. (Cal) Folden Corporate Operating Officer J.S. (Scott) McDougall Corporate Operating Officer G.W.P. (Geoff) MacMillan Corporate Operating Officer J.B. (John) Williams Corporate Operating Officer L.A. (Laurel) Friesen Assistant Corporate Secretary J.C. (John) Gorman (1 (4) Director D. (Dirk) Jungé, C.F.A. (4) Director D.M. (David) Knott Director W.B. (Wally) MacInnes, Q.C. (1) (2) (3) (4) Director V.S.A. (Vi) Riddell Director S.L. (Sue) Riddell Rose Director J.B. (John) Roy(1) (2) (3) (4) Director A.S. (Alistair) Thomson (1) (4) Director B.M. (Bernie) Wylie(2) Director (1) Member of Audit Committee. (2) Member of Environmental, Health and Safety Committee. (3) Member of Compensation Committee. (4) Member of Corporate Governance Committee. F I V E - Y E A R S H A R E P R I C E A N D T R A D I N G V O L U M E �� 6 PARA MOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT �� Trilogy Energy Trust (1) (TET.UN): is a Canadian energy trust formed through the spinout of a portion of Paramount Resources assets in the Kaybob and Marten Creek areas of central Alberta. These assets are primarily low-risk, high working interest, lower-decline properties that are geographically concentrated with many inﬁll drilling opportunities, good access to infrastructure and processing facilities that are operated and controlled by the Trust. By operating the wells and production infrastructure, we can control two variables that aﬀect the cash ﬂow and revenues of the Trust. The Trust will employ a strategy to provide Unitholders with: a competitive annual yield by making monthly cash distributions to Unitholders, maintain the Trilogy assets at a level that provides stable production, and continue to expand the business of the Trust through the development of growth opportunities that will provide long-term stable cash ﬂows. The technical expertise that has been employed at Paramount will continue to develop and exploit the land and reserves in Kaybob and Marten Creek. The ﬁeld operation has been growing and developing the operational expertise to operate eﬀectively and eﬃciently in the Kaybob area and will continue to be an intregal part of the exploitation and production of the assets. The Trust’s inﬁll drilling opportunities and large undeveloped land base are expected to make it less reliant on the acquisition market to maintain distributions. The management of Trilogy Energy Ltd., the Administrator of the Trust, will consider strategic asset acquisitions that would be accretive to the production, reserves and cash ﬂow of the Trust and provide undeveloped potential that can be exploited to increase the value of the Trust. (1) References to the Trust in this summary include, where the context requires, the trusts, corporations and partnerships directly or indirectly owned by the Trust. Marten Creek East Kaybob TR IL OG Y ENER GY TRUST 1 Letter to Unitholders Paramount’s management continually reviews all options available to it to ensure that Paramount’s capital structure is eﬃcient and that shareholder value is being enhanced. In this regard, in 2004, certain senior management of Paramount conducted a preliminary review of possible restructuring alternatives available to Paramount to increase shareholder value. The Board of Directors, after considering the alternatives presented to it and after receiving advice from its legal and ﬁnancial advisors, approved a reorganization of a portion of Paramount’s assets into an energy trust (the “Trust Spinout”). The Beneﬁts of Forming the Trust Paramount believes the Trust Spinout will enhance value for shareholders by dividing Paramount’s assets into two speciﬁc groups, consisting of: (i) the higher free cash ﬂow Kaybob and Marten Creek assets which will be owned through the Trust, which will pay regular cash distributions; and (ii) the predominantly growth oriented assets which will continue to be owned by Paramount. The Trust Spinout will allow shareholders to participate, either separately or on a combined basis, in the growth potential and mature qualities of Paramount’s assets. Paramount believes that the post transaction structure better aligns risks and returns from each asset class in a way that is both sustainable and tax eﬀective. This new structure should provide greater aggregate access to capital to fund the growth of the businesses of each of Paramount and the Trust; and a more active and liquid market for the new Common Shares and the Trust Units. The Process of Restructuring In order to implement any proposed reorganization of Paramount, Paramount required the consent of the majority of the holders of each of its 7 7/8% Notes due 2010 and its 8 7/8% Notes due 2014. On February 7, 2005, Paramount obtained consent from the note holders and completed, as amended, the Notes Oﬀer issuing U.S.$213,593,000 principal amount of 8 1/2% Notes due 2013 and paying aggregate cash consideration of approximately U.S.$36.2 million in exchange for approximately 99.31% of the outstanding 2010 Notes and 100% of the outstanding 2014 Notes. This cleared the way to continue with the Trust Spinout. The Plan The Trust Spinout resulted in the shareholders receiving one new Paramount Resources Ltd. Common Share and one Unit of the Trust in exchange for each Paramount Resources Ltd. Common Share held. Upon completion of the Trust Spinout, Paramount shareholders owned 100 percent of post-reorganization Paramount and 81 percent of the outstanding units of Trilogy. Paramount owned the remaining 19 percent of the outstanding units of the Trust. Through Trilogy, the unitholders will receive regular monthly cash distributions from the cash ﬂow produced by the Trust’s developed assets. Through Paramount, shareholders will participate in the potential upside of Paramount’s remaining predominately growth-oriented assets. 2 TRILOGY ENERGY TRU ST The following diagram illustrates the organizational structure of Paramount Resources Ltd. and Trilogy Energy Trust: Shareholders Unitholders �� Paramount Resources Ltd. �� Trilogy Energy Ltd. (General Partner) �� Trilogy Energy Trust �� Trilogy Holding Trust �� Paramount Resources (General Partnership) Trilogy Energy LP (Limited Partnership) Assets Spinout Assets �� TR IL OG Y ENER GY TRUST 3 The Assets The East Kaybob and Marten Creek properties held by Trilogy Energy Trust are geographically concentrated in central Alberta. These are developed, high working interest, lower decline properties with many inﬁll drilling opportunities and good access to owned infrastructure and processing facilities. The Trilogy assets are currently producing approximately 25,000 Boe/d, comprised of approximately 120 MMcf/d of natural gas and 5,000 Bbl/d of crude oil and natural gas liquids. A report of Paddock Lindstrom & Associates Ltd., independent petroleum engineers, dated eﬀective December 31, 2004 assigned 44,722 MBoe of Proved Reserves and 64,254 MBoe of Proved plus Probable Reserves to these properties. The East Kaybob properties represent approximately 89 percent of the production and 93 percent of the Proved plus Probable Reserves of the Trust Spinout assets as at December 31, 2004. The production at the end of March 2005 averaged approximately 22,200 Boe/d (approximately 103 MMcf/d of natural gas and 5,000 Bbl/d of crude oil and natural gas liquids). The natural gas produced from the East Kaybob area is typically liquid-rich with a high heat content which translates into a premium price relative to AECO gas. The Paddock Lindstrom report has assigned 41,714 MBoe of Proved Reserves and 60,008 MBoe of Proved plus Probable Reserves to this area. The assets in East Kaybob also include, as at December 31, 2004, 356,927 (333,203 net) developed acres and 373,362 (206,558 net) undeveloped acres of land. This area is known for its multi-zone potential. The wells in this area produce from the Viking, Spirit River, Bluesky, Gething, Nordegg, Montney and Swan Hills formations which have well depths between 1,500 to 3,500 metres. Approximately 58 percent of the natural gas production from these properties will be processed at three Trilogy-operated natural gas plants with an average 75 percent working interest. Approximately 64 percent of the oil and natural gas liquids production in this area is treated at Trilogy-operated oil batteries with an average working interest of 65 percent. The Marten Creek property represents approximately 11 percent of the production and 7 percent of the Proved plus Probable Reserves attributable to the Trust Spinout assets as at December 31, 2004. The production at the end of March 2005 averaged approximately 17 MMcf/d of natural gas or approximately 2,800 Boe/d. The Paddock Lindstrom report has assigned 3,008 MBoe of Proved Reserves and 4,246 MBoe of Proved plus Probable Reserves to this area. As at December 31, 2004 Marten Creek had 26,880 (26,880 net) developed acres and 117,120 (115,200 net) undeveloped acres of land. The wells in this area produce primarily from the Viking, Clearwater and Wabiskaw formations which have well depths of between 300-500 metres. The main gathering system and processing plant in Marten Creek is operated by a midstream processing company. 4 TRILOGY ENERGY TRU ST Simonette A&B �� Karr �� Fox Creek �� Kaybob North BHL #1 �� Marten Creek �� Kaybob North �� Kaybob South BHL Unit #1 �� Kaybob South BHL Unit #2 �� Kaybob South BHL Unit #3 �� Two Creek �� Clover �� Pine Creek �� Edson �� Other �� TR IL OG Y ENER GY TRUST 5 The People Dedicated Paramount staﬀ involved in the development and implementation of the technical fundamentals responsible for the successful exploitation of the Trust assets will continue their employment with Trilogy, employed by Trilogy Energy LP. The management will consider strategic asset acquisitions that would be accretive to the production, reserves and per unit cash ﬂow of the Trust and provide undeveloped potential that can be exploited to add additional value. The ﬁeld operation has been growing and developing the operational expertise to operate eﬀectively and eﬃciently in the Kaybob area and will continue to be a part of the exploitation and production of the assets. The Trust will ensure that the ﬁeld employees are trained, qualiﬁed and suﬃciently experienced to perform the assigned task in a competent manner. It is the tenet of the Trust to create a corporate culture that attracts and rewards employees who are passionate, innovative and inspired to add to the value of the Trust. The Trust culture will support continuous improvement, resulting in better performance and more free cash ﬂow for distributions. The Outlook The success of Trilogy Energy Trust will be contingent on the implementation of a strategy that will result in a stable production proﬁle, provide steady cash ﬂow and ultimately, stable distributions for unitholders. We are excited to go forward with a capital program to replace reserves and production. The assets will provide a growth platform for successful ongoing development of this tight gas resource play. We are conﬁdent in the vast array of currently identiﬁed development opportunities. There exists a large, as yet, undeveloped resource in the central Alberta area that will fuel future growth and add tremendous value for Trilogy Unitholders and Paramount Shareholders. The ﬁrst monthly distribution of the Trust is targeted to occur on May 15, 2005 to unitholders of record on May 2, 2005. Successful production replacement, prudent asset management, strong commodity prices and continued eﬃcient control of operations will support a stable distribution. We are conﬁdent in our management, our high quality assets and our proven expertise. We believe the Trust will be a rewarding investment for our unitholders. signed Jim Riddell President & Chief Executive Oﬃcer 6 TRILOGY ENERGY TRU ST Ofﬁcers and Directors of Trilogy Energy Ltd., the Administrator of the Trust OFFICERS DIRECTORS J. H. T. Riddell President and Chief Executive Oﬃcer B. K. Lee Chief Financial Oﬃcer J. B. Williams Chief Operating Oﬃcer C. E. Morin Corporate Secretary C. H. Riddell Non Executive Chairman of the Board Calgary, Alberta J. H. T. Riddell President and Chief Executive Oﬃcer Calgary, Alberta R.M. MacDonald Independent Businessman Calgary, Alberta D.F. Textor Retired Locust Valley, New York E.M.Shier Partner Heenan Blaikie LLP Calgary, Alberta TR IL OG Y ENER GY TRUST 7 4100, 350 Seventh Avenue, S.W. Calgary, Alberta Canada T2P 3N9 Telephone: (403) 290-2900 Facsimile: (403) 263-8915 The Toronto Stock Exchange Listing: “TET.UN” ABBREVIATIONS barrels barrels per day billion cubic feet billion cubic feet of gas equivalent barrels of oil equivalent gigajoules gigajoules per day thousand cubic feet thousand cubic feet of gas equivalent thousand cubic feet per day million cubic feet Bbl Bbl/d Bcf Bcfe Boe GJ GJ/d Mcf Mcfe Mcf/d MMcf MMcf/d million cubic feet per day MBbl thousands of barrels MMbtu millions of British Thermal Units MBoe MMcfe/d million cubic feet of gas equivalent per day thousands of barrels of oil equivalent 4700 Bankers Hall West 888 Third Street S. W. Calgary, Alberta Canada T2P 5C5 Telephone: (403) 290-3600 Facsimile: (403) 262-7994 www.paramountres.com

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