KEYWEST ENERGY CORPORATION
#1200, 520-5thAvenue S. W.
Calgary, Alberta
Canada
T2P 3R7
Revised Annual Information Form
For the year ended December 31, 2001
October 11, 2002
TABLE OF CONTENTS
GLOSSARY OF ABBREVIATIONS AND TERMS
1
INCORPORATION
2
BUSINESS OF THE COMPANY
2
Corporate Profile and General Development of the Business
2
Undeveloped Land
3
Drilling Activity – Wells Drilled
3
Principal Producing Properties of KeyWest
4
Oil and Gas Wells
5
Reserves and Future Revenue
5
Reconciliation of Reserves (based on constant pricing)
6
Reserve Life Index
6
History
7
Marketing
8
Government Regulation
8
Pricing and Marketing - Oil and Natural Gas
8
The North American Free Trade Agreement
8
Provincial Royalties and Incentives
9
MANAGEMENT’S DISCUSSION AND ANALYSIS
10
SELECTED OPERATING AND FINANCIAL INFORMATION
11
DIRECTORS AND OFFICERS
12
SHARE INFORMATION
13
ADDITIONAL INFORMATION
14
GLOSSARY OF ABBREVIATIONS AND TERMS
In this Annual Information Form, the following abbreviations and terms have the following meanings:
Abbreviations
Crude oil and natural gas liquids:
bbls
-
barrels
mbbls
-
1,000 barrels
bopd
-
barrels of oil per day
Natural gas:
mcf
-
1,000 cubic feet
mmcf
-
1,000,000 cubic feet
bcf
-
1,000,000,000 cubic feet
mcfd
-
1,000 cubic feet per day
mmcfd
-
1,000,000 cubic feet per day
boe
-
barrel of oil equivalent at the rate of 6 mcf of gas = 1 boe
ngls
-
natural gas liquids
Terms
"Bashaw Acquisition"means the October 1, 2002 Bashaw, Alberta, production purchase by KeyWest of 2,000 boe/d;
"CBCA" means theCanada Business Corporations Act;
"Common Shares" means common shares in the capital of KeyWest;
"GLJ" means Gilbert Laustsen Jung Associates Ltd.;
"Interim GLJ Report"means the evaluation report dated October 9, 2002 prepared by GLJ;
"KeyWest", the"Company" or the"Corporation" means KeyWest Energy Corporation, a corporation continued under the CBCA;
"San Fernando" means San Fernando Mining Company Ltd., the predecessor company of KeyWest;
"Sequoia" means Sequoia Exploration and Development Ltd., a corporation amalgamated with KeyWest under the CBCA;
"Shareholders" means holders of Common Shares;
"Viewpoint" means Viewpoint Resources Ltd., a corporation incorporated pursuant to theBusiness Corporations Act (Alberta); and
"Year-End GLJ Report" means the evaluation report dated March 11, 2002 prepared by GLJ.
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ANNUAL INFORMATION FORM
INCORPORATION
KeyWest Energy Corporation (“KeyWest”, the “Company” or the “Corporation”) was incorporated on June 12, 1987 pursuant to theCompany Act, Province of British Columbia, under the name Harrisburg-Dayton Resource Corp. and the Company’s name was changed to San Fernando Mining Company Ltd. on July 16, 1991. Pursuant to a Special Resolution of Shareholders passed on May 14, 1998, the Corporation was authorized to make application for continuance under the CBCA and to change the name of the Company to KeyWest Energy Corporation. Effective January 1, 1999, KeyWest amalgamated under the CBCA with Colt Energy Inc. and subsequently, on June 30, 1999, KeyWest amalgamated under the CBCA with Sequoia. KeyWest has one wholly-owned subsidiary, Viewpoint Resources Ltd., an Alberta corporation.
The head office of the Company is located at 1200, 520-5 Avenue S.W., Calgary, Alberta T2P 3R7.
In this document, reference to "KeyWest", the "Company" or the "Corporation" means KeyWest Energy Corporation and its wholly-owned subsidiary, unless the context otherwise requires.
BUSINESS OF THE COMPANY
Corporate Profile and General Development of the Business
The business of KeyWest is the acquisition, exploration, development, production and marketing of oil and natural gas in Western Canada. The Corporation has experienced management, along with professional, technical and support staff in the exploration, land, production, drilling, engineering, marketing, financial, and administration areas of responsibility. At October 1, 2002, KeyWest had 31 full-time employees in its Calgary head office and five field contract operators. KeyWest evolved as the result of a change in corporate direction by the former San Fernando, the Corporation’s predecessor company.
San Fernando was a publicly-traded company operating as a mining concern and involved in various mining concessions in Mexico - none of which ultimately proved to be economic. In late February of 1998, San Fernando's Board of Directors entered into a letter agreement with former executives of Jordan Petroleum Ltd. (a company which had been sold in December of 1997) to redirect San Fernando into the oil and gas business. In May 1998, the Company concluded a $1.57 million private placement by which means the new management and directors acquired 2,884,615 Common Shares at $0.52 per share and 96,155 Common Shares at $0.76 per share. Subsequently, a Special Shareholders' Meeting was called on May 14, 1998 to change the Company's name to KeyWest and to vote on various corporate matters to effect the Company's change in business direction.
The Company’s subsequent growth has been achieved through a combination of financings, mergers, acquisitions and drilling.
On September 1, 1998, KeyWest concluded a private placement of 2,376,427 Common Shares at $0.90 per share for total gross proceeds of $2.14 million. Under the terms of the private placement, 70% of the proceeds were utilized for oil and gas drilling operations (with respect to which the Corporation “flowed-through” the tax benefits to subscribers).
On December 17, 1998, the Company acquired all the shares of Colt Energy Inc. (with whom the Company subsequently amalgamated on January 1, 1999) by issuing 12,789,885 Common Shares to acquire assets, comprising cash, together with oil and gas properties, collectively totaling $8.6 million in value ($8.0 million net of acquisition costs of approximately $630,000). The oil and gas assets were subsequently sold at a price equal to their carried value of $764,000.
Effective June 30, 1999, KeyWest amalgamated with Sequoia, a private Alberta corporation. Sequoia’s assets consisted of $4.1 million in cash and daily production of 100 boe in central Alberta. KeyWest issued 7.06 million Common Shares valued at $5.46 million to acquire the company.
In June 1999, a $10.1 million purchase of 735 boe per day, weighted 62% towards gas, was made at Carbon in central Alberta. The transaction included proven reserves of 1.9 million boe, a pipeline infrastructure, two underutilized gas plants and a 68% interest in 13,360 acres of undeveloped lands.
In September 1999, KeyWest purchased a 100% interest in production of 400 bopd at Chin Coulee in southern Alberta. The purchase price was $9.1 million for proven reserves of 1.44 million barrels of oil along with a 100% interest in 5,660 undeveloped acres.
KeyWest received $1.6 million from the exercise of warrants at $1.01 per share in September 1999. The warrants were originally issued by Colt Energy Inc. prior to its 1998 merger with KeyWest.
In October 1999, a $5.0 million “bought deal” at $1.01 per share was completed with a group of Canadian and U. S. institutional investors. KeyWest closed a second financing in November 1999 consisting of a $2.5 million private placement at $1.05 per share with subscribers receiving flow-through Canadian tax benefits for eighty percent of their subscription amounts.
During 1999 KeyWest drilled 15 wells comprised of four exploratory and 11 development wells. The Company’s drilling program resulted in 12 successful wells (seven oil and five gas wells) for an 80% success rate.
KeyWest had no oil and gas production prior to May 1999 however, the Company’s production, when prorated over the full 12 months of 1999, averaged 2,763 mcfd for gas and 376 bopd. The Company’s average daily production throughout 1999 was 837 boe.
In September 2000, KeyWest acquired Viewpoint, a private Alberta corporation. Viewpoint’s assets included production of 360 boe per day together with 13,000 acres of undrilled lands. The consideration of $3.9 million was paid in cash totalling $1.9 million together with the issuance of 1.8 million Common Shares. Viewpoint remains a wholly-owned subsidiary of KeyWest.
During 2000 KeyWest drilled 45 wells comprised of 15 exploratory and 30 development wells. The Company’s 2000 drilling program resulted in 27 successful oil wells, four gas wells, four service wells and 10 dry holes for a 78% drilling success rate. Average daily production for 2000 was 2,638 boe (a 215% increase over 1999). By December 31, 2000 KeyWest’s daily production had risen to 3,500 boe.
In 2001 KeyWest announced three separate production purchases collectively producing 1,010 boe equivalent per day (78% light oil) in central and southern Alberta. The total price paid for the three properties was approximately $18.2 million for which KeyWest acquired combined estimated reserves of 3.33 million boe.
In December 2001, KeyWest issued Common Shares on a "flow-through" basis for a purchase price of $2.00 per share, pursuant to private placement exemptions, for aggregate gross proceeds of approximately $4.5 million.
During 2001 KeyWest drilled 45 wells comprising 25 exploratory and 20 development wells. The Company’s 2001 drilling program resulted in 18 successful oil wells, 14 gas wells, two service wells and 11 dry holes for a 76% success rate. Average daily production for 2001 was 4,290 boe (a 63% increase over 2000). By December 31, 2001 KeyWest’s production had risen to 5,500 boe/d.
In May 2002, KeyWest sold substantially all of its Saskatchewan assets consisting primarily of its Merid properties for aggregate gross proceeds of approximately $4.6 million. At the time of sale the properties were producing approximately 325 boe/d.
On October 1, 2002, KeyWest closed a production purchase of 2,000 boe/d which is 94% light oil. The property is located in Bashaw, Alberta in close proximity to existing KeyWest production. KeyWest paid approximately $60 million, before adjustments, for total reserves of 7.4 million barrels of oil equivalent (as determined by the independent engineering firm of GLJ). The producing formation is the Devonian Nisku at about 5,600 feet and KeyWest acquired large interests in the property ranging from 85% to 100%.
The addition of this property brings KeyWest's current production to approximately 8,500 boe/d which is 80% oil and 20% gas. Following the purchase, three KeyWest core areas are each producing in excess of 2,000 boe/d.
On October 4, 2002, KeyWest received gross proceeds of $17 million from the issuance of 6,165,480 special warrants, at a price of $2.75 per special warrant. KeyWest anticipates that a second closing will occur on or about November 4, 2002, whereby it will receive additional gross proceeds of approximately $13 million for up to 4,743,610 additional special warrants. Each special warrant is exercisable into one Common Share for no additional consideration, subject to certain adjustments.
KeyWest focuses on properties which can provide near-term cash flow. The Company’s operations are concentrated in areas that have year-round access and an existing infrastructure of facilities and pipelines. KeyWest retains high working interests in its properties and operates virtually all of its drilling and production to control costs and regulate pool development.
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Undeveloped Land
KeyWest’s inventory of undeveloped lands at the years ended December 31, 2001 and 2000 and as at October 1, 2002 is summarized below. The market value of the lands, as set out below, was determined by Seaton Jordan & Associates Ltd. (petroleum land management consultants) by analysing the most current prices paid at land sales for properties in the immediate vicinity of the lands being valuated.
October 1, | Years ended December 31, | |||
2002 | 2001 | 2000 | ||
Acres | Gross | Net | Gross | Net | Gross | Net |
Alberta(1) | 111,353 | 91,104 | 82,816 | 69,159 | 45,361 | 35,844 |
British Columbia | 2,810 | 937 | 2,810 | 937 | 2,810 | 937 |
Saskatchewan | 1,966 | 983 | 31,343 | 18,417 | 32,275 | 22,157 |
Total | 116,129 | 93,024 | 116,969 | 88,513 | 80,446 | 58,938 |
Value of net acres ($millions) | $ 7.71 | $ 6.93 | $ 4.48 |
Average working interest | 80% | 76% | 73% |
Notes:
(1)
Includes an 89% W.I. in 5,275 gross (4,708 net) undeveloped acres acquired by the Company in connection with its Bashaw Acquisition.
Drilling Activity – Wells Drilled
KeyWest drilled, or participated in drilling, the following wells during the last two years and in the nine months to October 1, 2002:
Nine month period to October 1, | Years ended December 31, | |||
2002 | 2001 | 2000 | ||
Gross | Net | Gross | Net | Gross | Net |
Oil | 32 | 31.5 | 18 | 14.85 | 27 | 24.5 |
Gas | 8 | 7.6 | 14 | 11.15 | 4 | 4.0 |
Service | - | - | 2 | 2.00 | 4 | 4.0 |
Dry | 10 | 8.6 | 11 | 10.00 | 10 | 9.6 |
Total | 50 | 47.7 | 45 | 38.00 | 45 | 42.1 |
Exploratory | 19 | 17.2 | 25 | 19.00 | 15 | 14.3 |
Development | 31 | 30.5 | 20 | 19.00 | 30 | 27.8 |
Total | 50 | 47.7 | 45 | 38.00 | 45 | 42.1 |
Average working interest
95.4%
84.4%
94%
Notes:
(1)
“Gross” refers to all wells in which KeyWest has an interest.
(2)
“Net” refers to KeyWest’s aggregate percentage interest in the gross wells.
(3)
As at October 1, 2002, KeyWest had not drilled, or participated in drilling any wells in connection with the Bashaw Acquisition.
Production Summary
The following tables set out the Company’s net average daily volumes, before royalties, attributable to its producing properties as of December 31, 2001 and October 1, 2002. The properties are listed in descending order of production volumes as of December 31, 2001.
Oil and NGLs Production
Nine month period to October 1, 2002 | Year Ended December 31, 2001 | |||
Property | bbls/d | % of Total | bbls/d | % of Total |
Chin Coulee, Alta. | 2,171 | 33% | 2,041 | 70% |
Carbon, Alta. | 377 | 6% | 510 | 17% |
Merid, Sask. | - | - | 191 | 7% |
Bashaw, Alta.(1) | 2,024 | 31% | 144 | 5% |
Bassano, Alta. | 2,019 | 30% | 36 | 1% |
Total | 6,591 | 100% | 2,922 | 100% |
Note:
(1)
Proforma amount assumes production for the Bashaw Acquisition for the nine month period to October 1, 2002.
Natural Gas Production
Nine month period to October 1, 2002 | Year Ended December 31, 2001 | |||
Property | mcf/d | % of Total | mcf/d | % of Total |
Carbon, Alta. | 3,694 | 32% | 4,638 | 56% |
Merid, Sask. | - | - | 1.867 | 23% |
Eastern Area, Alta. | 5,286 | 45% | 671 | 8% |
Enchant, Alta. | - | - | 497 | 6% |
Bashaw, Alta.(1) | 1,224 | 11% | 243 | 3% |
Other | 1,456 | 12% | 290 | 4% |
Total | 11,660 | 100% | 8,206 | 100% |
Note:
(1)
Proforma amount assumes production for the Bashaw Acquisition for the nine month period to October 1, 2002.
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Principal Producing Properties of KeyWest
KeyWest's properties were evaluated as of December 31, 2001 by the independent engineering firm of Gilbert Laustsen Jung Associates Ltd. ("GLJ") in their report dated March 11, 2002 (the "Year-End GLJ Report"); subsequently an updated evaluation of KeyWest's properties was prepared by GLJ effective October 1, 2002 in a report dated October 9, 2002 (the "Interim GLJ Report"). The following is a description of KeyWest's principal producing oil and gas properties (including the Chin Coulee, Carbon, Bassano, Eastern Gas, Bashaw and Carrot Creek properties located in Alberta and the Merid property in Saskatchewan) as of December 31, 2001, as reflected in the Year-End GLJ Report. Where, based on the Interim GLJ Report, there has been a material change in reserves assigned to a property subsequent to year-end, such change is noted in the related proper ty description. In this section all references to reserves and production are working interest numbers before deduction of royalties payable to others. All reserve numbers have been obtained from the Year-End GLJ Report or Interim GLJ Report. In the property descriptions set out below, probable reserves volumes have been reduced by 50% to account for associated risk. The properties comprise over 95% of KeyWest’s reserves and are listed in descending order of “proven” reserves volumes as of December 31, 2001.
Chin Coulee
The Chin Coulee property is located in Townships 6, 7 and 8, Ranges 14 and 15, W4M approximately 40 miles southeast of Lethbridge, Alberta. Oil production is mainly attributable to the Sawtooth formation with minor contributions from the Mannville formation. During 2001 KeyWest drilled five successful wells on the property and by year-end owned a 100% working interest in 34 producing Sawtooth and Basal Mannville oilwells and in five Sawtooth zone water disposal wells. KeyWest also has a 100% interest in a central oil battery which is capable of handling 37,000 bbls/day of fluid and will be expanded to handle 47,000 bbls/day of fluid in 2002. Forecast proven average daily working interest production from Chin Coulee in 2002 is 2,201 bopd. Proven producing reserves of 4.3 mmbbls oil were assigned to KeyWest’s interests in this area. Proven non-producing reserves of 562 mbbls were assigned based on the drilling of three infill wells to be drilled in 2002. Risked probable reserves of 350 mbbls were assigned based on five additional locations. In 2000 KeyWest flowlined all its wells into a central treater; as a consequence operating costs were reduced significantly.
Carbon
The Carbon property is located in Townships 29 and 30, Ranges 23, 24 and 25 W4M, approximately 45 miles northeast of Calgary. As of December 31, 2001, KeyWest had an average working interest of 78% in 60 producing wells completed in the Leduc, Nisku, Pekisko, Ellerslie, Viking and Belly River zones in this area. KeyWest operates, and owns average working interests of 92% and 93% respectively, in an oil battery and water disposal facility and in a sour gas processing plant and sulphur recovery system. KeyWest expanded capacity of the oil battery and water disposal system to increase fluid handling capacity from 3,000 to 6,000 barrels per day of fluid. Capacity of the sour gas processing plant and sulphur recovery system is 2150 mcfd with current throughput of approximately 500 mcfd solution gas. In addition, KeyWest owns and operates a 100% working int erest in an 8,000 mcfd gas plant with current throughput of 1,850 mcfd. The Company’s share of forecast proven production from the Carbon area for 2002 is 4,400 mcfd natural gas and 483 bbls per day oil and natural gas liquids (ngls). Proven producing working interest reserves of 10.0 bcf natural gas and 894 mbbls oil and ngls were assigned to the Carbon property. As of December 31, 2001 proven non-producing reserves of 2.3 bcf natural gas and 793 mbbls of oil and ngls were also assigned. The non-producing oil reserves reflect incremental reserves attributable to a waterflood scheme implemented in the latter part of 2000. Risked probable reserves of 1.1 bcf natural gas and 159 mbbls of oil and ngls were assigned based on improved recovery factors and increased drainage areas together with potential tie-in of a shut in Viking gaswell at 6-12-30-25W4M.
Bassano
Bassano is a light oil project located 90 miles southeast of Calgary. When KeyWest acquired the property at the beginning of December 2001 it was producing 500 boepd (including minor associated gas) from the Glauconite formation. Based on the Year-End GLJ Report, the Company's share of forecast production from the Bassano area for 2002 was 954 bbls per day of oil and ngls and 419 mcfd of natural gas. KeyWest expects to exceed this production forecast: by April, 2002, through a combination of workovers and recompletions on existing wells together with new drilling, KeyWest had increased production on the property to better than 1,000 bopd and 800 mcfd of gas. As at December 31, 2001 proved producing reserves of 1,864 mbbls of oil and ngls and 0.77 bcf natural gas, proven non-producing reserves of 528 mbbls of oil and ngls and 0.3 bcf natural gas, and risked probab le reserves of 320 mbbls of oil and ngls and 0.16 bcf natural gas were assigned to KeyWest's interest in the property.
On October 1, 2002, the Interim GLJ Report assigned proved producing reserves of 4,706 mbbls of oil and ngls and 2.2 bcf natural gas, proven non-producing reserves of 910 mbbls of oil and ngls and 0.4 bcf natural gas and risked probable reserves of 980 mbbls of oil and ngls and 0.514 bcf natural gas to KeyWest's interests. Through additional drilling and workovers, current production has been increased to approximately 2,000 boe/d (90% oil).
East Central Gas
The eastern gas project area comprises five separate properties in east central Alberta located approximately 125 to 165 miles northeast of Calgary. The lands are all situated in close proximity to pipelines and there is considerable unused plant capacity in the immediate area. The area has multi-zone gas potential and is mainly productive in the Viking, Colony and McLaren zones. During 2001 KeyWest drilled six successful gas wells in the project in which KeyWest’s average working interest is 92%. KeyWest’s forecast proven average daily working interest production from the area for 2002 is 3,390 mcfd. As at December 31, 2001, KeyWest's interests comprised proven producing reserves of 5.5 bcf gas, proven non-producing reserves of 2.5 bcf, and risked probable reserves of 0.8 bcf. On October 1, 2002, as a result of further successful drilling i n the area, the Interim GLJ Report assigned proved producing reserves of 7.12 bcf of gas, proven non-producing reserves of 5.09 bcf, and risked probable reserves of 1.31 bcf.
Bashaw
Bashaw, a property located approximately 110 miles northeast of Calgary, was acquired in May 2001. Production is mainly comprised of light oil and liquids from the Nisku and Leduc with some associated gas also being produced. Proven producing reserves of 688 mbbls of oil and liquids and 0.7 bcf natural gas and proven non-producing reserves of 201 mbbls of oil and liquids and 0.5 bcf natural gas were assigned to KeyWest’s interests in the GLJ Year-End Report. Risked probable reserves of 281 mbbls oil and 0.6 bcf gas were also assigned based on converting several wells in the Bashaw D-3A Pool to water injection, thereby increasing recoverable reserves. The Company’s share of forecast production from the area for 2002 was 360 bbls/day oil and liquids and 536 mcfd of gas.
Subsequent to year-end, the Company made a sizeable property purchase in Bashaw immediately south of the Company's existing interests. KeyWest acquired interests ranging from 85 to 100% in 24 wells producing approximately 2,000 boe/d (net to KeyWest) of light Nisku oil with some associated gas. The purchase was effective October 1, 2002 and the related lands were evaluated in the Interim GLJ Report. The purchased lands have been assigned proved producing reserves of 3,165 mbbls oil and ngls and 3.62 bcf gas, proven non-producing reserves of 1,243 mbbls oil and ngls and 167 mmcf gas, and risked probable reserves of 1,039 mbbls oil and ngls and 729 mmcf gas. KeyWest believes that it can realize upside on the property through a combination of workovers and recompletions on existing wells together with infill drilling.
Merid
Merid is an oil and gas exploration project located just inside the western boundary of the Province of Saskatchewan approximately 180 miles east of the City of Calgary. By 2001 year-end KeyWest owned various interests in a total of 29 producing oil and gas wells in the area. Oil is produced from the Bakken and Lodgepole formations and gas from the Viking, Colony and Waseca. Forecast net proven production to KeyWest’s account for 2002 is 170 bopd and 1,045 mmcfd of gas. Total proved reserves of 1.7 bcf natural gas and 455 mbbls oil were assigned to KeyWest’s interest in this area. Risked probable reserves of 0.6 bcf natural gas and 145 mbbls oil were also assigned. Subsequent to year-end (in May, 2002), KeyWest sold its interests in Merid for $4.6 million and accordingly, no reserves are assigned to this property in t he Interim GLJ Report. At the time of sale the property was producing approximately 325 boe/d split approximately evenly between oil and gas. Average production for the four months prior to the sale was 342 boe/d (50/50 oil and gas) and based on cumulative production to May 1, 2002, internal estimates of remaining proven reserves at the time of sale, are 434 mbbls oil and 1.57 bcf gas.
Carrot Creek
As of year-end KeyWest owned a 47.98% working interest in one gas well in the Carrot Creek area located approximately 140 kilometers west of Edmonton, Alberta. KeyWest’s forecast proven production for 2002 is 177 mcfd and 13 bbls per day natural gas liquids. Proven producing reserves of 1.3 bcf natural gas and 91 mbbls natural gas liquids were assigned to KeyWest’s interest in the Mannville zone in this well. Proven non-producing reserves of 0.2 bcf natural gas and 14 mbbls ngls were assigned to the Viking zone in the well and risked probable reserves of 0.1 bcf natural gas and 8 mbbls ngls were assigned based on the probability of increased drainage area in the Viking.
The foregoing properties account for over 95% of KeyWest’s total proven reserves. The remaining reserves consist of minor interests at Crossfield, Ghost Pine, Pine Creek and Saddle Hills.
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Oil and Gas Wells
The following table summarizes KeyWest’s working interest as at December 31, 2001 based on the Year-End GLJ Report and as of October 1, 2002 based on the Interim GLJ Report in its principal producing wells and in non-producing wells which are believed capable of production. The wells in this table comprise in excess of 95% of KeyWest’s proven oil and gas reserves value as of their respective dates.
As of October 1, 2002 | As of December 31, 2001 | ||||||||||
Oil Wells | Gas Wells | Oil Wells | Gas Wells | ||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
Alberta | 173.0 | 140.3 | 50.0 | 37.5 | 130.0 | 99.3 | 43.0 | 31.0 |
Saskatchewan | - | - | - | - | 22.0 | 8.3 | 7.0 | 2.1 |
Total | 173.0 | 140.3 | 50.0 | 37.5 | 152.0 | 107.6 | 50.0 | 33.0 |
Notes:
(1)
“Gross Wells” refers to all wells in which KeyWest has an interest;
(2)
“Net Wells" refers to the aggregate of the percentage interest of KeyWest in the Gross Wells.
(3)
Includes 24 gross (22 net) wells acquired pursuant to the Bashaw Acquisition.
Reserves and Future Revenue
KeyWest’s oil and gas reserves as of December 31, 2001 were evaluated by GLJ, an independent engineering firm, in a report dated March 11, 2002. An updated evaluation of KeyWest's properties was prepared by GLJ effective October 1, 2002 in a report dated October 9, 2002. The results of the respective GLJ reports are summarized in the following tables. Future net production revenues, including Alberta Royalty Tax Credits to be derived therefrom, as set forth in the following table are stated prior to provision for income taxes and indirect costs and after deduction of royalties.
The present worth of estimated future net production revenue contained in the following table may not be an accurate representation of the fair market value of the reserves. The present worth of future net production revenue is based on certain assumptions regarding future prices and costs; however there is no assurance that such assumed prices and costs will be realized and variances could be material. Assumptions relating to costs, prices for future production and other matters are summarized in the notes following the table. Probable reserve values have been risked at 50%.
Oil and Gas Reserves
December 31, 2001 (based on escalated price assumptions)
Reserves | Present Worth ($mm) | ||||||||
Oil & | Discounted at the Rate of | ||||||||
NGLs mbbls | Gas mmcf | Undiscounted | 10% | 15% | 20% | ||||
Proven Reserves | ||||||
Producing | 8,176 | 20,963 | $ 165.5 | $ 110.7 | $ 96.1 | $ 85.2 |
Non-Producing | 50 | 4,627 | 13.4 | 7.8 | 6.4 | 5.5 |
Undeveloped | 2,163 | 1,393 | 33.9 | 20.6 | 16.9 | 14.1 |
Total Proven | 10,389 | 26,983 | $ 212.8 | $ 139.1 | $ 119.4 | $ 104.8 |
Probable Reserves | 2,525 | 7,024 | 25.2 | 11.4 | 8.7 | 6.9 |
Total Proven Plus | 12,914 | 34,007 | $ 238.0 | $ 150.5 | $ 128.1 | $ 111.7 |
Probable |
Oil and Gas Reserves
October 1, 2002 (based on escalated price assumptions)
Reserves | Present Worth ($mm) | ||||||||
Oil & | Discounted at the Rate of | ||||||||
NGLs mbbls | Gas mmcf | Undiscounted | 10% | 15% | 20% | ||||
Proven Reserves | ||||||
Producing | 13,911 | 23,873 | $ 278.4 | $ 186.5 | $ 162.1 | $ 144.3 |
Non-Producing | 162 | 6,904 | 21.8 | 13.9 | 11.8 | 10.3 |
Undeveloped | 3,124 | 1,574 | 47.1 | 29.4 | 24.5 | 20.8 |
Total Proven | 17,197 | 32,351 | $ 347.3 | $ 229.8 | $ 198.4 | $ 175.4 |
Probable Reserves | 5,769 | 8,610 | 53.0 | 27.3 | 21.6 | 17.7 |
Total Proven Plus | 22,966 | 40,961 | $ 400.3 | $ 257.1 | $ 220.0 | $ 193.1 |
Probable |
Oil and Gas Reserves
December 31, 2001(based on constant pricing)
Reserves | Present Worth ($mm) | ||||||||
Oil & | Discounted at the Rate of | ||||||||
NGLs mbbls | Gas mmcf | Undiscounted | 10% | 15% | 20% | ||||
Proven Reserves | ||||||
Producing | 8,155 | 20,963 | $ 152.9 | $ 104.4 | $ 91.0 | $ 81.0 |
Non-Producing | 50 | 4,623 | 12.0 | 7.1 | 5.9 | 5.0 |
Undeveloped | 2,154 | 1,393 | 31.7 | 19.3 | 15.8 | 13.3 |
Total Proven | 10,359 | 26,979 | $ 196.6 | $ 130.8 | $ 112.7 | $ 99.3 |
Probable Reserves | 2,496 | 7,036 | 21.8 | 10.3 | 7.9 | 6.2 |
Total Proven Plus | 12,855 | 34,015 | $ 218.4 | $ 141.1 | $ 120.6 | $ 105.5 |
Probable |
Based on the Year-End GLJ Report, the total capital costs net to the Corporation necessary to achieve the estimated future net proved and probable production revenues are estimated to be $14,442,000 over the life of the reserves with $6,934,000, $6,224,000 and $801,000, to be incurred in fiscal years 2002, 2003 and 2004 respectively, and the balance of $483,000 to be spent thereafter.
Oil and Gas Reserves
October 1, 2002(based on constant pricing)
Reserves | Present Worth ($mm) | ||||||||
Oil & | Discounted at the Rate of | ||||||||
NGLs mbbls | Gas mmcf | Undiscounted | 10% | 15% | 20% | ||||
Proven Reserves | ||||||
Producing | 14,091 | 24,390 | $ 384.4 | $ 252.1 | $ 216.7 | $ 190.9 |
Non-Producing | 162 | 7,036 | 24.8 | 15.8 | 13.4 | 11.7 |
Undeveloped | 3,133 | 1,565 | 71.6 | 45.4 | 38.1 | 32.6 |
Total Proven | 17,386 | 32,991 | $ 480.8 | $ 313.3 | $ 268.2 | $ 235.2 |
Probable Reserves | 5,847 | 8,849 | 75.9 | 40.6 | 32.3 | 26.6 |
Total Proven Plus | 23,233 | 41,840 | $ 556.7 | $ 353.9 | $ 300.5 | $ 261.8 |
Probable |
Based on the Interim GLJ Report, the total capital costs net to the Corporation (including those costs associated with the Bashaw Acquisition) necessary to achieve the estimated future net proved and probable production revenues are estimated to be $22,300,000 over the life of the reserves with $1,100,000, $12,800,000 and $8,400,000 to be incurred in fiscal years 2002, 2003 and 2004 respectively.
Notes:
(1)
Reserve volumes are before the deduction of royalty interests. Probable reserve values were reduced by 50% to allow for risk; probable reserve volumes were not reduced. The evaluations of future net production revenues are stated net of royalties, operating costs and future development costs and prior to any provision for income taxes, overhead and interest costs.
(2)
“Proved” reserves as summarized based on price assumptions in the GLJ Report (see note 5) are those reserves estimated as recoverable under current technology and anticipated economic conditions from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. There is relatively little risk associated with proved reserves. The proved reserves are subdivided into the following groups:
(a)
“Proved producing” reserves are those reserves that are actually on production, or if not producing, that could be recovered from existing wells or facilities and where the reasons for the current non-producing status is the choice of the owner rather than the lack of markets or some other reason.
(b)
“Proved non-producing” reserves are those reserves that are not currently producing either due to lack of facilities and/or markets. Such reserves are developed in that proven non-producing reserves are assigned to acreage that has been drilled and proved capable of economic production through drillstem and/or production testing and related technical analysis.
(c)
“Proved undeveloped” reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled.
(3)
“Probable additional” reserves are those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be “proved” under current technology and existing economic conditions or anticipated economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes reasonably expected to be instituted in the future. There is some degree of geological and engineering risk associated with probable reserves. A risk factor of 50 % has been applied to the probable reserve values to reflect this risk.
(4)
All values are shown in Canadian dollars.
(5)
The reference crude oil and natural gas price forecasts used in the Year-End GLJ Report are as follows:
Crude Oil U.S. $/bbl | Natural Gas Cdn. $/mmbtu |
2002 | $20.00 | $4.10 |
2003 | $21.00 | $4.45 |
2004 | $21.00 | $4.50 |
2005 | $21.00 | $4.50 |
2006 | $21.25 | $4.50 |
+ 1.5%/yr. | +0.87%/yr. next 6yrs. |
+1.5%/yr. thereafter |
The reference crude oil and natural gas forecasts used in the Interim GLJ Report are as follows:
Crude Oil U.S. $/bbl | Natural Gas Cdn. $/mmbtu |
2002 (4th quarter) | $28.00 | $4.85 |
2003 | $24.00 | $4.85 |
2004 | $21.00 | $4.50 |
2005 | $21.00 | $4.50 |
2006 | $21.25 | $4.50 |
2007 | $21.75 | $4.50 |
2008 | $22.00 | $4.50 |
+ 1.5%/yr. |
(a)
Crude oil reference prices are the assumed West Texas Intermediate (“WTI”) prices for crude oil at Cushing Oklahoma.
(b)
Natural gas prices are the assumed average spot prices at the Alberta Plant Gate.
-5-
Reconciliation of Reserves (based on constant pricing)
The following tables provide a breakdown of reserves added during 2001 and to October 1, 2002 based on a constant pricing scenario:
Oil & NGLs (mbbls) | Natural Gas (bcf) | |||||
Reserves(1) | Proven | Probable | Total | Proven | Probable | Total |
As at December 31, 2000 | 6,261 | 1,335 | 7,596 | 17.0 | 5.9 | 22.9 |
Drilling | 1,631 | 581 | 2,212 | 7.4 | 1.2 | 8.6 |
Acquisitions | 2,265 | 1,057 | 3,322 | 4.9 | 3.2 | 8.1 |
Revisions | 1,268 | (477) | 791 | 0.7 | (3.3) | (2.6) |
Total Additions | 5,164 | 1,161 | 6,325 | 13.0 | 1.1 | 14.1 |
Production | (1,066) | - | (1,066) | (3.0) | - | (3.0) |
As at December 31, 2001 | 10,359 | 2,496 | 12,855 | 27.0 | 7.0 | 34.0 |
Oil & NGLs (mbbls) | Natural Gas (bcf) | |||||
Reserves(1) | Proven | Probable | Total | Proven | Probable | Total |
As at December 31, 2001 | 10,359 | 2,496 | 12,855 | 27.0 | 7.0 | 34 |
Drilling | 3,755 | 1,553 | 5,308 | 7.2 | 1.7 | 8.9 |
Acquisitions | 4,453 | 2,110 | 6,563 | 3.8 | 1.5 | 5.3 |
Dispositions | (455) | (289) | (744) | (1.7) | (1.2) | (2.9) |
Revisions | 418 | (23) | 395 | (0.4) | (0.2) | (0.6) |
Total Additions | 8,171 | 3,351 | 11,522 | 8.9 | 1.8 | (0.7) |
Production | (1,144) | - | (1,144) | (2.9) | - | (2.9) |
As at October 1, 2002 | 17,386 | 5,847 | 23,233 | 33.0 | 8.8 | 41.8 |
(1)
Reserves are the Company’s reserves before the deduction of any royalties.
Reserve Life Index
KeyWest’s reserve life index, comparing total reserves and production for the 2001 and 2000 fiscal year-ends, is as follows:
2001 | 2000 |
Years | Proven | Probable | Proven | Probable |
Oil | 7.3 | 9.1 | 7.6 | 9.2 |
Gas | 7.7 | 9.7 | 5.9 | 7.9 |
Combined | 7.4 | 9.3 | 7.0 | 8.7 |
-6-
History
The following table shows the Company's average working interest sales volume before deduction of royalties payable to others, average netbacks received and net oil and gas capital expenditures incurred for each of the last eight fiscal quarters and the years then ended:
Average Daily Sales
Three Months Ended | |||||
Mar 31, 2001 | June 30, 2001 | Sept 30, 2001 | Dec 31, 2001 | Total | |
Oil (bbl/d) | 2,522 | 2,803 | 3,127 | 3,225 | 2,922 |
Gas (mcf/d) | 7,657 | 7,337 | 8,490 | 9,319 | 8,206 |
Combined (boepd) | 3,798 | 4,026 | 4,542 | 4,779 | 4,290 |
Three Months Ended | |||||
Mar 31, 2000 | June 30, 2000 | Sept 30, 2000 | Dec 31, 2000 | Total | |
Oil (bbl/d) | 1,132 | 1,203 | 1,550 | 2,062 | 1,489 |
Gas (mcf/d) | 6,194 | 6,978 | 6,563 | 7,822 | 6,893 |
Combined (boepd) | 2,164 | 2,366 | 2,644 | 3,366 | 2,638 |
Oil ($ per bbl)
Three Months Ended | |||||
Mar 31, 2001 | June 30, 2001 | Sept 30, 2001 | Dec 31, 2001 | Total | |
Sales revenue(1) | $ 29.26 | $ 29.47 | $ 31.61 | $ 17.73 | $ 26.74 |
Royalties | (5.04) | (5.00) | (6.04) | (3.91) | (4.99) |
Operating costs(2) | (4.76) | (3.26) | (4.75) | (5.04) | (4.48) |
$ 19.46 | $ 21.21 | $ 20.82 | $ 8.78 | $ 17.27 | |
Oil prices | $ 28.25 | $ 30.62 | $ 32.45 | $ 18.46 | $ 26.81 |
Three Months Ended | |||||
Mar 31, 2000 | June 30, 2000 | Sept 30, 2000 | Dec 31, 2000 | Total | |
Sales revenue | $ 30.13 | $ 32.12 | $ 36.12 | $ 28.47 | $ 31.52 |
Royalties | (5.92) | (5.71) | (7.79) | (6.77) | (6.67) |
Operating costs(2) | (5.80) | (3.33) | (2.73) | (4.35) | (3.99) |
$ 18.41 | $ 23.08 | $ 25.60 | $ 17.35 | $ 20.86 | |
Note:
(1)
Includes hedging gains or losses.
(2)
Operating costs are expenses incurred in the operation of producing properties and include items such as field staff salaries, power, fuel, chemicals, repairs and maintenance, property taxes, processing and treating fees, overhead fees and other costs.
Natural Gas Netbacks ($ per mcf)
Three Months Ended | |||||
Mar 31, 2001 | June 30, 2001 | Sept 30, 2001 | Dec 31, 2001 | Total | |
Sales revenue(1) | $ 10.97 | $ 5.94 | $ 3.33 | $ 2.98 | $ 5.57 |
Royalties(2) | (2.78) | (1.21) | (0.54) | (0.11) | (1.08) |
Operating costs | (0.68) | (1.07) | (0.87) | (1.04) | (0.92) |
$ 7.51 | $ 3.66 | $ 1.92 | $ 1.83 | $ 3.57 | |
Natural gas prices | $ 8.98 | $ 5.94 | $ 3.33 | $ 2.98 | $ 5.11 |
Three Months Ended | |||||
Mar 31, 2000 | June 30, 2000 | Sept 30, 2000 | Dec 31, 2000 | Total | |
Sales revenue | $ 3.25 | $ 3.99 | $ 4.57 | $ 8.90 | $ 5.37 |
Royalties(2) | (0.49) | (0.86) | (0.76) | (2.99) | (1.37) |
Operating costs(3) | (0.54) | (0.63) | (0.68) | (0.83) | (0.68) |
$ 2.22 | $ 2.50 | $ 3.13 | $ 5.08 | $ 3.32 | |
Note:
(1)
Includes hedging gains or losses.
(2)
After inclusion of ARTC.
(3)
Operating costs are expenses incurred in the operation of producing properties and include items such as field staff salaries, power, fuel, chemicals, repairs and maintenance, property taxes, processing and treating fees, overhead fees and other costs.
Net Oil and Gas Capital Expenditures ($000's)
Three Months Ended | |||||
Mar 31, 2001 | June 30, 2001 | Sept 30, 2001 | Dec 31, 2001 | Total | |
Exploration and land (including drilling) | $ 5,307 | $ 2,931 | $ 5,406 | $ 4,761 | $ 18,405 |
Development (including facilities) | 6,156 | 2,986 | 4,393 | 4,039 | 17,574 |
Other | 19 | 4 | 13 | 28 | 64 |
Property acquisitions, net of dispositions | 2,134 | 9,328 | 3,984 | 4,535 | 19,981 |
$ 13,616 | $ 15,249 | $ 13,796 | $ 13,363 | $ 56,024 | |
Three Months Ended | |||||
Mar 31, 2000 | June 30, 2000 | Sept 30, 2000 | Dec 31, 2000 | Total | |
Exploration and land (including drilling) | $ 3,418 | $ 2,165 | $ 2,031 | $ 4,600 | $ 12,214 |
Development (including facilities) | 3,554 | 3,814 | 2,475 | 4,286 | 14,129 |
Other | 33 | 7 | 26 | 42 | 108 |
Property acquisitions, net of dispositions | (582) | (425) | 3,949 | 1,332 | 4,274 |
$ 6,423 | $ 5,561 | $ 8,481 | $ 10,260 | $ 30,725 | |
-7-
Marketing
Oil and Natural Gas Liquids
During 2001, KeyWest marketed its crude oil and ngls under thirty day evergreen contracts mainly to senior producers.
Through these arrangements the Company received an average of Cdn. $26.81 per bbl. Medium gravity oil accounted for 2,041 bbls per day or 70% of the total, light oil comprised 602 bbls per day or 21% of the total, 2% was ngls production which averaged 89 bbls per day and the remaining 7%, or 190 bbls per day, was heavy oil.
During 2001 KeyWest implemented two separate hedges, each fixing the heavy oil differential on 500 bopd. The first was put in at $8.25 US/bbl in late 2000; the second during the summer of 2001 at $10.45/bbl. Both hedges were closed out at a slight loss in later summer 2001. Subsequent to year-end light oil as a percentage of total production had doubled to 40%.
Natural Gas
KeyWest’s 2001 natural gas price averaged Cdn. $5.11 per mcf.
During 2001, KeyWest sold virtually all of its gas on the spot market, mainly to senior producers. KeyWest had a financial hedge in place for 5.7 mmcfd at $13.50 Cdn. per mcf for February and March, 2001 which netted $1.4 million.
Government Regulation
The oil and natural gas industry is subject to extensive controls and regulations governing its operations including land tenure, exploration, development, production, refining and marketing imposed by various levels of government. The governments of Canada, Alberta, Saskatchewan and British Columbia, acting in concert, have enacted legislation with respect to pricing and taxation of oil and natural gas. Outlined below are some of the principal aspects of the legislation, regulations and agreements governing the oil and gas industry.
Pricing and Marketing – Oil and Natural Gas
The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends in part on oil quality, prices of competing oils, distance to market and the value of refined products. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude and two years in the case of heavy crude, providing that an order approving such export has been obtained from the National Energy Board ("NEB"). Any oil export to be made pursuant to a contract of longer duration requires an exporter to obtain an export licence from the NEB which in turn requires the approval of the Governor in Council.
In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts meet certain criteria prescribed by the NEB and the government of Canada. As is the case with oil, natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor in Council approval.
The governments of Alberta and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.
The North American Free Trade Agreement
On January 1, 1994 the North American Free Trade Agreement ("NAFTA") among the Governments of Canada, the U.S. and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use, (ii) impose an export price higher than the domestic price, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.
The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.
-8-
Provincial Royalties and Incentives
In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owners and the lessee although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.
From time to time the governments of Canada, Alberta, British Columbia and Saskatchewan have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced production projects.
Alberta
Regulations made pursuant to the Alberta Mines and Minerals Act provide various incentives for exploring and developing oil reserves on Alberta Crown lands. Oil produced from horizontal well extensions commenced at least five years after the well was originally spudded may qualify for a royalty reduction. Wells drilled prior to September 1, 1990, and reactivated between November 1, 1991 and October 1, 1992, having had no production between September 1, 1990 and November 1, 1991, are entitled to a five year royalty exemption to a maximum of 25,000 barrels. A 50,000 barrel royalty exemption is available to production from a well that has not produced for a 12 month period, if resuming production prior to February 1, 1993, or for a 24 month period if resuming production after January 1993. In addition, oil production from eligible new fields and new pool wildcat wel ls and deeper pool test wells spudded or deepened after September 30, 1992 is entitled to a 12 month royalty exemption to a maximum of $1 million. Oil produced from low productivity wells, enhanced recovery schemes such as injection wells, and experimental projects is also subject to royalty reductions. Gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 metres is subject to a royalty exemption, the amount of which depends on the depth of the well.
The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30% in the case of new gas, and between 15% and 35% in the case of old gas, depending upon a prescribed or corporate average reference price.
In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC (Alberta Royalty Tax Credit) program. The ARTC program is based on a price-sensitive formula, with the ARTC rate varying between 75%, at prices for oil below $100 per cubic metre ($16 per barrel), and 25%, at prices above $210 per cubic metre ($33 per barrel). Royalty tax credits under this program are earned to a maximum of $2.0 million of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the prior quarter.
Oil and natural gas royalty holidays and reductions for specific wells reduce the amount of Crown royalties paid by the Corporation to the provincial governments. The ARTC program provides a rebate on Crown royalties paid in respect of eligible producing properties. Both of these incentives increase the net income of the Corporation.
Saskatchewan
Effective January 1, 1994, the Government of Saskatchewan revised its fiscal regime for the oil and gas industry. Some royalties on wells existing as of that date will remain unchanged and therefore subject to various periods of royalty reduction. While a number of incentives were eliminated or reduced, such as incentives for vertical infill wells and lower cost horizontal wells, new incentive programs were initiated to encourage greater exploration and development activity in the province. The new fiscal regime provides an incentive to encourage the drilling of new vertical oil wells through a revised royalty structure for new vertical oil wells and incremental production from new or expanded water flood projects. This "third tier" Crown royalty rate is price sensitive and varies between heavy and non-heavy oil (from a minimum of 10% for heavy oil at a base price to a maximum of 35% for non-heavy oil at a price above the base price). Previous time-based royalty holidays applicable to vertically drilled oil wells have been replaced with volume-based royalty reduction incentives in which a maximum royalty of 5% will apply to various volumes depending on the depth and nature of the well, up to 157,000 barrels of oil in the case of deep exploratory wells. The maximum royalty applicable to the first 75,000 barrels of oil has been increased from 5% to 10% for production from certain horizontal wells. In addition, royalty holidays for deep horizontal oil wells have been replaced with a 157,000 barrel volume incentive 5% maximum royalty. Oil production from qualifying reactivated oil wells are subject to a maximum new royalty rate of 5% for the first five years following re-activation in the case of wells reactivated after 1993 and shut-in or suspended prior to January 1, 1993. With respect to qualifying exploratory natural gas wells , the first 900 million cubic feet of natural gas produced will be subject to an incentive maximum royalty rate of 5%.
Environmental Regulation
The oil and gas industry in Canada is subject to environmental regulations pursuant to a variety of provincial and federal legislation. An environmental assessment and review may be required prior to initiating exploration or development projects or undertaking significant changes to existing projects. Environmental legislation provides for restrictions and prohibitions on oil spills and releases on emissions of various substances produced in association with certain oil and gas operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in suspension or revocation of necessary licences and authorizations, civil liability for pollution damage and the imposition of fines and penalties. Environmental legislation in Alberta has undergone a major revision to update and consolidate the various pieces of legislation into the Environmental Protection and Enhancement Act (the "EPEA"), which came into force on September 1, 1993. The EPEA brings a wider range of activities within the scope of environment regulation. Environmental standards and the penalties are generally stricter under the EPEA than under the environmental regulatory regime it replaces. The Corporation is committed to meeting its responsibilities to protect the environment wherever it operates and to making financial provision for protection of the environment relative to operating activities and capital projects. KeyWest has commissioned detailed independent safety and environmental audits of each of its core areas together, Area-specific Emergency Response Plans. The Corporation has also conducted in-house and field level emergency simulation drills. Environmental and safety procedures are updated on an ongoing basis.
-9-
MANAGEMENT’S DISCUSSION AND ANALYSIS
Overview
KeyWest achieved strong financial results in 2001 with higher production volumes offsetting lower product prices. Production growth in 2001 was the result of both successful drilling activities and property acquisitions, whereas the Company’s growth in 2000 was mainly attributable to drilling.
Cash Flow and Earnings Summary
$000’s (except per share numbers) | 2001 | 2000 |
Cash flow from operations | $ | 25,085 | $ | 17,631 |
Cash flow from operations per share (basic) | $ | 0.53 | $ | 0.37 |
Earnings | $ | 9,017 | $ | 6,957 |
Earnings per share (basic) | $ | 0.19 | $ | 0.15 |
Oil and Gas Revenue
As a result of the Company’s successful drilling and acquisition program, gross production revenue increased 48% to $45.2 million from $30.6 million 2000. Included in this amount is a net $1.3 million hedging gain earned mainly in the first quarter. The revenue contributions were 63% oil and 37% gas, compared to 56% oil and 44% gas in the prior year.
KeyWest’s average oil price was down 15% to $26.81 per bbl versus $31.52 per bbl for 2000, while gas was 5% lower at $5.11 per mcf compared to $5.37 per mcf in 2000.
The oil netback decreased 17% to $17.27 from $20.86 per bbl in 2000, reflecting lower prices and slightly higher operating costs. The gas netback increased 7% to $3.57 per mcf as compared to $3.33 in 2000 due to the first quarter hedging gains.
KeyWest’s rapid growth continues with a projected 31% increase in 2002 production revenues to approximately $59 million. This forecast is based upon 2002 production volumes increasing to 6,065 boepd and assumes a West Texas Intermediate oil price of $22.50 US per bbl and a gas price of $3.75 Cdn. per mcf. See the section titled "Production" on page 9 of the Company's annual report for more information about the Company's increasing production.
Oil and Gas Analysis
The tables below comprise a summary of comparative operations (including netbacks) on a boe basis for 2001 and 2000 together with a breakdown of netbacks by product for 2001.
2001 | 2000 | % Change | |
Production | 4,290 boe/day | 2,638 boe/day | 63% |
($000’s) | ($/boe) | ($000’s) | ($/boe) | (total) | (/boe) |
Field Netback: | ||||||
Oil and gas production | $ 43,901 | $ 28.04 | $ 30,641 | $ 31.82 | 43 | (12) |
revenue | ||||||
Hedging gains | 1,296 | 0.83 | - | - | 100 | 100 |
Gross revenue | 45,197 | 28.87 | 30,641 | 31.82 | 48 | (9) |
Royalties | (8,560) | (5.47) | (7,051) | (7.32) | 21 | (25) |
Operating expenses | (7,532) | (4.81) | (3,876) | (4.03) | 94 | 19 |
FIELD NETBACK | 29,105 | 18.59 | 19,714 | 20.47 | 48 | (9) |
General and administrative | (2,678) | (1.71) | (2,014) | (2.09) | 33 | (18) |
Interest income | - | - | 153 | 0.16 | (100) | (100) |
Interest expense | (942) | (0.60) | (25) | (0.03) | 3,668 | 1,900 |
Current taxes | (400) | (0.26) | (197) | (0.20) | 103 | (30) |
CASH FLOW NETBACK | 25,085 | 16.02 | 17,631 | 18.31 | 42 | (13) |
Depletion and Depreciation | (10,457) | (6.68) | (5,737) | (5.96) | 82 | 12 |
Site restoration | (658) | (0.42) | (318) | (0.33) | 107 | 27 |
Future income taxes | (4,953) | (3.16) | (4,619) | (4.80) | 7 | (34) |
NET INCOME | $ 9,017 | $ 5.76 | $ 6,957 | $ 7.22 | 30 | (20) |
Netback by Product | |||
Oil | Natural Gas | 2001 Total | |
2001 Production | 2,922 bbls/day | 8,206 mcf/day | 4,290 boe/day |
(thousands) | ($/bbl) | (thousands) | ($/mcf) | (thousands) | ($/boe) |
Field Netback: | ||||||
Production revenue | $ 28,587 | $ 26.81 | $ 15,314 | $ 5.11 | $ 43,901 | $ 28.04 |
Hedging gain (loss) | (75) | (0.07) | 1,371 | 0.46 | 1,296 | 0.83 |
Total revenue | 28,512 | 26.74 | 16,685 | 5.57 | 45,197 | 28.87 |
Royalties | (5,317) | (4.99) | (3,243) | (1.08) | (8,560) | (5.47) |
Operating expenses | (4,778) | (4.48) | (2,754) | (0.92) | (7,532) | (4.81) |
FIELD NETBACK | $ 18,417 | $ 17.27 | $ 10,688 | $ 3.57 | $ 29,105 | $ 18.59 |
Royalties
Oil and gas royalties were $8.6 million as compared to $7.1 million in 2000. Royalties decreased from 21% of revenue in 2000 to 19% in 2001. Part of the decrease is the result of lower prices in 2001. In addition, 2000 royalties were unusually high relative to revenues because the Company’s Crown gas royalties were assessed at an average Alberta reference price of $3.90 per mcf (notwithstanding that a portion of the Company’s gas was actually contracted at $2.94 per mcf).
Operating Expenses
Operating expenses increased to $7.5 million in the past year as compared to $3.9 million in 2000. On a barrel of oil equivalent basis, operating costs increased 19% to $4.81 as compared to $4.03 in 2000. The increase reflects higher power costs in the first quarter of 2001 and the acquisition of properties with higher initial operating costs.
Operating costs are expected to decrease in 2002 to $4.70 per boe as power costs have normalized and KeyWest is implementing efficiency measures on its newly-acquired properties.
General and Administrative Expenses
Net general and administrative expenses increased to $2.7 million as compared to $2.0 million in 2000. On a barrel of oil equivalent basis, general and administrative expenses decreased 18% to $1.71 per boe from $2.09 per boe because of higher production volumes which resulted in lower unit costs. Overhead recoveries on operated properties increased 44% from last year due to the increased capital activity undertaken in fiscal 2001. The following table summarizes general and administrative expenses:
$000’s | 2001 | 2000 |
Gross expense | $ | 3,218 | $ | 2,389 |
Overhead recoveries | (540 ) | (375 ) |
Net expense | $ | 2,678 | $ | 2,014 |
Interest Expense
Interest expense increased to $942,000 from $25,000 in 2000 due to the increase in borrowings on the credit facility. The prior year interest was minimal as the Company had only minor overdraft positions in the fourth quarter of 2000. KeyWest’s effective interest rate on an average bank debt of $17 million was 5.5%. In 2002, further bank debt increases will result in higher interest expenses.
Depletion and Depreciation
The Company’s depletion and depreciation expense increased to $10.5 million from $5.7 million; however on a boe basis it only increased 12% to $6.68 from $5.96 in 2000. The increase in depletion is the result of increased finding and development costs.
Site Restoration
The current year provision for site restoration of $658,000 ($0.42 per boe) increased from $318,000 ($0.33 per boe) in 2000 due to the increase in the number of wells and higher well abandonment estimates. The following table summarizes the site restoration provision reported on the Company’s year-end balance sheets:
2001 | 2000 |
Opening provision | $ 443,488 | $ 77,600 |
Provision for the year | 657,899 | 317,801 |
Provision acquired - corporate acquisition | - | 48,087 |
Actual costs incurred | (111,229 ) | - |
Closing provision | $ 990,158 | $ 443,488 |
Income Taxes
Current taxes for 2001 and 2000 are related exclusively to the federal Large Corporations Tax and the Saskatchewan Resource Surcharge. The increase to $400,000 from $196,938 last year is due to the increase in the size of the Company’s capital base and the increase in revenues from Saskatchewan properties.
The total tax provision as a percentage of pre-tax earnings was 37% compared to 41% last year. The decrease reflects the benefit of the Alberta provincial income tax rate reduction. In addition, the Company’s resource allowance benefit increased this year due to increased production on freehold lands.
The following table summarizes the approximate tax pools at December 31, 2001:
($000's) | Annual Deduction Rate | |
Canadian oil and gas property expense | 10% | $32,980 |
Canadian development expense | 30% | 12,010 |
Canadian exploration expense | 100% | 7,425 |
Undepreciated capital cost | 25% | 29,775 |
Share issue costs | 20% | 580 |
Non-capital losses | 100% | 8,620 |
$91,390 | ||
Based on forecasted cash flow and capital spending, KeyWest does not expect to be cash taxable for at least another year and a half.
Cash Flow from Operations and Earnings
Cash flow from operations was $25.1 million which is a 42% increase over $17.6 million achieved in 2000. Higher production volumes offset lower prices. Cash flow per share increased 43% to $0.53 per share in 2001. On a netback basis, cash flow decreased by 13% to $16.02 per boe versus $18.31 per boe one year ago because of lower prices.
The increase in cash flow and the reduction in tax rates resulted in a 30% improvement in earnings to $9.0 million as compared to $6.9 million in 2000.
KeyWest projects 2002 cash flow of approximately $30 million ($0.60 per share) and earnings of $8.6 million ($0.17 per share). The increase in cash flow is due to the 41% increase in production for 2002.
KeyWest’s cash flow and earnings sensitivities in 2001 to pricing and foreign exchange are estimated as follows:
Cash Flow | Earnings | |||
Product prices change by: | ($000’s) | Per share | ($000’s) | Per share |
Oil - $1.00 U.S./bbl | $ 1,465 | $ 0.03 | $ 893 | $ 0.02 |
Gas - 10¢ Cdn./mcf | $ 233 | $ 0.00 | $ 142 | $ 0.00 |
$U.S./$Cdn. exchange rate changes by 1¢ | $ 430 | $ 0.01 | $ 264 | $ 0.01 |
Capital Expenditures
Capital expenditures totaled $56.0 million in 2001, up 65% from $30.7 million in 2000.
The Company’s drilling and equipping expenditures are comparable to the prior year as the Company drilled a similar number of wells. Land and seismic costs increased over the prior year due to the increased activity of the exploration team. An increase in facility and flowline costs of $5.1 million was due to the facility expansions at Chin Coulee and Carbon. In addition, the Company completed three major property acquisitions this year as compared to one corporate acquisition in the prior year.
The following table sets out the Company’s actual capital cash expenditures.
$000’s | 2001 | 2000 |
Land | $ | 5,019 | $ | 2,435 |
Seismic | 3,867 | 1,696 | ||
Drilling and equipping | 16,881 | 17,055 | ||
Facilities and flowlines | 10,213 | 5,157 | ||
Corporate | 64 | 108 |
36,044 | 26,451 | |||
Acquisitions | 19,980 | 4,274 |
$ | 56,024 | $ | 30,725 |
Liquidity and Capital Resources
KeyWest achieved higher year-end reserves and production levels with the $56 million capital program. The 2001 capital program was financed 44% from cash flow and 56% from the credit facility. The Company’s year end debt and working capital deficiency of $33.7 million is less than 1.4 times trailing annual cash flow.
During the fourth quarter, KeyWest issued 2.25 million common shares (100% Cdn. flow-through) for proceeds of $4.3 million net of issue expenses. Pursuant to the flow-through share agreements, KeyWest committed to spending $4.5 million on qualifying exploration drilling and seismic prior to December 31, 2002.
Pursuant to its normal course issuer bid, the Company repurchased and cancelled 1,579,900 (2000 - 1,347,500) common shares at a cost of $2.8 million (2000 - $1.6 million). The Company believes that when the underlying value of its common shares is not reflected in market price, the share purchase program provides value by reducing the number of common shares outstanding. The Company anticipates making share repurchases under its issuer bid during 2002 which will be funded from cash flow.
Capital expenditures of $36 million for 2002 will be funded by cash flow and credit facility borrowings. Forecasted 2002 year-end debt is $45.5 million which will be below the Company’s guidelines of limiting its debt to less than two times estimated cash flow. The Company’s current borrowing facility is $60 million.
Share Information
As at December 31, 2001 there were 49,364,381 shares issued and outstanding which represents a minor increase of 2% over the number of shares outstanding from the previous year. The weighted average number of shares outstanding for 2001 was 47,628,384. KeyWest’s shares trade on the Toronto Stock Exchange under the symbol KWE.
Business Risks
KeyWest operates in a business environment that is subject to numerous risks, some of which are within the Company’s ability to manage and some of which are beyond its control. By adhering to its effective business strategies, KeyWest can manage those risks within its control and partially mitigate the risks that are associated with the industry.
The prospect of finding oil and gas reserves in commercial quantities is inherently uncertain, and significant financial resources must be employed before production can be brought onstream. To minimize this risk, KeyWest has employed a team of highly qualified explorationists to generate low to medium risk prospects in areas commensurate with the financial resources of the Company. The Company focuses on exploring new areas to find oil and gas and to this end, extensive geological and geophysical analysis is performed prior to drilling. Once an area is targeted, the Company strives to build an extensive land base and maintain high working interests in its prospects.
KeyWest also mitigates its risk by employing a technically strong team of engineers to evaluate and acquire core properties which have exploitation potential. A significant amount of the Company’s drilling is to exploit acquisitions. The Company also strives to reduce outside risk by operating most of its production.
Where capital resources are concerned, the Company strives to maintain a balance between the use of cash flow, equity markets and debt. Since the equity markets are somewhat limited at this time, the 2002 capital program will be funded with cash flow and debt. While the Company has significant unused credit lines, it does not intend to allow its debt to exceed two times cash flow.
Once reserves are brought on stream, there are risks associated with transportation and markets for oil and gas, especially for a junior oil and gas company. To reduce these risks, KeyWest markets its oil and gas through several purchasers. In addition, KeyWest maintains a portfolio of both oil and gas assets to minimize the risks associated with changing market conditions.
Commodity price volatility is also a significant risk to oil and gas producers. Prices for oil and gas are related to conditions beyond the Company’s control such as worldwide supply and demand, competition, the U.S. dollar exchange rate and weather related seasonal changes in demand. KeyWest maximizes cash netbacks by working to reduce its operating costs and being as efficient as possible in terms of general and administrative expenses. From time to time the Company also uses fixed price contracts and financial products to mitigate the risk of price volatility.
The industry is subject to extensive regulations imposed by governments related to the protection of the environment. Environmental legislation in Western Canada has undergone major revisions resulting in more stringent environmental and compliance standards in recent years. The Company is committed to operating in a manner that meets or exceeds the required standards and compliance guidelines. In addition, the Company strives to minimize the impact of its activities on the environment by using the best available technologies.
Quarterly Review
($000’s except per share amounts)
2001 | Gross Production Revenue | Cash Flow From Operations | Cash Flow Per Share(1) (basic) | Earnings | Earnings Per Share(1) (basic) | Earnings Per Share(1) (diluted) | Total Assets | Long Term Financial Liabilities |
Q1 | 14,200 | 8,745 | $0.18 | 3,571 | $0.07 | $0.07 | 72,218 | 8,585 |
Q2 | 11,931 | 6,839 | $0.14 | 2,875 | $0.06 | $0.06 | 84,130 | 20,390 |
Q3 | 11,697 | 6,307 | $0.13 | 1,990 | $0.04 | $0.04 | 94,932 | 25,332 |
Q4 | 7,369 | 3,194 | $0.07 | 581 | $0.01 | $0.01 | 104,986 | 30,908 |
Total | 45,197 | 25,085 | $0.53 | 9,017 | $0.19 | $0.18 |
2000 |
Q1 | 4,880 | 2,707 | $0.06 | 848 | $0.02 | $0.02 | 39,961 | -- |
Q2 | 6,049 | 3,652 | $0.08 | 1,359 | $0.03 | $0.03 | 41,702 | -- |
Q3 | 7,909 | 5,024 | $0.11 | 2,031 | $0.04 | $0.04 | 50,549 | -- |
Q4 | 11,803 | 6,248 | $0.13 | 2,719 | $0.05 | $0.05 | 60,602 | -- |
Total | 30,641 | 17,631 | $0.37 | 6,957 | $0.15 | $0.14 |
(1)
The sum of the quarterly per share amounts may not necessarily equal the annual per share amounts due to the different weightings of shares issued during the year.
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SELECTED OPERATING AND FINANCIAL INFORMATION
Three Year Review
Years Ended December 31 | 2001 | 2000 | 1999 |
Operating | ||||||
Production | ||||||
Oil – bopd | 2,922 | 1,489 | 376 | |||
Gas – mcf/d | 8,206 | 6,893 | 2,763 |
Product Prices | ||||||
Oil - $/bbl | $ | 26.81 | $ | 31.52 | $ | 26.23 |
Gas - $/mcf | $ | 5.11 | $ | 5.37 | $ | 3.14 |
Reserves | ||||||
Oil – mbbls | 12,195 | 7,510 | 3,790 | |||
Gas – mmcf | 34,007 | 21,877 | 18,060 | |||
Drilling Activity | ||||||
Oil wells | 18 | 27 | 7 | |||
Gas wells | 14 | 4 | 5 | |||
Service wells | 2 | 4 | – | |||
Other | 11 | 10 | 3 | |||
Total wells | 45 | 45 | 15 | |||
Net wells | 38 | 42 | 13 | |||
Undeveloped Lands | ||||||
Net acres | 88,513 | 58,938 | 25,504 |
Financial($000’s except per share numbers) | ||||||
Gross production revenue | $ | 45,197 | $ | 30,641 | $ | 6,783 |
Cash flow from operations | $ | 25,085 | $ | 17,631 | $ | 3,692 |
per share (basic) | $ | 0.53 | $ | 0.37 | $ | 0.10 |
per share (diluted) | $ | 0.51 | $ | 0.36 | $ | 0.10 |
Earnings | $ | 9,017 | $ | 6,957 | $ | 1,898 |
per share (basic) | $ | 0.19 | $ | 0.15 | $ | 0.05 |
per share (diluted) | $ | 0.18 | $ | 0.14 | $ | 0.05 |
Average shares outstanding | 47,628 | 47,423 | 37,782 | |||
Capital expenditures | ||||||
Exploration & development | $ | 36,044 | $ | 26,451 | $ | 8,689 |
Acquisitions | $ | 19,980 | $ | 4,274 | $ | 20,560 |
Working capital (deficiency) | $ | (2,783 ) | $ | (4,751 ) | $ | 7,752 |
Total assets | $ | 104,986 | $ | 60,602 | $ | 40,987 |
Long-term debt | $ | 30,908 | – | $ | – | |
Shareholders’ equity | $ | 50,995 | $ | 41,632 | $ | 35,203 |
BUSINESS PROSPECTS
The prospects for the oil and gas industry generally, and for KeyWest in particular, remain very positive. The industry is once again experiencing a marketplace in which both crude oil and natural gas prices are relatively strong, albeit highly volatile.
Recent pricing volatility and record consolidations in the oil and gas sector over the past two years are expected to result in an abundance of new acquisition and merger opportunities which KeyWest, with its financial resources, is in a strong position to pursue. KeyWest will continue to pursue opportunities that fit the Company’s corporate strategy of adding reserves with significant upside potential, maintaining high working interests in new prospects, and developing opportunities that have “core asset” potential.
The Company will also continue to actively explore and develop its core areas in the coming months and, to that end, has budgeted for an aggressive 2002 drilling program.
Net Asset Value
The following table shows December 31st year-end and October 4, 2002 net asset values at varied discount rates:
October 4, | December 31, | |||
2002 | 2001 | 2000 | ||
Present Worth Discount | Present Worth Discount | Present Worth Discount | ||
Reserve Value ($000’s) | 10% | 15% | 10% | 15% | 10% | 15% |
Proven plus 50% of | ||||||
probable reserves | $ 257,121 | $ 219,958 | $ 150,504 | $ 128,046 | $ 102,750 | $ 89,150 |
Add: Land value | 7,709 | 7,709 | 6,934 | 6,934 | 4,480 | 4,480 |
Deduct: Total debt | (71,600)(1) | (71,600)(1) | (33,691) | (33,691) | (4,751) | (4,751) |
Net asset value | 193,230 | 156,067 | 123,747 | 101,288 | 102,479 | 88,879 |
Net asset value per share | $ 3.14 | $ 2.54 | $ 2.51 | $ 2.05 | $ 2.13 | $ 1.85 |
Notes:
(1)
Estimated debt as of October 4, 2002
(2)
NAV calculated on the assumption that the special warrants issued on October 4 are converted into Common Shares (outstanding Common Shares increased to 61.5 million from 55.03 million)
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DIRECTORS AND OFFICERS
The name, cities of residence, employment history and principal occupation of the directors and officers of the Company are set forth in the following table:
(1)
Member Audit & Reserves Committee
(2)
Compensation Committee
(3)
Corporate Governance Committee
Officers | |
Bruce M. Beynon | Vice-President, Exploration |
Carrie McLauchlin | Vice-President, Finance and Chief Financial Officer |
Steve Sugianto | Vice-President, Engineering and Corporate Development |
The above individuals have been engaged in the respective principal occupations indicated opposite their names for the past five years, except: Mr. Harold Pedersen was formerly President of Jordan Petroleum Ltd. until December, 1997; Ms. Mary Blue was Senior Vice-President, Land of Jordan Petroleum Ltd. until December, 1997; prior to becoming a KeyWest vice-president Mr. Steve Sugianto was Engineering Manager of KeyWest from March, 1999, Operations Manager with Remington Energy Ltd. from March, 1996 and Senior Exploitation Engineer with HCO Energy Ltd., before that; prior to becoming a KeyWest vice-president Ms. Carrie McLauchlin was Accounting Manager of KeyWest from June, 1999, CFO for Revolve Magnetic Bearings Inc. from December, 1997 and Senior Manager at KPMG (chartered accountants) before that; prior to becoming a KeyWest vice-president Mr. Bruce Beynon was Exploration Manager of KeyWest from April, 1999, Senior Explorationist with Remington Energy Ltd. from April, 1998 and prior thereto, Senior Geologist with Jordan Petroleum Ltd. until December, 1997; Mr. Alain Lambert was a principal and past President of Trilogy Investor Relations Inc. from July, 1998 and prior thereto President of Tokenhouse Capital & Research Inc. (investor relations firm) from November 1994; Mr. Ronald Woods was formerly Vice-President of Jascan Resources Inc. from 1996.
As of October 4, 2002, the directors and officers of the Corporation, as a group, own directly or indirectly, or exercise control over 6,178,037 Common Shares, or approximately 10.0% of the issued and outstanding Common Shares (after giving effect to the conversion of special warrants issued on October 4, 2002). The directors and officers also hold, in the aggregate, 2,455,000 options to purchase Common Shares, which if exercised, would increase the beneficial ownership of Common Shares for the directors and officers, as a group, to 14.0% of the Common Shares.
The term of office of each director expires at the next Annual and General Meeting of Shareholders to be held in 2003.
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SHARE INFORMATION
KeyWest's authorized share capital consists of an unlimited number of preferred shares issuable in series (none issued or outstanding) and an unlimited number of Common Shares. The Common Shares trade on The Toronto Stock Exchange under the symbol "KWE". At December 31, 2001 there were 49,364,381 Common Shares issued and outstanding. At October 4, 2002, there were 61,492,764 Common Shares outstanding (after giving effect to the exercise of 6,165,480 special warrants issued pursuant to the Company's $17 million financing).
Share Trading Data
The following table summarizes KeyWest’s trading statistics over two years ended December 31, 2001 and for the first nine months of 2002:
2002 | Volume | High | Low |
1st Quarter | 3,461,451 | $2.22 | $1.66 |
2nd Quarter | 6,396,333 | $2.63 | $2.03 |
3rd Quarter | 7,271,495 | $2.98 | $2.10 |
Total Volume | 17,129,279 | ||
September 30th Closing Price | $2.75 | ||
2001 | Volume | High | Low |
1st Quarter | 4,881,647 | $1.71 | $1.35 |
2nd Quarter | 8,712,960 | $2.45 | $1.65 |
3rd Quarter | 5,021,931 | $2.09 | $160 |
4th Quarter | 3,364,833 | $1.82 | $1.56 |
Total Volume | 21,981,371 | ||
December 31st Closing Price | $1.76 | ||
2000 | Volume | High | Low |
1st Quarter | 5,555,112 | $1.45 | $1.09 |
2nd Quarter | 4,229,170 | $1.25 | $0.90 |
3rd Quarter | 4,168,515 | $1.39 | $1.01 |
4th Quarter | 4,592,128 | $1.70 | $1.21 |
Total Volume | 18,544,925 | ||
December 31st Closing Price | $1.55 | ||
Dividend Policy
No dividends have been paid on any shares of the Company since its incorporation nor are they likely to be paid in the foreseeable future. Any decision to pay dividends in the future will be made by the Board of Directors and will be based on the Company’s earnings, financial requirements and other conditions at the time.
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ADDITIONAL INFORMATION
Additional information, including directors' and officers' remuneration, principal holders of KeyWest's securities and options to purchase securities is contained in the Company's Information Circular dated April 16, 2002 which relates to the Annual Meeting of Shareholders held on May 28, 2002. Other information is also provided in the Company's Annual Report which contains the audited consolidated financial statements for the year ended December 31, 2001. All the above information is incorporated herein by reference.
KeyWest will provide to any person or company, upon request to the Corporate Secretary of the Corporation:
(a)
when the securities of the Corporation are in the course of a distribution pursuant to a short form prospectus, or a preliminary short form prospectus has been filed in respect of a proposed distribution of its securities:
(i)
one copy of the Corporation's latest annual information form, together with one copy of any document, or the pertinent pages of any document, incorporated therein by reference;
(ii)
one copy of comparative financial statements of the Corporation for the Corporation's most recently completed financial year in respect of which such financial statements have been issued, together with the report of the auditor thereon, and one copy of any interim financial statements of the Corporation subsequent to the financial statements for its most recent financial year;
(iii)
one copy of the information circular of the Corporation in respect of the most recent annual meeting of shareholders of the Corporation which involved the election of directors; and
(iv)
one copy of any other documents which are incorporated by reference into the preliminary short form prospectus or the short form prospectus and are not required to be provided under i) to iii) above; or
(b)
at any other time, a copy of the documents referred to in clauses (a)(i), (ii) and (iii) above, provided that the Corporation may require a payment of a reasonable charge from such a person or company who is not a security holder of the Corporation where the documents are furnished under this clause b).
Copies of the Management Information Circular and Annual Report of the Corporation and the materials listed in the preceding paragraphs may be obtained upon request from Ms. Mary C. Blue, 1200, 520 - 5 Avenue S.W., Calgary, Alberta, T2P 3R7 or by telephone at (403) 261-2766.
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