Item 1. BUSINESS
CEC Resources Ltd. (the "Company" or "Resources") was incorporated on May 31, 1955 under the Business Corporations Act (Alberta) in Canada and was acquired by the former parent of Columbus Energy Corp. ("Columbus") in 1969 and by Columbus on July 31, 1984. Resources is an independent oil and gas company and considered a "junior oil" company in Canada. It remained a wholly-owned subsidiary of Columbus until spun-off from Columbus by a rights offering in February 1995. Resources engages in the production of crude oil and natural gas and acquires and develops leaseholds and other interests in oil and gas properties in the provinces of Alberta and Saskatchewan. Resources also has ownership interests in one liquids extraction plant and several gas gathering and compression systems in Alberta. Prior to year end substantially all of Resources' oil and gas properties were operated by other industry companies. With certain acquisitions completed in fiscal 1999, the Company has increased the percent of oil and gas properties which it operates.
Resources' principal office is located at Suite 1605, 700 6th Avenue S.W., Calgary, Alberta, Canada T2P 0T8. Resources also has a United States office located at 1700 Broadway, Suite 1150, Denver, Colorado 80290.
The Company's business strategy is to develop its existing proved oil and natural gas reserves and to acquire additional oil and gas properties. The Company employs a staff of oil and gas industry professionals to direct in this effort.
The Company's business is comprised of two segments which are the direct ownership of oil and natural gas properties and the ownership of natural gas processing, compression and gathering facilities.
The Company owns working interests in 16 oil wells located in Saskatchewan, Canada and 47 natural gas wells located in Alberta, Canada.
The Company also owns an interest in a natural gas liquids processing facility located in Alberta, Canada.
Item 2.
Item 2. PROPERTIES
The following disclosures set forth the Company's oil and gas producing activities. Currency amounts are in Canadian dollars, unless otherwise stated.
Estimated Oil and Gas Reserve Quantities and Revenues
The estimated reserve amounts and future net revenues were determined by Sproule
Associates Limited, independent geological and petroleum engineering consultants for fiscal year 1998, and by Reed Ferrill & Associates, an independent consulting petroleum engineering firm for fiscal years 1997 and 1996. The Company owned only Canadian reserves during this period.
Proved Developed Producing Reserves
As of November 30, 1998, Resources has approximately 3.9 billion cubic feet of proved developed producing gas reserves which represents 65% of the Company's total
proved gas reserves. Resources also has approximately 144,000 barrels ("Bbl") of oil and 81,000 barrels of natural gas liquids ("Ngl" or "liquids") of proved developed producing reserves which together represent 70% of the Company's total proved oil reserves.
The reserves in this category can be materially affected positively or negatively by either currently prevailing or future prices because they determine the economic lives of the producing wells.
Proved Developed Non-Producing Reserves
As of November 30, 1998, Resources has approximately 500 million cubic feet of proved developed non-producing reserves representing 9% of the Company's total proved gas reserves. Resources' oil and liquids reserves in this category are approximately 60,000 barrels or 19% of its total proved oil reserves.
The reserves in this category are primarily reserves behind the casing in existing wells and recompletion of those zones will be required to place them on production. Also included are any wells which have been completed and were awaiting connection to a gas pipeline as of each year end, provided such pipeline connection does not require significant investment.
Proved Undeveloped Reserves
As of November 30, 1998, Resources' proved undeveloped reserves total approximately 1.6 billion cubic feet of gas, or 26% of the Company's total proved natural gas reserves, and approximately 38,000 barrels of oil and liquids, or 11% of the Company's total proved oil reserves.
These reserves are attributable to wells which have been completed and were awaiting pipeline connection as of the end of the year where such pipeline connection would require significant investment and also undrilled locations offsetting production in the Carbon, East Carbon, Harmon and Rowley areas of Alberta.
Probable Reserves
As of November 30, 1998, Resources' probable natural gas reserves are approximately 600 million cubic feet. Resources' oil and gas liquids reserves in this category are approximately 6,000 barrels.
The reserves in this category are primarily reserves which may reasonably be assumed to exist because of geophysical or geological indications and drilling done in the
regions which contain proven reserves. The reserves in this category are not included in the schedule of Standardized Measure of Discounted Future Net Cash Flow (the "Standardized Measure").
The following table compares the Company's estimated proved reserves as of November 30, 1997 and 1998.
The decrease in proved developed producing reserves from 1997 to 1998 is primarily attributable to fiscal 1998 production. The majority of the decrease in proved developed non-producing and proved undeveloped reserves is attributable to the following factors:
The unsuccessful completion of a well in the East Carbon area resulted in more stringent reservoir engineering interpretations of log characteristics and analogous production in two natural gas zones. The unsuccessful completion also disproved a geological hypothesis that was formally presumed in the determination of proved undeveloped reserves in these two natural gas zones.
In 1998, a zone in the East Carbon area was remapped due to new offset well information, resulting in geologic interpretations that did not support the assignment of proved reserves for a location.
Standardized Measure
The Standardized Measure schedule is presented below pursuant to the disclosure requirements of the United States Securities and Exchange Commission ("SEC") and Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (SFAS 69). Future cash flows are calculated using year-end oil and gas prices and operating expenses, and are discounted using a 10% discount factor.
Under SEC guidelines, Future Net Revenues ("FNR") shown below must be calculated using prices that were in effect on November 30 of each year and are projected forward based on existing contracts or the spot market price on that date. Accordingly, the FNR has been calculated using the spot market sales price in effect on November 30, 1998 and the sales price of long-term contracts in effect prior to the end of the 1998 fiscal year.
The prices utilized in this calculation are summarized as follows:
The standardized measure is intended to provide a standard of comparable measurement of the Company's estimated proved oil and gas reserves based on economic and operating conditions existing as of November 30, 1998, 1997 and 1996. Pursuant to SFAS 69, the future oil and gas revenues are calculated by applying to the proved oil and gas reserves the oil and gas prices at November 30 of each year relating to such reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year end. Production and development costs are based upon costs at each year end. Future income taxes are computed by applying statutory tax rates as of the year end with recognition of tax basis, resource allowance, tax pool carryforwards and earned depletion carryforwards as of that date and relating to the proved properties. Discounted amounts are based on a 10% annual discount rate. Changes in the demand for oil and gas, price changes and other factors make such estimates inherently imprecise and subject to revision.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO ESTIMATED PROVED OIL AND GAS RESERVES (thousands of dollars)
As required by SFAS 69, the tax computation does not consider the Company's annual interest expense and general and administrative expenses or future drilling and equipment costs. Because of these factors, the tax provisions shown do not represent the much lower future tax expense expected as long as Resources remains an active operating company.
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES FOR THE THREE YEARS ENDED NOVEMBER 30, 1998 (thousands of dollars)
Production
Resources' net oil and gas production for each of the past three fiscal years is shown on the following table:
Average price and cost per unit of production for the past three fiscal years are as follows:
Natural gas is converted to oil at the ratio of six Mcf of natural gas to one Bbl of oil. Production costs include only lease operating expenses.
Developed Properties
A summary of the gross and net interest in producing wells and gross and net interest in producing acres as of November 30, 1998 is shown in the following table:
Undeveloped Properties
The following table sets forth the Company's ownership in undeveloped properties as of November 30, 1998:
Drilling Activities
The Company engages in exploratory and development drilling in association with other oil and gas companies. In most cases, the Company participates in wells operated by other industry partners but acts as the operator of some of the wells in which it owns an interest. The table below sets forth information regarding the Company's drilling activity for the last three fiscal years. The net interest shown is the Company's working interest ("WI").
Current Operations Activity
The Company is engaged in the production of oil and the production, gathering, compression and processing of natural gas liquids and natural gas. The Company owns working interests in 47 natural gas wells located in Alberta, Canada and working interests in 16 oil wells located in Saskatchewan, Canada. The Company also owns an interest in the Carbon Plant (a natural gas liquids processing facility) and associated natural gas gathering and compression facilities located in Alberta, Canada.
The Company's primary focus is the operation and development of its natural gas properties in the Carbon Field area of Central Alberta.
The Company intends to develop additional proved reserves at its existing
properties and to seek to acquire additional natural gas properties in the Carbon Field area and other areas.
Neutrino Acquisition - --------------------
In December 1998, the Company acquired working interests in 16 producing natural gas wells and associated leaseholds in the Wayne-Rosedale Field, located in Alberta, Canada from Neutrino Resources Ltd. for approximately $2.3 million. The acquisition was funded with cash and bank financing. The acquisition increased Resources' working interest ownership in the Wayne-Rosedale Field from approximately 33.3% to 66.3% Through this transaction Resources became operator of the East Carbon Field wells and gas gathering system, thereby creating opportunities for increased efficiencies and profitability due to greater control of field operations. Oil and gas reserves related to the acquisition are not included in the reserve tables listed previously as of November 30, 1998 since closing did not take place until December 1998. The following increase to proved reserves and values would have been added had the closing taken place by November 30, 1998 using year end prices of $16.94 per barrel of oil, $12.67 per barrel of natural gas liquids and $2.61 per Mcf of natural gas.
Title to Properties
The Company holds title to its properties pursuant to leases from third parties or the Crown. Management of the Company believes the Company has satisfactory title to its properties. Oil and gas interests are subject to customary interests and burdens, including overriding royalties and operating agreements. The Company's properties may also be subject to liens incident to operating agreements, as well as minor encumbrances, easements and restrictions.
As is customary in the oil and gas industry, the Company does not regularly investigate title to oil and gas leases when it acquires undeveloped acreage. Title is typically examined before any drilling or development is undertaken. The methods of title examination adopted by the Company are reasonably calculated, in the opinion of
management of the Company, to insure that production from its properties, if obtained, will be readily salable for the account of the Company. Management of the Company is not aware of any material pending or threatened claims affecting title to the Company's proved acreage.
The Company's producing and non-producing properties are subject to customary royalty interests liens for current taxes, and other burdens, none of which, in the opinion of management of the Company, materially interferes with the use of or adversely affects the value of such properties.
Competition, Markets for Oil and Gas & Customers
The oil and gas industry is highly competitive. Major oil and gas companies and independent producers are active bidders for undeveloped acreage and desirable oil and gas properties, as well as for the equipment and labor required to operate such properties. With the Company's solid financial position and its growth strategy, Resources is in position to take advantage of opportunities in the currently depressed oil and gas industry.
With the completion of two significant pipeline expansion projects which have added 1.1 BCF/d of export capacity from Alberta, the natural gas pricing scenario for producers with Alberta reserves has improved. The Company is in position to take advantage of any favorable price changes due to its high percentage of natural gas production.
Resources sells its natural gas production to natural gas marketing companies. The operator of the Carbon gas plant pays Resources for liquids sold from the plant. The amount paid by the plant operator for liquids exceeds 10% of the Company's revenues.
The marketability of oil and natural gas is affected by numerous industry factors. The Company has utilized forward pricing contracts to fix the sales price on a percentage of its natural gas sales. In the Company's judgment, termination by any purchaser under which its present sales are made would not have a material impact upon its ability to sell its production to another purchaser at similar prices.
Government Regulation
The petroleum and natural gas industry operates in Canada under federal and provincial legislation and regulations which govern land tenure, royalties, production rates, environmental protection, exports and other matters. Federal authorities do not regulate the price of oil and gas in export trade, but instead rely on market forces to establish these prices. Legislation exists that regulates the quantities of oil and gas which may be removed from the provinces or exported from Canada.
Producers pay provincial royalties for production from Crown leases and freehold royalties on freehold leases. Provincial royalties are subject to a sliding scale which fluctuates with changes in productivity and prices. The sliding scale formula is designed to retain funds in the oil and gas industry when commodity prices are low, with increases in the royalty rates in times of high commodity prices when the industry's need for royalty rate relief is not as great.
The Alberta government requires that gas royalties be paid on the basis of the Gas Reference Price (determined monthly on the basis of a weighted average field price) or on the basis of the producer's Corporate Average Price. This requirement discourages natural gas price discounting. Resources has elected to use the Gas Reference Price. The Alberta government permits gas gathering and processing costs (based on corporate average capital costs and deemed operating costs) to be deducted in computing the Crown royalty. Effective January 1, 1990, the Alberta government revised the Alberta Royalty Tax Credit ("ARTC") formula to a sliding scale, based on oil and gas prices. From January 1995 to the present, ARTC entitlements are equal to the lessor of Alberta Crown Royalties paid and $2,000,000, multiplied by the weighted average royalty tax credit rate which ranges from 75% to 25%.
Environmental Regulations
The industry is also subject to environmental regulation pursuant to legislation of the Canadian Federal and provincial governments. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facility sites and access be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such regulations may result in the imposition of fines and penalties, the suspension of operations and potential civil liability. The Environmental Protection and Enhancement Act imposes environmental standards and requires compliance with various legislative criteria (including reporting and monitoring) in Alberta. The Alberta Energy and Utilities Board, pursuant to its governing legislation, also plays a role with respect to the regulation of environmental impacts of oil and gas activities.
Resources believes that it is in compliance with applicable environmental laws and regulations, and that the environmental regulations as presently in effect, will not have a material effect upon its capital expenditures, or competitive position in the industry. Consequently, Resources does not anticipate the need for any material capital expenditures for environmental control facilities for the current year. Resources believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. No assurance can be given as to the future capital expenditures which may be required for compliance with environmental regulations which come into force in the future.
Operating Hazards
The oil and gas business involves a variety of operating risks including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, gas leaks, ruptures and discharge of toxic substances. The occurrence of any of these events might result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that any such insurance that is obtained will be adequate to cover all losses or exposure for liability. Furthermore, the Company cannot predict whether such insurance will continue to be available at premium levels that justify its purchase. Generally, the Company has elected not to obtain blow-out insurance when drilling a well since it has not operated in areas with abnormally high pressures or with known severe lost circulation problems.
Item 3.
Item 3. LEGAL PROCEEDINGS
Resources is not a party to any legal proceedings.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1998, no matters were submitted to a vote of security holders.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of Resources has traded on the American Stock Exchange regular list since July 6, 1995. The common stock initially began trading on the American Stock Exchange Emerging Companies Marketplace on March 24, 1995 about one month after it was divested by Columbus to its shareholders by a rights offering. The reported high and low sales prices in U.S. dollars for the periods listed below were as follows:
As of January 31, 1999 the most recently reported closing sales price of Resources common stock was $4.375 per share.
As of November 30, 1998, there were approximately 60 holders of record of Resources' common stock and an estimated 430 or more beneficial owners who hold their shares in brokerage accounts.
The Company has never paid any cash dividends on its common stock and does not contemplate the payment of cash dividends since it plans to use available earnings for its drilling, development and acquisition programs. Payment of future cash dividends would
also be dependent on earnings, financial requirements and other factors.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The table below sets forth selected historical financial and operating data for the Company as of the dates and for the periods indicated. The historical financial data for each of the years in the five-year period ended November 30, 1998, were derived from the financial statements of the Company which have been audited by PricewaterhouseCoopers LLP, Chartered Accountants. This information is not necessarily indicative of the Company's future performance. The information set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," and the Company's Financial Statements and notes thereto, included elsewhere herein.
(1) See discussion of cash flows in "Management's Discussion and Analysis of Financial Condition and Results of Operations". (2) Certain of the amounts above have been restated because the Company elected to adopt for fiscal 1998 Canadian Institute of Chartered Accountants ("CICA") 1540, Cash Flow Statements. Cash flow data for fiscal years ending November 30, 1998, 1997 and 1996 are presented in conformance with CICA 1540. (3) Restated for a five-to-one stock split on October 27, 1994.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion below summarizes the Company's financial condition and results of operations and should be read in conjunction with the financial statements and related notes. The financial statements contained in this report have been prepared in accordance with generally accepted accounting principles ("GAAP") in Canada. Certain disclosures required by U.S. GAAP differ from Canadian GAAP and are detailed in the notes to the financial statements.
The information below contains several forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995. These statements involve inherent uncertainties, including price volatility, development, operational and implementation risks, as well as other factors that may cause the actual financial performance of Resources to be materially different from predicted financial performance.
Liquidity and Capital Resources
Management considers Resources' liquidity to be substantially better than most other small Canadian oil and gas companies based on the fact that it has positive working capital, a history of excellent cash flow relative to its modest market capitalization, and has established a $2.5 million credit facility agreement with Canadian Imperial Bank of Canada ("CIBC").
Fiscal net earnings were $240,000 or $.16 per share in 1998, $605,000 or $.38 per share in 1997, and $526,000 or $.35 per share in 1996. At November 30, 1998, Resources' stockholders' equity had increased by $31,000 since November 30, 1997 to $8,722,000 and it had positive working capital of $2,120,000.
For 1998 cash provided by operating activities was $1,366,000 while the amount in 1997 was $1,724,000. The decrease from 1997 to 1998 is primarily attributable to increased lease operations and general and administrative expenses ("G&A"). Cash used in investing activities was higher in 1996 and 1997 primarily due to reduced drilling activity in 1998. Cash used in financing activities increased as the result of the Company's purchase of 99,600 shares of its own stock partially offset by the proceeds from the issuance of 70,000 shares of common stock.
CIBC Relationship - -----------------
In December, 1998, Resources secured a financing commitment with CIBC. The primary purpose of the loan is to assist the Company in the acquisition of oil and gas reserves. The initial commitment is a $2.5 million revolving production loan. The revolving phase of the loan will expire on April 30, 1999 and may be renewed by CIBC. The interest
rate on outstanding borrowings is the CIBC Prime Rate plus 3/4 of 1%. The Company has a long standing relationship with CIBC and believes the opportunity exists to increase the commitment to assist the Company in future acquisitions.
Results of Operations
The Company's total revenues decreased by $56,000 in 1998 compared to 1997 primarily due to price decreases in oil and Ngls which were partially offset by a price increase in gas. Lease operating expenses increased by $128,000 in 1998 compared to 1997 primarily due to well workovers and additional compression charges. G & A costs increased $233,000 in 1998 compared to 1997 primarily due to hiring full time employees. Depreciation, depletion, and amortization ("DD&A") increased by $205,000 in 1998 compared to 1997 primarily due to the Company's proved developed non-producing and proved undeveloped natural gas reserves. The above factors contributed to income tax expenses that were lower by $223,000 in 1998 compared to 1997 and net earnings which were $365,000 lower in 1998 compared to 1997.
Oil and Gas Operations Comparisons for 1998, 1997 and 1996
The increases (decreases) in the components of oil and gas revenues during the periods presented are summarized as follows:
Natural gas revenues in fiscal 1998 were 4% higher than in 1997 because 13% higher average prices received more than offset 8% lower sales volumes due to plant and compressor down time and normal well productivity decline. Revenues from oil were 17% lower in 1998 compared to last year because of a 29% decrease in oil prices, which overshadowed a 14% increase in volume. Plant liquids sales volumes were flat from 1997 to 1998 and revenues as well as prices were similarly affected by the global oil price decrease as product prices and revenues decreased by 35% from 1997 to 1998.
Natural gas revenues for fiscal 1997 were 5% higher than in 1996 because 27% higher average prices received more than offset 17% lower sales volumes due to plant and compressor down time and normal well productivity decline. Revenues from oil were 55% higher in 1997 compared to 1996 because of a 47% volume increase primarily from a new well which overcame the 1% price decrease. Plant liquids sales volumes decreased 4% and prices increased 14% in 1997 compared to 1996.
Royalty expense consists primarily of Crown royalties in addition to freehold and gross overriding royalties. The Company is eligible for the Alberta Royalty Tax Credit ("ARTC") that varies inversely with prevailing prices for oil and gas sales in Alberta. For 1998 the net Crown royalty rate was 6% of oil and gas sales compared to 8% in 1997. This decrease was attributed to a 13% increase from 1997 to 1998 in the gas sales price received by the Company coupled with a 4% decrease from 1997 to 1998 in the reference price used to calculate Crown royalty expense.
Lease operating expenses for fiscal 1998 were 22% as a percentage of oil and gas sales compared to 17% for 1997 and 20% for 1996. The increase in 1998 compared to 1997 is attributed to well workovers and a full year of production of oil wells in the Company's Hoffer area and additional compression in the East Carbon area. This increase was partially offset by variable expense decreases related to production declines. Lease operating expenses per BOE sold were $2.92, $2.27 and $2.12 for 1998, 1997 and 1996, respectively. This trend is attributed to increased well workovers and fixed cost absorption on a declining production base. Resources has always followed the U.S. practice of converting its natural gas to BOE based on the heating value ratio of six Mcf of natural gas to one barrel of oil rather than a ratio of 10 to 1 which historically has approximated price ratios. The latter ratio is used almost exclusively by Canadian public companies. Resources' share of processing fees charged to its wells have been deducted from its field services revenues where Resources' one- third Carbon plant ownership is involved. It is anticipated that the Company will be able to exert greater control over its East Carbon lease operating expenses in fiscal 1999, as Resources is now the operator as a result of the Neutrino acquisition discussed in "Current Operations Activity".
Field netbacks which are commonly reported by Canadian energy companies equate to oil and gas sales less royalties and lease operating expenses. Resources' average field netback was $9.23/BOE in 1998, $9.69/BOE in 1997 and $7.68/BOE in 1996. If natural gas had been converted to oil using the Canadian practice of a 10:1 ratio, then reported field netbacks would have been $13.45/BOE in 1998, $14.32/BOE in 1997 and $11.67/BOE in 1996.
Field Services Business Segment
The Company receives operating service revenue generated by its share of processing fees at the Carbon area liquid extraction plant. The Company also processes Resources' own
gas, and that portion of the processing fee revenue attributable thereto is not reported in this segment and offsets an identical amount of process expense otherwise chargeable to lease operations. The Carbon plant also processes gas of unrelated third parties which in fiscal 1998 amounted to approximately 37% of the plant's volumes and represents the majority of field services profit.
Resources also derives revenues and net cash flow from separate gathering and compression facilities in which it has ownership. Amounts applicable to Resources' own production have likewise been eliminated from both revenue and expense of these operations.
General and Administrative Expenses
G&A expenses relate to the direct costs of Resources which do not originate from either its limited operation of properties or the providing of services. As explained in Note 7 to the financial statements, each month Resources incurs certain direct and indirect G&A costs for management services provided by Columbus. These costs are primarily for labor, related benefits and other overhead costs billed by Columbus as allocated by its employees. G&A costs increased in 1998 by $233,000 compared to 1997 primarily due to hiring full time employees, which was partially offset by a reduction in Columbus expenses as additional full time employees were hired. Effective March 31, 1999, the Company will no longer incur management fees from Columbus.
Depreciation, Depletion and Amortization
DD&A of oil and gas assets are determined based upon the unit of production method. This expense is not only related to the current level of production, but also is dependent upon past costs to find, develop and recover those reserves. The liquid extraction plant, other gathering and compression facilities and office equipment are depreciated on a straight line method.
For 1998, the depletion rate of oil and gas properties was $4.02/BOE (6:1) for the Company, compared to $3.01/BOE for fiscal 1997, and $2.15/BOE for fiscal 1996. The 1998 increase was primarily due to a downward adjustment to the Company's year end proved reserves. The above calculated amounts for 1998, 1997 and 1996 include $62,000, $33,000 and $30,000 respectively, for estimated future site restoration costs.
Exploration Activity
Under the full cost method of accounting, all exploration costs associated with continuing efforts to acquire or review prospects and outside geological and seismic
consulting work are capitalized. A total of $54,000 of exploration costs were capitalized during 1998. These charges include seismic and consulting costs in the Carbon, East Carbon and Harmon areas of Alberta. A total of $230,000 of exploration costs were capitalized during 1997. These charges included seismic costs in the Maxim area of Saskatchewan and in the East Carbon area of Alberta which totaled $67,000 and compared with 1996's $181,000 primarily in the Hoffer area of Saskatchewan and 3-D seismic coverage for the Nisku reef oil project in the Carbon field. Also included was $108,000 of seismic cost which was capitalized during first quarter 1997 and had been added to leasehold costs related to undeveloped reserves in the Carbon field.
Income Taxes
In 1997, the Company adopted CICA 3465, Income Taxes. Since 1993, Resources has paid current taxes to Revenue Canada based on its taxable income after utilization, to the extent allowed, of its tax pool carryforwards. Currently payable taxable income for future periods is dependent upon the level and type of capital expenditures that are incurred in these periods as well as percentage limitations for utilization of existing tax pools. For fiscal 1998, current income taxes are estimated to be $19,000. For the 1997 and 1996 fiscal years Resources paid no current federal tax because additions to deductible property tax pools coupled with carryover balances were sufficient to result in no taxable income.
Effects of Changing Prices
The Canadian economy experienced considerable inflation during the late 1970's and early 1980's but in recent years has been fairly stable at relatively low levels. The Company, along with most other business enterprises, was then and will be affected in the future by any recurrence of such inflation. Changing prices, or a change in the dollar's purchasing power, distorts the traditional measures of financial performance which are generally expressed in terms of the actual number of dollars exchanged and do not take into account changes in the purchasing power of the monetary unit. This results in the reporting of many transactions over an extended period as though the dollars received or expended were of common value, which does not accurately portray financial performance.
Oil and gas prices fluctuate over time as a function of market economics. Refer to the price change table in the discussion "Oil and Gas Operations Comparisons for 1998, 1997 and 1996" for information on product price fluctuation over the past three years. This table clearly depicts the effect of changing prices on the Company's revenue stream.
Operating expenses have been relatively stable but also can become distorted since they represent a larger percentage of revenues when lower product prices prevail. Competition in the industry can significantly affect the cost of acquiring leases, although in recent years this factor has been less important as more operators have withdrawn from
active exploration programs. Inflation, as well as a recessionary period, can cause significant swings in the interest rates that companies pay on bank borrowings. These factors are anticipated to continue to affect the Company's operations both positively and negatively for the foreseeable future.
EXCHANGE RATE OF THE CANADIAN DOLLAR
All dollar amounts set forth in this report are in Canadian dollars except where otherwise indicated. The following table sets forth the rates of exchange for the Canadian dollar, expressed in United States dollars:
On January 29, 1999, the noon buying rate in Canadian dollars was $0.6634 U.S. = $1.00 Canadian.
Year 2000 Compliance
The Year 2000 issue is the result of computer programs being written using two digits rather than four, or other methods, to define the applicable year. Computer programs that have date sensitive software may recognize a date using "00" as the year 1900, rather than the year 2000. This could result in a system failure or miscalculations causing disruptions of operations, including among other things, a temporary inability to price transactions, send invoices or engage in similar normal business activities. In addition to affecting mainframe and mid-range computer systems, this problem potentially impacts computer chips integrated in security, plant automation, and pipeline control and metering systems.
Resources is currently completing an external review of all Year 2000 issues by contacting and/or sending out questionnaires to all of its natural gas purchasers, gathering system and plant operators, downstream pipeline operators, equipment and service providers, operators of its oil and gas properties, financial institutions and vendors providing payroll and medical benefits and services. Management has set a deadline of April 1999 for this external review process to be completed. Once this review has been completed, a schedule of necessary revisions to existing systems as well as requisite contingency plans will be designed and implemented.
The Company utilizes a service bureau for its accounting processing. The service bureau is working on a new software release that would bring its system into compliance at no cost to the Company. The Company is also evaluating accounting systems and making a determination whether to bring all accounting services and processing in-house. Only software that is certified Year 2000 compliant will be considered. If the Company brings these services and processing in-house, a July 1999, deadline will be established for completion of system evaluation and implementation. The Company is also dependent upon personal computer based software programs and files that may not be Year 2000 compliant. The Company has set a deadline of April 1999, to be internally compliant with Year 2000 specifications.
Management expects costs for the Company to become Year 2000 compliant will not be significant. The Company does not believe that any loss of revenue will occur as a result of the Year 2000 problem. However, despite the Company's efforts to identify and remedy Year 2000 problems, there may be related failures that disrupt Resources' business temporarily. In addition, the timetable for the Company's planned completion of its own Year 2000 modifications and the estimated costs to accomplish this are management's best estimates. These assessments involve many assumptions concerning future events, including the continued availability of certain resources, particularly personnel able to locate, reprogram or replace, and test the Company's hardware and software in accordance with the Company's established schedule. There can be no guarantee that the Company's estimates will prove accurate, and actual results could differ significantly because of the non-compliance of third parties of business importance to the Company.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of loss that may impact the financial position, results of operation or cashflow of the Company due to adverse changes in financial and commodity market prices and rates. In regard to interest rate risk, the Company in fiscal 1999 established a $2.5 million credit facility with a Canadian bank as described in "Liquidity and Capital Resources" under Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 14 to the Financial Statements of the Company. The interest rate for borrowings under this facility are variable. In regard to foreign currency risk, the Company's operations except for certain administration functions performed in the Company's Denver, Colorado office, are conducted in Canada. The Company does not use financial instruments relating to currency and exchange rates. For information on the exchange rate of the Canadian dollar, refer to "Exchange Rate of the Canadian Dollar" under Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations." In regard to commodity price risk, the Company does use certain financial instruments in an attempt to manage this risk as described in Note 9 to the Financial Statements of the Company.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The report of independent accountants and financial statements listed in the accompanying index are filed as part of this report. See Index to Financial Statements on page 35.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None. PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The directors and executive officers of CEC Resources Ltd. are listed with brief statements setting forth the present principal occupations and other five year biographical information concerning each. Each director listed has served continuously since his/her election.
* Member of the Audit Committee.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The Company entered into a written agreement in 1995 with Columbus to provide management services until new management was retained, either by merger, acquisition or direct employment. On June 30, 1998, the Company entered into a Stock Purchase Agreement ("Agreement") with McDonald Energy, LLC. ("McDonald"), a Colorado limited liability company solely owned by Patrick R. McDonald. The Agreement provided that Patrick R. McDonald become a director, president and chief executive officer of Resources as of July 1, 1998 at an annual salary of U.S. $120,000 pursuant to a three year employment agreement, and was granted a five year employee stock option for 78,000 shares exercisable at U.S. $5.50 per share. Mr. McDonald's salary for 1998 was U.S. $50,000. The Company has paid no direct cash compensation to the officers of Columbus for the period that they served as officers of Resources. The Company continues to be charged by Columbus for the specific time each Columbus officer or employee devotes to the Company on a monthly basis. See "Certain Relationships and Related Transactions". The management agreement with Columbus will expire in March 1999.
The following table sets forth certain information regarding compensation paid during each of the last three years to the Company's Chief Executive Officer and the other executive officers who earned over U.S. $100,000 in salary and bonus in fiscal 1998 (referred to subsequently as the "named executive officers").
SUMMARY COMPENSATION TABLE
OPTIONS GRANTS IN LAST FISCAL YEAR
The following table sets forth information concerning individual grants of stock options made during fiscal 1998 to the Company's named executive officers.
(1) Options granted at the closing price of the Company's common stock on that date.
(2) These columns present hypothetical future realizable values of the options, obtainable upon exercise of the options net of the option's exercise price, assuming that the market price of the Company's common stock appreciates at a 5% and 10% compound annual rate over the term of the options. The 5% and 10% rates of market price appreciation are presented as examples pursuant to rules of the SEC and do not reflect management's prediction of the future market price of the Company's common stock. No gain to the optionees is possible without an increase in the market price of the common stock above the option price. There can be no assurance that the potential realizable values shown in this table will be achieved. The potential realizable values presented are NOT intended to indicate the value of the options. ---
Compensation of Directors
The directors of Resources who are neither officers nor employees are currently paid an annual directors' fee of CDN $400 per quarter, plus CDN $700 per meeting for attendance at all regular and special meetings of the Board of Directors. In 1998, each outside director was granted a 6,000-share, three-year stock option except for Mr. Loyola Keough who was granted a 10,000 share, five year option. The exercise prices of each of the options are equal to at the closing price of the American Stock Exchange on the date of grant which was U.S. $5.375.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information concerning persons known by the Company to be beneficial owners of more than five percent of the Company's voting securities as of January 31, 1999. All information is taken from or based on filings made by such beneficial owners with the Securities and Exchange Commission ("SEC") or information provided by such owners to the Company. Except as indicated in the footnotes, each person identified in the table holds sole voting and investment power with respect to the shares shown opposite such person's name.
(1) Patrick R. McDonald is the sole member of McDonald Energy, LLC, includes 250,000 shares underlying a one year option which expires June 30, 1999. Also includes 78,000 employee stock options exercisable after July 1, 1999 and 73,800 shares owned by CEC Resources Holdings, LLC of which McDonald Energy, LLC has 58.3% interest. (2) Includes 6,000 shares underlying exercisable stock options. Does not include 28,911 shares which are owned by Lucile B. Trueblood, Mr. Trueblood's wife, which she acquired as her separate property and as to which Mr. Trueblood disclaims any beneficial ownership. Includes 207,000 shares owned by the Harry A. Trueblood Charitable Remainder Unitrust dated June 1, 1998 to which shares Mr. Trueblood disclaims ownership; but as the only trustee, does hold sole voting rights to such shares. (3) Includes 79,957 shares owned by Carl and Associates, a partnership in which Mr. Seaman owns an 80% partnership interest and as to which Mr. Seaman shares voting and investment power. Does not include 2,032 shares which are owned by Linda Seaman, Mr. Seaman's wife, which she acquired as her separate property and as to which Mr. Seaman disclaims any beneficial ownership. (4) Includes 26,000 shares underlying exercisable stock options.
Security Ownership of Management
The table below provides information as to each class of Resources' equity securities beneficially owned as of January 31, 1999 by (i) each director, (ii) each "named executive officer" (as defined in SEC rules), and (iii) all directors and officers as a group. All information is taken from or based on filings made by such persons with the SEC or provided by such persons to the Company. Except as indicated in the footnotes, each person identified in the table holds sole voting and investment power with respect to the shares shown opposite such person's name.
(1) See Footnote 1 under "Security Ownership of Certain Beneficial Owners".
(2) See Footnote 2 under "Security Ownership of Certain Beneficial Owners".
(3) Includes 26,000 shares underlying exercisable stock options.
(4) Represents 10,000 shares underlying exercisable stock options.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company has never entered into any transactions with officers or directors of the Company with respect to participation in oil and gas operations, and the present management of the Company has no intention of doing so in the future. However, if any transaction with an officer or director of the Company does occur, it is the Company's intention to cause any such transaction to be on terms that are no less favorable to the Company than the terms that could be obtained from an unrelated third party in an arms-length transaction.
During fiscal 1998, Columbus Energy Corp. received U.S. $218,000 from the Company for providing certain management services pursuant to the management agreement described "Executive Compensation".
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS FORM 8-K
(a) Financial statements and schedules included in this report:
See "Index to Financial Statements" Page 35
All schedules are omitted since either the required information is set forth in the financial statements or in the notes thereto or the information called for is not present in the accounts or is not required under the exception stated in Rule 5.04.
(b) Reports on Form 8-K:
The following reports on Form 8-K were filed on behalf of the Registrant during the fourth quarter of fiscal 1998:
NONE
(c) Exhibits:
Exhibit No. - -----------
* 2(a) Agreement of Purchase and Sale between Neutrino Resources Inc. and CEC Resources Ltd. (Exhibit 2(a) to Form 8-K dated December 31, 1998).
* 3 Articles of Association (Exhibit 3 to Registration Statement No. 33- 86996).
* 3(a) Articles of Continuance and Amendments thereto (Exhibit 3(a) to Registration Statement 33-86996).
* 3(b) By-Laws (Exhibit 3(b) to Registration Statement No. 33-86996).
*10(a) Employee Incentive Share Option Plan (Exhibit 10(a) to Registration Statement No. 33-86996).
*10(b) Firm Service Gas Sale Agreement (Exhibit 10(b) to Registration Statement No. 33-86996).
*10(c) Administrative Services Agreement (Exhibit 10(c) to Registration Statement No. 33-86996).
*10(d) Indemnity Agreement Between CEC Resources Ltd. and Harry A. Trueblood, Jr. (Exhibit 10(d) to Registration Statement No. 33-86996).
*10(e) Indemnity Agreement Between CEC Resources Ltd. and Margaret Cartwright (Exhibit 10(e) to Registration Statement No. 33-86996).
*10(f) Separation pay policy adopted effective February 24, 1995 for officers and employees (Exhibit 10(a) to Form 10-Q dated October 11, 1995).
*10(g) Employment agreement by and between CEC Resources Ltd. and Patrick R. McDonald (Exhibit 10(a) to Form 8-K dated July 7, 1998).
*10(h) Stock purchase agreement by and between McDonald Energy, LLC and CEC Resources Ltd. (Exhibit 10(b) to Form 8-K dated July 7, 1998).
*10(i) Option agreement among CEC Resources Ltd. and McDonald Energy, LLC (Exhibit 10(c) to Form 8-K dated July 7, 1998).
10(j) Financing Commitment by and between CEC Resources Ltd. and Canadian Imperial Bank of Canada.
11 Statement of computation of per share earnings.
23(a) Consent of PricewaterhouseCoopers LLP Chartered Accountants.
23(b) Consent of Reed W. Ferrill and Associates, Inc.
23(c) Consent of Sproule Associates Limited.
27 Financial Data Schedule
- -------------------------------------------------------------------------------- *Incorporated by reference
CEC RESOURCES LTD.
AUDITORS' REPORT
To the Stockholders of CEC Resources Ltd.
We have audited the balance sheets of CEC Resources Ltd. as at November 30, 1998 and 1997, and the statements of income, stockholders' equity and cash flows for each of the three years in the period ended November 30, 1998. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about 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 financial statements present fairly, in all material respects, the financial position of CEC Resources Ltd. as at November 30, 1998 and 1997 and the results of its operations and its of cash flows for each of the three years in the period ended November 30, 1998, in accordance with accounting principles generally accepted in Canada.
PricewaterhouseCoopers LLP Chartered Accountants
February 16, 1999 Calgary, Canada - ---------------
COMMENTS BY THE AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE - -----------------------------------------------------------------------------
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company's financial statements, such as the change described in Note 4 to the financial statements. Our report to the shareholders dated February 16, 1999 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditor's report when the change is properly accounted for and adequately disclosed in the financial statements.
PricewaterhouseCoopers LLP Chartered Accountants
February 16, 1999 Calgary, Canada - ---------------
CEC RESOURCES LTD.
BALANCE SHEETS
ASSETS ------
CEC RESOURCES LTD.
BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------
The accompanying notes are an integral part of these financial statements.
CEC RESOURCES LTD.
STATEMENTS OF INCOME --------------------
The accompanying notes are an integral part of these financial statements.
CEC RESOURCES LTD. STATEMENTS OF STOCKHOLDERS' EQUITY For The Three Years Ended November 30, 1998 (in Canadian dollars) (in thousands, except shares)
The accompanying notes are an integral part of these financial statements.
CEC RESOURCES LTD.
STATEMENTS OF CASH FLOWS (Note 4)
The accompanying notes are an integral part of these financial statements.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS
(1) FORMATION AND OPERATIONS OF THE COMPANY
CEC Resources Ltd. ("Resources" or "the Company") was incorporated as an Alberta, Canada corporation on May 31, 1955 and, since its acquisition in 1969 as a wholly-owned Canadian subsidiary by its former parent, Consolidated Oil & Gas, Inc., has been engaged in exploration, development and production of oil and gas reserves in Canada and oil and gas field services. Resources was a wholly-owned subsidiary of Columbus Energy Corp. ("Parent" or "Columbus") from 1984 until February 24, 1995 when 100% of the Resources shares were sold by its Parent to its shareholders or the public in a rights offering.
(2) ACCOUNTING POLICIES
The financial statements of the Company are prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and require the use of management's estimates. The following is a summary of the significant accounting policies followed by the Company.
Currency --------
The amounts in these financial statements and notes thereto are in Canadian dollars, unless otherwise stated.
Cash Equivalents ----------------
For purposes of the statements of cash flows, the Company considers all temporary investments to be cash equivalents. Results of hedging activities, when employed, are included in cash flow from operations in the statements of cash flows.
Oil and Gas Properties ----------------------
The Company follows the full cost method of accounting whereby all costs associated with the acquisition of, exploration for and the development of oil and gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenditures, drilling productive and non-productive wells and tangible production equipment. General and administrative expenses are capitalized to the extent such costs are directly associated with acquisition, exploration and development of oil and gas properties. Proceeds from the sale of petroleum and natural gas properties reduce capitalized costs without recognition of a gain or loss unless such a sale would significantly alter the rate of depletion and depreciation.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
Capitalized costs, including tangible production equipment, are depleted using the unit of production method based on proved reserves of oil and gas, before royalties, as estimated by independent engineers. For purposes of the calculation, oil and gas reserves are converted to a common unit of measure on the basis of six thousand cubic feet of gas to one barrel of oil. Depreciation of the liquid extraction plant and other assets are calculated using the straight line method over their estimated useful lives.
In applying the full cost method, the Company performs a ceiling test which restricts the net capitalized costs from exceeding an amount equal to the estimated undiscounted value of future net revenues from proven oil and gas reserves, based on current prices and costs, after deducting estimated future operating costs, development costs, general and administrative expense and income tax expense.
Estimated future site abandonment and restoration costs are provided using the unit of production method over the life of proven reserves with the current year provision included in depreciation, depletion and amortization expense. Site abandonment and restoration expenditures incurred are recorded as a reduction of the accumulated accrual.
Income Taxes ------------
The liability method is used in measuring income taxes based on temporary differences including both timing differences and other differences between the tax basis of an asset or liability and its carrying amount in the financial statements. This method uses the tax rate and tax law expected to apply to taxable income in the periods in which the future income tax asset or liability is expected to be realized. The Company is subject to tax under applicable Canadian tax law.
Field Services --------------
The Company recognizes revenue for field services provided to third parties from its one-third ownership in the Carbon area liquids extraction plant as well as from facilities in other fields.
The Company's share of the cost of providing such third party services is expensed and shown as "field services" cost.
Earnings Per Share ------------------
Basic earnings per share is calculated using the weighted average number of shares of common stock outstanding during the year. Fully diluted earnings per share is calculated
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
assuming the exercise of outstanding options.
(3) RECLASSIFICATION
Effective for the 1998 fiscal year, Resources has classified its stockholders' equity to conform to Canadian laws in Alberta to combine stated capital and additional paid-in capital as share capital as well as to net the purchase of shares against those accounts when they are cancelled. Accordingly, year end stockholder equity balances for 1995 through 1997 have been reclassified as follows:
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
(4) STATEMENTS OF CASH FLOWS
The Company elected to adopt Canadian Institute of Chartered Accountants (CICA) 1540, Cash Flow Statements for fiscal 1998. This statement requires a business enterprise to provide a statement of cash flows in place of a statement of changes in financial position. Application of this statement is required for fiscal years beginning on or after August 1, 1998, and earlier application is encouraged. Cash flow information for earlier years that is presented with corresponding information for the initial year of application is restated to conform to the requirements of CICA 1540 as follows:
There are no restatements for the year ended November 30, 1996. The adjustments for 1997 were due to capital expense accruals that are excluded in calculating cash flows from investing activities.
(5) OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth the capitalized costs related to oil and gas producing activities, costs incurred in oil and gas property acquisition, exploration and development activities, and results of operations for producing activities:
(a) Excludes well facilities cost of $664,000 in 1998 and 1997 that are amortized on a straight-line basis. (b) In 1998 and 1997 no costs are excluded from amortization.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
During the three years ended November 30, 1998, no general and administrative expenses have been capitalized.
(a) Production costs only include lease operating expenses. (b) Depletion and amortization expense per equivalent barrel of production: 1998 - $4.02, 1997 - $3.01, 1996 - $2.15
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
MAJOR CUSTOMERS
The Company sells its own natural gas production in the Carbon and East Carbon areas directly to gas marketing companies. The operator of the gas processing plant pays Resources for liquids sold at the plant tailgate and those amounts are included in Customer 2.
During the fourth quarter of 1998, the Company made a change in accounting estimate in proved reserves due to a significant decrease in proved developed non-producing and proved undeveloped reserves. The majority of this decrease is attributable to the unsuccessful completion of a well in the East Carbon area and additional offset well information. The effect of this change on current year operations was an increase in depletion expense of $190,000.
(6) INCOME TAXES
The provision for income taxes consists of the following (in thousands):
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
The total tax provision has resulted in effective tax rates which differ from the statutory Federal income tax rates. The reasons for these differences are illustrated by the following table:
The tax effect of significant temporary differences representing Canadian deferred tax assets and liabilities and charges were as follows (in thousands):
For Canadian income tax purposes, Resources has the following tax attributes available at November 30, 1998 to reduce future taxable income which have been included in calculating the temporary differences above:
Accumulated property exploration and development costs of $1,696,000, earned depletion base of $1,167,000 and undepreciated capital cost of $1,152,000. The tax attributes of carryforward pools are included to determine the temporary differences shown as deferred tax liabilities. These attributes generally do not expire.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
The earnings before income taxes for financial statements differed from taxable income as follows (in thousands):
(7) RELATED PARTY TRANSACTIONS
The Company incurs certain direct and indirect general and administrative costs for management services provided by its former Parent in lieu of expanding the number of its own full-time employees. These costs are primarily for labor, related benefits and other overhead costs. The following table sets forth these costs, in thousands, for each period:
Year Ended November 30, 1998 $334 Year Ended November 30, 1997 394 Year Ended November 30, 1996 445
(8) CAPITAL STOCK
During November 1996, the Company issued 79,000 shares of common stock at U.S. $5.25 per share by private placement using an investment letter under a Regulation D exemption of which 38,000 shares were purchased by Resources' then President and Chairman of the Board.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
During June 1998, McDonald Energy, LLC,("McDonald") a Colorado limited liability company solely owned by Patrick R. McDonald, currently a director, President and Chief Executive Officer of Resources acquired 70,000 shares of common stock by direct purchase from Resources for U.S. $5.50 per share.
On October 27, 1994 the Company's Board of Directors authorized an unlimited number of shares of preferred stock, no par value, none of which is currently issued.
On October 27, 1994 the Company adopted an Employee Incentive Share Option Plan (the "Plan"). The Plan is administered by a committee appointed by the Board of Directors of the Company. The Plan authorizes the committee to grant options for up to 300,000 shares of the Company's common stock. The shares are to be issued out of the Company's authorized and unissued shares and will be issued as fully paid and non-assessable. Also, the number of Resources shares so reserved for issuance or subject to an option under the Plan to any one person may not exceed 5% of the number of Resources shares which are outstanding at the time of the granting of the option.
Options may be granted to officers, directors and regular full and part- time employees of the Company and majority-owned subsidiaries. Options may be exercised starting one year after grant. The option term cannot be less than one year or more than five years from the date the option is granted. The option price may not be less than 100% of the fair market value of the last trading price on the date the option is granted.
During 1996, the Board of Directors granted stock options for 30,000 shares at the exercise price of U.S. $5.50 per share and an option for 10,000 shares was exercised at the price of U.S. $3.25 per share. At November 30, 1996, there were 80,000 shares under option at prices ranging from U.S. $3.25 to U.S. $6.00 per share, of which 50,000 shares were exercisable.
No options were granted in fiscal year 1997. At November 30, 1997, there were 80,000 shares under option at prices ranging from U.S. $3.25 to U.S. $6.00 per share, all of which were exercisable.
During 1998, the Board of Directors granted stock options for 152,000 shares at exercise prices ranging from U.S. $4.625 to U.S. $5.50 per share and a stock option grant of 10,000 shares at U.S. $6.00 per share expired. At November 30, 1998 there were 222,000 shares under option at prices ranging from U.S. $3.25 to U.S. $6.00 per share, of which 70,000 shares are exercisable.
On June 30, 1998, Resources entered into a Stock Purchase Agreement (the
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
"Agreement") with McDonald. In connection with the Agreement, McDonald was granted a one-year option to purchase 250,000 shares of common stock at U.S. $6.00 per share, all of which are exercisable and were granted in addition to options granted to Mr. McDonald as a director and officer.
(9) Financial Instruments
The nature of the Company's operations exposes the Company to fluctuations in commodity prices. The Company attempts to manage these risks by minimizing its commodity price exposure through the use of derivative contracts. Gain and losses on these contracts are deferred and recognized in income as an adjustment to oil and gas sales revenues during the period in which the physical product to which the contracts relate is actually sold.
During the fourth quarter of 1998, the Company entered into three AECO C/N.I.T. based forward price hedge transactions. The terms of these transactions are as follows:
The unrecognized gain on these contracts totaled $148,000 based on November 30, 1998 market values.
(10) COMMITMENTS AND CONTINGENT LIABILITIES
The Company leases office space in Calgary, Alberta and Denver, Colorado. These leases are month-to-month with no related future minimum lease payments. Total rent expense for 1998, 1997 and 1996 was $64,000, $34,000 and $33,000, respectively.
The Company adopted a separation pay policy effective February 24, 1995 which covers all regular terminations and, in addition, certain "special" terminations of officers in the case of certain contractions and restrictions of the Company, or in the event of a change of control of the Company. At the discretion of the Board of Directors, officers and non-officer employees may receive upon their retirement the same benefits they would have
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
received upon a friendly change of control of the Company. As of November 30, 1998 no benefits are payable.
Resources sells its natural gas production in the Carbon and East Carbon areas directly to certain gas marketing companies. At November 30, 1998 the Company had entered into three forward price hedge transactions, as described in Note 9. The majority of the Company's remaining gas is contracted to a gas marketing company on a deliverability basis and sold at published index prices less applicable transportation and marketing charges. The Company has assigned its firm transportation agreements through October 1999 but has reserved the right to obtain firm transportation service in its own name.
The Company estimates that future costs of site abandonment and restoration of well sites, gas processing plant and other facilities will be $310,000 as of November 30, 1998 in addition to $165,000 already accrued as a liability. The estimated costs are being recognized on the unit of production basis over the life of the properties.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
(11) INDUSTRY SEGMENTS
The Company's business is primarily participating in (1) oil and gas exploration and development, and (2) field services.
Summarized financial information concerning the business segments is as follows:
(a) Inter-segment revenues of $394,000, $416,000 and $485,000 for 1998, 1997 and 1996, respectively, are included in services revenues and are offset by the same amounts in oil and gas operating expenses.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
(12) CONCENTRATIONS OF CREDIT RISK AND FINANCIAL INSTRUMENTS
The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value because of the short maturity of these instruments. Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of cash and cash equivalents and accounts receivable.
The Company maintains demand deposit accounts with separate banks in Calgary, Alberta and Denver, Colorado. The Company also invests cash in the highest rated commercial paper of large Canadian companies, with maturities not over 30 days, which have minimal risk of loss. At November 30, 1998 the Company had $1,598,000 invested in such commercial paper.
Most jointly owned oil and gas properties are operated by other companies who sell oil and liquids production to relatively large Canadian oil and gas purchasers (see Note 5) and who pay vendors of oil and gas services on the wells. The Company sells its own natural gas production in the Carbon and East Carbon Areas directly to certain gas marketing companies. The risk of non- payment by the purchasers or by those operators is monitored and is considered minimal. The Company does not obtain collateral from these purchasers to assure payment for sales to them. Joint interest receivables are subject to collection under the terms of operating agreements which provide lien rights to the operator.
In management's judgment, termination by any purchaser under which its present sales are made would not have a material impact upon its ability to sell its production to another purchaser at similar prices. Also, because the Company has a high percentage of natural gas reserves, results of operations are particularly sensitive to current pricing. The sensitivity to current prices has been partially mitigated by the Company's use of financial instruments that provide a fixed sales price for a percentage of the Company's production.
(13) GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES
The financial statements have been prepared in accordance with Canadian GAAP which differ in certain respects from those principles that the Company would have followed had its financial statements been prepared in accordance with U.S. GAAP. Differences in disclosures which affect these financial statements are:
(a) Under U.S. GAAP, cash (and cash equivalents) includes bank deposits, money market instruments, and commercial paper with original maturities of three months or less.
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
Canadian GAAP permits the inclusion of temporary investments with maturities greater than 90 days in cash. The differences in measurement had no impact on classification in the balance sheets.
(b) Basic earnings per share using U.S. GAAP is the same as basic earnings per share using Canadian GAAP. Diluted earnings per share using U.S. GAAP uses the "treasury stock method". Fully diluted earnings per share using Canadian GAAP assumes cash proceeds from the deemed exercise of stock options are invested in such a way as to earn a reasonable return but the number of shares remains the same.
(c) Using the full cost accounting method under U.S. GAAP, the ceiling test is applied to capitalized costs using a 10% discount factor. There would be no impairment of the U.S. full cost pool under this method.
Stock Based Compensation Plans - ------------------------------
Using U.S. GAAP, the Company would have adopted in 1996, Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"). The Company would have elected to continue to measure compensation costs for these plans using the current method of accounting under Accounting Principles Board ("APB") Opinion No. 25 and related interpretations in accounting for its stock option plan. Accordingly, no compensation expense is recognized for stock options granted with an exercise price equal to the market value of Resources stock on the date of grant. Had compensation cost for the Company's stock option plan been determined using the fair-value method in SFAS No. 123, the Company's net income and earnings per share would have been as follows:
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
Options are granted at 100% of fair market value on the date of grant. The following table is a summary of stock option transactions (reported in U.S. dollars) for the three years ended November 30, 1998:
The following table summarizes information about the Company's stock options (reported in U.S. dollars) outstanding at November 30, 1998:
CEC RESOURCES LTD. NOTES TO THE FINANCIAL STATEMENTS - (continued)
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:
No options were granted during 1997.
(14) SUBSEQUENT EVENTS
In December 1998, the Company acquired working interests in 16 producing natural gas wells and associated leaseholds in the Wayne-Rosedale Field, located in Alberta, Canada, effective September 1, 1998 for $2.3 million. The assets, liabilities, revenues and expenses for the period September through November 1998 have not been recorded as of November 30, 1998 because the closing did not take place until after year end.
In December 1998, the Company secured a financing commitment. The initial commitment is a $2.5 million revolving production loan. The revolving phase of the loan will expire on April 30, 1999 and may be renewed by the bank. The interest rate on outstanding borrowings is the CIBC Prime Rate plus 3/4 of 1%.
SIGNATURES - ----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.