Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
(a) On July 2, 1990, DEKALB Energy Company (``DEKALB'' or the ``Company'') purchased from Royal Producing Corp. - Texas, an interest in thirty-six onshore oil and gas fields, most of which were located in the Texas Gulf Coast. On July 3, 1990, the Company transferred its interest in certain of these acquired fields in exchange for cash and an increased interest in one of the fields obtained through the acquisition. The purchase price was funded through the Company's revolving credit agreement. On July 12, 1990, the Company issued $75 million of 9 7/8% notes due July 15, 2000, in a public offering. The net proceeds of $74.4 million were used to reduce the line of credit borrowing.
On October 16, 1992, the Company sold substantially all of its U.S. oil and gas properties to Louis Dreyfus Gas Holdings Inc. The Company did not sell its Canadian or California properties. The effective date of the transaction was July 1, 1992. Proceeds from the transaction were used primarily to reduce the Company's long-term debt.
On August 5, 1993, the Company sold all of its California gas wells to Samedan Oil Corporation. The effective date of the transaction was July 1, 1993. Proceeds from the transaction were used to repurchase long-term debt. The Company's only remaining assets in the U.S. are a non-operated interest in an oil well in California and acreage adjacent thereto.
On December 21, 1994, the Company entered into a merger agreement with Houston-based Apache Corporation (``Apache'') under which outstanding shares of DEKALB Class A Stock and Class B (nonvoting) Stock will be converted into between .85 and .90 shares of Apache Common Stock depending upon the price of Apache's Stock during a period shortly before the merger. DEKALB's holders of Class A Stock will be asked to approve this transaction at a shareholders' meeting that will be held during this spring.
(b) DEKALB is engaged in only one industry segment on a continuing basis.
(c) DEKALB is engaged in the exploration for, and the development and production of, crude oil and natural gas in Canada. The Company's wholly-owned Canadian subsidiary, DEKALB Energy Canada Ltd., concentrates its exploration and development activity in the Provinces of Alberta and British Columbia. Since the disposition of the U.S. assets in 1992 and 1993, DEKALB's only U.S. activity is an interest in one non-operated California well.
DEKALB's operations are largely dependent upon its ability to discover or acquire reserves of oil and natural gas, to produce oil and natural gas in commercial quantities, and to obtain additional unproved oil and gas lands by lease, option, concession, or otherwise. The prices obtained for the sale of oil and natural gas depend upon numerous factors, most of which are beyond the control of the Company, including the domestic and foreign production rates of oil and natural gas, market demand, and the effect of government regulations and incentives.
The Company uses the full cost method of accounting, under which the cost of all exploration and development activities (both successful and unsucessful) is capitalized and subsequently amortized to expense using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related capitalized interest costs are excluded from the amortization base until the properties associated with these costs are evaluated and determined to be productive or impared. Should the net evaluated capitalized cost (net of deferred income taxes) exceed the estimated after-tax present value of oil and gas reserves (using prices in effect at the end of each quarter being reported) plus the unimpared value of unevaluated properties on a country-by-country basis, the excess would be charged to expense. No write-down of the Company's capitalized costs was required under this
ITEM 1. BUSINESS (continued)
method in 1994, nor would a write-down be required using current prices. However, should natural gas prices continue to decline from current levels, the Company could be required to record an impairment of its oil and gas properites in 1995.
Competition
There is a high degree of competition in the oil and gas industry for the acquisition of prospective oil and gas properties and oil and gas reserves, and in the marketing and transportation of natural gas. A number of the companies with which DEKALB competes are substantially larger and have greater financial resources than DEKALB.
Marketing
Oil produced by DEKALB is sold to crude oil purchasers or refiners at market prices which depend on worldwide crude prices adjusted for location and quality of the oil. Natural gas produced by DEKALB is sold to major aggregators of natural gas, gas marketers and direct users under long and short-term contracts. These contracts provide for sales at specified prices, or at prices which are subject to change due to market conditions. The Company also enters into hedge contracts from time to time to reduce the Company's exposure to oil and gas price fluctuations.
The Company diversifies the markets for its Canadian gas production by selling directly or indirectly to customers through aggregators and brokers in the United States and Canada. The Company transports natural gas via the Company's firm transportation contracts to California (12 million cubic feet per day) and the Province of Ontario, Canada (4 million cubic feet per day) through end-users' firm transportation contracts. In addition, the Company has contracted for the sale of 5 million cubic feet per day of natural gas to the Hermiston Cogeneration Project in the Pacific Northwest of the United States. The Hermiston Project is expected to commence purchases of natural gas in the third quarter of 1996.
Environmental Matters
In general, the exploration and production activities of the Company are subject to certain federal, provincial, state, and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the cost of these activities and may prevent or delay the commencement or continuance of a given operation. The Company charged $0.4 million in 1994, $0.6 million in 1993 and $0.6 million in 1992 against income for future removal and site restoration costs. The 1994 and 1993 amounts related primarily to the Canadian operations.
General
In 1994, two Canadian customers each accounted for 11% of the Company's sales. The Company does not believe that the loss of these customers would have a material adverse effect upon the Company.
At December 31, 1994, the Company had 95 employees in Canada, and 1 employee in the United States.
(d) Geographic Segment Information for 1992 is included in Part II, Item 8, Note L of the Consolidated Financial Statements. Information for the U.S. and Canada has been combined for 1994 and 1993 due to the immateriality of the U.S. information in relation to the Company as a whole.
ITEM 2.



ITEM 2. PROPERTIES
Offices
DEKALB leases approximately 40,000 square feet of office space in Calgary, Alberta, Canada from which it directs its business.
Acreage
The following table summarizes DEKALB's interest in developed and undeveloped oil and gas acreage located in the Provinces of Alberta and British Columbia, Canada as of December 31, 1994. U.S. acreage is not significant and has been combined with the Canadian acreage.
(a) Undeveloped acreage represents leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas.
Productive Wells and Drilling Activity
The Company owns varying working interests in producing oil and gas wells located in the Provinces of Alberta and British Columbia, Canada and one well in the State of California. The Company also owns interests in twelve gas processing plants located in the Province of Alberta, Canada.
The following table summarizes DEKALB's interest in the productive oil and gas wells as of December 31, 1994.
(1) One or more completions in the same well bore are counted as one well. The data in the above table includes 20 oil wells (12 net) and 61 gas wells (57 net) that are multiple completions in Canada. The only U.S. well is completed in one zone.
ITEM 2. PROPERTIES (continued)
The following table summarizes the number of net productive exploratory and development wells in which DEKALB participated, the number of net dry exploratory and development wells drilled and the net total wells drilled for the years ended December 31, 1994, 1993, and 1992:
Sales
The following table summarizes DEKALB's net oil and gas sales for the years ended December 31, 1994, 1993, and 1992:
ITEM 2. PROPERTIES (continued)
Average Prices and Cost per Unit of Sales
The following table shows the average sales prices received by DEKALB and the lease operating expense per equivalent barrel of oil for the years ended December 31, 1994, 1993, and 1992:
Reserves
The estimated proved developed and undeveloped oil and gas reserves of DEKALB, as of December 31, 1994, 1993, and 1992, and the standardized measure of discounted future net cash flows attributable thereto, are included in Supplementary Financial Information.
Reserve estimates for U.S. operated wells were reported by the Company to the U.S. Department of Energy during 1994 and were prepared on a basis consistent with the reserve estimates contained herein. Reserve estimates submitted to the U.S. Department of Energy were prepared as of December 31, 1993 and 1992 based on December 31, 1993 and 1992 reserve reports, respectively, and represent the gross remaining recoverable reserves assigned to the properties operated by DEKALB. Effective July 1, 1993 DEKALB sold substantially all of its remaining U.S. holdings to Samedan Oil Corporation. The only U.S. assets retained by DEKALB are a single non-operated oil well in California and acreage adjacent thereto.
December 31, 1994 reserve forecasts utilized December 1994 actual prices for gas and natural gas liquids and the December 31st postings for oil and condensate in accordance with Securities and Exchange Commission (SEC) Guidelines and do not reflect current prices. The Company has also incorporated future removal and site restoration costs of $6.8 million ($1.0 million present value) as of December 31, 1994, $6.9 million ($0.8 million present value) as of December 31, 1993, and $7.7 million ($1.1 million present value) as of December 31, 1992 into the forecasts.
Since December 31, 1994, there have been no material discoveries, extensions or revisions which would either favorably or adversely affect the Company's proved reserve quantities.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
Management is of the opinion there are no pending legal proceedings that would have a material effect on the consolidated financial position, results of operations, or liquidity of the Company.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders in the fourth quarter of 1994.
Executive Officers of the Registrant
The names, ages, and positions of the executive officers of the Company, with their business experience during the past five years, are shown below. Officers are elected annually by the Board of Directors.
Officer Age ------- ---
Donald McMorland.............................................67 President, Vice Chairman of the Board and Director
Mr. McMorland was elected President and Vice Chairman of the Board on May 13, 1994. He was Chairman of the Board of Alberta & Southern Gas Co. Ltd. from October 1, 1991 until June 30, 1994. He was Executive Vice President and Chief Operating Officer of that company until he was elected President and Chief Executive Officer in July 1990. He resigned as President and Chief Executive Officer in October 1993. He was also Senior Vice President and a director of Alberta Natural Gas Company Ltd. until he resigned as an officer in April 1991 and as a director in December 1991.
John H. Witmer, Jr...........................................54 Vice President, General Counsel and Secretary
Mr. Witmer was elected Senior Vice President, General Counsel and Secretary on March 2, 1989. He relinquished the position of Senior Vice President and was elected Vice President on November 19, 1992. He has been Senior Vice President, General Counsel and Secretary of DEKALB Genetics Corporation for the past five years.
Richard G. Nash..............................................52 Vice President, Exploration and Land - DEKALB Energy Canada Ltd.
Mr. Nash has served as Vice President, Exploration and Land of DEKALB Energy Canada Ltd. since July 20, 1992. He joined DEKALB Energy Canada Ltd. as Vice President, Exploration in 1986.
John Leteta..................................................59 Vice President, Finance and Treasurer
Mr. Leteta was appointed Vice President, Finance and Treasurer on September 17, 1994. He had retired from DEKALB Energy Canada Ltd. in 1991 after thirty-one years of service. During that time, he last served DEKALB Energy Canada Ltd. as Vice President of Finance and Administration.
Larry G. Evans...............................................39 Vice President, Production - DEKALB Energy Canada Ltd.
Mr. Evans has served as Vice President, Production of DEKALB Energy Canada Ltd. since August 1993. From August 1990 to August 1993, he served as Vice President, Engineering. Prior to that date, he served as Manager of Engineering.
Bruce A. Craig...............................................41 Vice President, Marketing - DEKALB Energy Canada Ltd.
Mr. Craig has served as Vice President, Marketing of DEKALB Energy Canada Ltd. since November 1992 when he joined the Company. Prior to joining DEKALB Energy Canada Ltd., he served as Manager, Oil and Gas Marketing for Kerr-McGee Canada Ltd. (formerly Maxus Energy Canada Ltd.)
Eddy Y. Tse..................................................44 Chief Accounting Officer
Mr. Tse was elected Chief Accounting Officer on November 11, 1992. He has also served as Chief Accounting Officer of DEKALB Energy Canada Ltd. since November 1992 and as Controller since July 1991. Prior to that date, he served DEKALB Energy Canada Ltd. as the Manager of Taxes.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S STOCK AND RELATED STOCKHOLDERS' MATTERS
A. As of February 28, 1995 there were approximately 920 record holders of Class A Stock and approximately 2,100 record holders of Class B (nonvoting) Stock. Class B shares are currently being traded on the NASDAQ/NMS over-the-counter market and the Toronto Stock Exchange.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA (continued)
ITEM 6. SELECTED FINANCIAL DATA (continued)
NOTES:
(1) Return on sales was calculated by dividing earnings (loss) from continuing operations by total operating revenues. (2) Return on assets was calculated by dividing earnings (loss) from continuing operations by beginning total continuing assets. (3) Return on equity was calculated by dividing earnings (loss) from continuing operations by beginning shareholders' equity. (4) Total debt as a % of capitalization was calculated by dividing total debt by shareholders' equity plus total debt. (5) Gas is converted to oil at 6,000 cubic feet per barrel. (6) Book value per share was calculated by dividing shareholders' equity by the total year-end shares outstanding. (7) Includes the effect of hedge contracts. Prices before the effect of hedging were $15.43 for the 1994 combined operations, $17.45 for the U.S. and $18.74 for Canada in 1992, $18.77 for the U.S. and $19.75 for Canada in 1991, and $22.07 for the U.S. and $22.73 for Canada in 1990. There were no oil hedge contracts in place during 1993. (8) Includes the effect of the Royal acquisition. (9) 1992 includes six months of U.S. expenditures on all divested properties, and 12 months of California and Canadian properties; 1993 includes six months of U.S. expenditures on divested California properties, and 12 months of expenditures in Canada and on the one remaining oil well in California. (10) There were no U.S. expenditures incurred during 1994. 1992 includes six months of U.S. operating data on divested properties, and 12 months of California properties. For 1993, six months of U.S. operating data on divested properties, and 12 months of the remaining California property has been combined with Canadian operating data due to the immateriality in relation to the operating results as a whole. 1994 again represents the combined U.S. and Canadian operations. (11) U.S. reserve data has been combined with Canada for 1993 due to the immateriality of the U.S. reserves in relation to the total Company reserves as a whole. No U.S. reserves have been assigned at December 31, 1994. (12) Includes the effect of hedge contracts. 1994 prices before the effect of hedging averaged $1.47 for the combined operations.
Reference is made to Management's Discussion and Analysis of Financial Condition and Results of Operations and to the Financial Statements and Supplementary Financial Information for a discussion of the Company's operations and financial position.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW --------
1994 earnings and earnings per share from continuing operations rose 20.1% and 20.3%, respectively, compared with 1993. These improved results were reflective of significantly higher natural gas prices during the first nine months of 1994, as well as increasing oil prices in the last half of 1994 and the positive impact of the Company's hedging activities. 1994 results also reflect the impact of the lower Canadian dollar exchange rate, resulting in lower U.S. dollar equivalent expenses.
Net earnings for 1994 were $4.2 million lower and $77.1 million higher than in 1993 and 1992, respectively. 1993 earnings included a one-time tax benefit of $5.3 million due to the adoption of Statement of Financial Accounting Standard (SFAS) 109 ``Accounting for Income Taxes''. The net loss in 1992 was primarily due to the loss of $34.9 million pre-tax ($32.3 million after-tax) on the disposition of substantially all of the Company's U.S. oil and gas properties to Louis Dreyfus Gas Holdings Inc., and the writedown of oil and gas properties of $53.3 million pre-tax ($40.6 million after-tax).
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
DISPOSITION OF ASSETS ---------------------
In November 1994, the Company announced the sale of its interest in a gas plant, leasehold, and other tangible property in the Claresholm area in the Province of Alberta, Canada. The sale was effective November 1, 1994 for proceeds of $9.0 million. During the third quarter of 1994, the Company sold its interest in leasehold and tangible property in the Buick Creek area of the Province of British Columbia, Canada for proceeds of $0.4 million. In March 1994, the Company sold its interest in leasehold and tangible property in the Rigel area of the Province of British Columbia, Canada for proceeds of $3.6 million. In accordance with the full cost method of accounting, the proceeds received for the 1994 dispositions were credited to the full cost pool; therefore, no gains or losses were recorded on the sales.
Effective July 1, 1993, the Company sold all of its California gas wells to Samedan Oil Corporation for $5.1 million. Consistent with the full cost method of accounting on a cost center basis, the Company recorded a $0.5 million pre-tax and after-tax gain on the disposition of the California gas wells in the third quarter of 1993. The Company also closed its exploration office in Bakersfield in 1993. The Company's only remaining assets in the U.S. are a non-operated working interest oil well in California and acreage adjacent thereto.
On July 9, 1992, the Company announced that it had entered into a definitive agreement to sell substantially all of its U.S. oil and gas properties to Louis Dreyfus Gas Holdings Inc. On October 16, 1992, the Dreyfus transaction was approved by the shareholders at a special shareholders' meeting, and the closing of the transaction was completed on the same day. The Company did not sell its California properties in this transaction. The Company received $104.0 million of gross proceeds from the sale, which included approximately $6.0 million of cash flow from the properties from the effective date (July 1, 1992). In addition, Dreyfus assumed certain liabilities. In 1992 a loss on the disposition of $34.9 million was recorded ($32.3 million after- tax).
Sales revenues and volumes, lease operating expenses and depreciation, depletion and amortization (DD&A) associated with the U.S. divested properties for the six months ended June 30, 1993 and 1992, are shown under Note C, Disposition of Assets in the Notes to the Consolidated Financial Statements.
DRILLING ACTIVITY ----------------- Consistent with its focus on long-term growth through exploration and development, the Company participated in the drilling of 68 exploration and development wells (49.96 net wells) during 1994, with a success rate of 78% (82% on a net well basis). Fifty-six gas targets and twelve oil targets were drilled, primarily in the Nevis and Kaybob areas of Alberta, and in northeast British Columbia. Of particular significance was a successful 100% Company-owned and operated well drilled in the first quarter on the Hunter prospect in northeast British Columbia, where 26 feet of gas pay in the Halfway zone was encountered, with an established production test rate of 6.4 MMCF per day before royalties at 375 psi flowing tubing pressure. The well is expected to be tied in during the first half of 1995.
The Company participated in the drilling of 26 net wells in 1993 and 16 net wells in 1992.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
OPERATING REVENUES ------------------
1994 operating revenues of $46.3 million increased slightly from $45.9 million in 1993. The increase was mainly due to higher gas prices during the first nine months of 1994 and the positive impact of the Company's hedging activities, partially offset by decreased gas production and low oil prices during the first half of the year, and weakening gas prices in the last quarter. The 23.8% decline in 1994 operating revenues compared to 1992 results primarily from the disposition of the U.S. oil and gas properties in prior years.
Gas revenues for 1994 increased to $31.5 million from $30.2 million in 1993 and $30.7 million in 1992. This was due to improved gas prices which rose to an average of $1.61 per thousand cubic feet (MCF) during the first nine months of 1994, compared to $1.40 and $1.23 during the 1993 and 1992 comparative periods, respectively. A significant weakening in gas prices was seen in the 1994 fourth quarter, however, with an average Company gas price of $1.32 per MCF compared to $1.56 and $1.45 in 1993 and 1992, respectively. System gas prices received during the first nine months of 1994 were 18.8% and 33.3% higher than in the 1993 and 1992 comparative periods, respectively. Fourth quarter system gas prices were $1.00 per MCF compared to $1.56 in 1993 and $1.38 in 1992. Direct gas sales (short-term and spot) prices for the first nine months of 1994 were $1.41, up 9.3% and 80.8% compared to 1993 an 1992, respectively. For the fourth quarter, direct gas sales prices were $0.91 per MCF in 1994, $1.49 in 1993 and $1.35 in 1992. System and direct gas sales accounted for approximately 42% and 58%, respectively, of total Company 1994 gas sales volumes.
1994 gas sales volumes were down 2.3% from 1993 and 14.5% from 1992. This decline was principally due to the disposition of the Company's U.S. oil and gas properties in 1992 and 1993 (see Note C, ``Disposition of Assets,'' in the Notes to the Consolidated Financial Statements). In addition, a unitization adjustment was recorded in the second quarter of 1993, resulting in additional gas volumes relating to prior periods of approximately 220 MMCF. General field declines, compressor installations and repairs, and several plant turnarounds also resulted in some curtailment of production during the first half of 1994. Gas volumes for the third and fourth quarters were 13.0% and 3.8% higher, respectively, in 1994 versus 1993.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
OPERATING REVENUES (CONTINUED) ------------------------------
The Company's 1994 oil and condensate prices were 2.9% and 12.5% lower compared to 1993 and 1992, respectively. During the first six months of 1994, the Company received an average of $14.36 per barrel versus $17.49 in 1993. These prices followed changes in the WTI oil price, which averaged $16.28 per barrel during the first half of 1994 compared with $19.82 per barrel in the 1993 comparative period. A significant recovery was seen in the second half of 1994, however, with the Company's oil and condensate prices and the WTI oil price averaging $16.69 and $18.08 per barrel, respectively. Natural gas liquids prices similarly followed those of oil and condensate, with the Company receiving an average price of $2.18 per barrel less in the first half of 1994 versus 1993, but a 36 cent higher price in the second half of 1994 versus 1993. Combined 1994 oil, condensate and natural gas liquids volumes decreased slightly from 1993. The decrease in oil, condensate and natural gas liquids volumes of 799 Mbbls compared to 1992, again related to the disposal of the U.S. properties in 1992 and 1993.
During 1994, the Company tied in approximately 17.1 MMCFD of gas production. Forty-five gas wells in the Province of Alberta and nine oil wells in the Province of British Columbia were brought onto production during 1994. The Company's new plant in the Godin area in the Province of Alberta also commenced gas processing in December 1994. The plant was at full capacity beginning in January 1995 with a capability of approximately 10.0 MMCF per day.
To protect against oil and natural gas price fluctuations, the Company has entered into various hedge contracts for a portion of its oil and gas (see Note H, ``Commitments and Contingencies and Off-Balance Risks, Hedge Contracts,''in the Notes to the Financial Statements). A net gain of $1.5 million was recognized as a component of operating revenues in 1994 as a result of these hedge contracts. The effect of the gain on average prices was 34 cents per BOE based on total Company volumes.
OPERATING EXPENSES ------------------
1994 lease operating expenses and other direct charges were down 6.5% compared to 1993, and 38.1% compared to 1992. These declines primarily result from the disposition of the Company's U.S. properties in 1992 and 1993 (see Note C, ``Disposition of Assets'' in the Notes to the Consolidated Financial Statements), processing rate adjustments relating to current and prior years' production from two of the Company's non-operated fields, and a lower Canadian dollar exchange rate. In addition, a third party gas processing fee adjustment for 1991 and 1992 of $.6 million was recorded in the second quarter of 1993. During the 1994 fourth quarter, higher non-operated and third party processing costs, processing revenue adjustments relating to prior years and workover costs were incurred, which partially offset the decreases during the first nine months of 1994. Excluding the impact of the Canadian dollar exchange rate, the Company has maintained a constant per barrel of oil equivalent lease operating cost figure for 1994, 1993 and 1992.
1994 depreciation, depletion and amortization expense (``DD&A'') fell $0.5 million from 1993, primarily due to the disposition of the Company's higher cost California properties in 1993, lower sales volumes and a lower Canadian DD&A rate resulting from lower exchange rates. 1994 DD&A expense decreased $7.9 million from 1992, principally due to the sale of the U.S. assets and writedowns of oil and gas properties in 1992.
1994 general and administrative expense decreased by $0.3 million and $3.3 million compared to 1993 and 1992, respectively. This was primarily due to the lower Canadian dollar and the closure of the California and Denver offices in 1993 and 1992, partially offset by increased costs resulting from increased Canadian office staff levels.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
OPERATING EXPENSES (CONTINUED) ------------------------------
In 1992, the Company recorded a $53.3 million writedown of its Canadian and U.S. oil and gas properties. The $0.5 million gain on disposal in 1993 resulted from the sale of the California gas wells to Samedan Oil Corporation. The $34.9 million loss in 1992 related to the sale of the U.S. oil and gas properties to Louis Dreyfus Gas Holdings Inc.
NON-OPERATING ITEMS -------------------
1994 interest expense, net of interest income and capitalized interest, increased 6.6% compared to 1993. The increase was due to additional interest charges on the Company's Canadian revolving term credit facility, partially offset by lower capitalized interest and exchange rates, and lower U.S. interest costs as a result of the repurchase of a portion of the Company's public notes in 1993. 1994 net interest expense was $2.9 million below 1992, mainly due to the repurchase of $18.4 million in 1993 and $55.3 million in 1992 of the Company's publicly held notes.
Net other income in 1994 related mainly to settlement of a prior year lawsuit for which an allowance had previously been provided, and gas contract and transportation adjustments. Offsetting these 1994 income items were a net foreign exchange loss arising from translation of monetary items related to the Canadian operations and a provision for merger costs incurred to year end (see ``Prospective and Other Information ''further in this section). Net other income in 1993 primarily related to a gas contract settlement. In 1992, the Company recorded a $2.0 million gain on the sale of its 5% interest in Natural Gas Clearinghouse (``NGC''). Equity earnings from the partnership interest in NGC of $0.8 million were also recognized in 1992.
INCOME TAXES ------------
In 1994, the income tax expense reflected a different effective tax rate (47.0%) from the statutory Canadian income tax rate of 44.34%, mainly due to non-income and other tax charges (capital and withholding taxes).
At December 31, 1994, the Company had various offsetting tax matters pending relating to the Canadian operations which have not been provided for in the financial statements. In the opinion of management the net impact of these matters will not have a material effect on the consolidated financial position, results of operations, or liquidity of the Company, and will be provided for in the financial statements if required upon resolution of each item.
The Company adopted Statement of Financial Accounting Standard (``SFAS'') No. 109, ``Accounting for Income Taxes'' as of January 1, 1993. A one-time benefit adjustment of $5.3 million was recognized in the first quarter of 1993.
The tax benefit of $9.8 million for 1992 resulted from the disposition of U.S. assets and the writedown of oil and gas properties in 1992.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
CASH FLOWS FROM OPERATING ACTIVITIES ------------------------------------
1994 cash flows from operating activities before changes in assets and liabilities increased $1.8 million from 1993 and decreased $4.7 million from 1992. 1994 and 1993 reflects the Company as a primarily Canadian operation, while 1992 included revenues from the U.S. assets which were subsequently sold. The increase in 1994 from 1993 is primarily due to higher operating revenues, as well as lower operating expenses which are impacted by the lower Canadian dollar exchange rate.
Cash flows from continuing operations decreased by 25.1% from 1993, mainly due to a lower year-end accounts payable and other current liabilities balance, and an increase in accounts receivable and other current assets. In addition, the Company received U.S. tax refunds of $5.6 million from tax loss carrybacks during 1993.
Taxes paid in 1994, 1993, and 1992 primarily relate to the Canadian Large Corporations Tax, withholding taxes and franchise taxes.
Cash flows from discontinued operations in 1994, 1993 and 1992 relate to settlement of pending litigation from prior years.
CASH FLOWS FROM INVESTING ACTIVITIES ------------------------------------
Purchases of property, plant and equipment were $43.0 million in 1994 compared to $22.9 million in 1993 and $25.1 million in 1992, reflecting a significant increase in capital spending related to exploration and development.
During 1994, the Company disposed of its interest in various property in the Buick Creek and Rigel areas of the Province of British Columbia, Canada, the Claresholm area of the Province of Alberta, Canada, and other miscellaneous assets for total proceeds of $13.7 million. In accordance with the full cost method of accounting, the proceeds were credited to the full cost pool, therefore no gains or losses were recorded on the sales (see Note C, ``Disposition of Assets,'' in the Notes to the Consolidated Financial Statements).
1993 proceeds of $0.9 million from the sale of property, plant and equipment were received primarily as a result of the sale of several small Canadian properties. 1993 proceeds of $6.2 million from the sale of U.S. assets were composed of $5.1 million from the sale of the California gas wells to Samedan Oil Corporation in the third quarter of 1993, and additional proceeds received in the first quarter of 1993 of $1.1 million relating to the 1992 disposition of U.S. assets to Dreyfus.
Proceeds from the disposition of U.S. assets to Dreyfus, excluding post effective date revenues retained and offset against the purchase price, were $97.1 million in 1992. Additional 1992 divestiture proceeds of $7.8 million were received primarily as a result of the sale of some smaller U.S. properties. Also, $7.5 million was received during the second quarter of 1992 from the sale of the Company's interest in NGC.
CASH FLOWS FROM FINANCING ACTIVITIES ------------------------------------
Cash flows from financing activities resulted in an inflow of $1.6 million in 1994 compared with outflows of $13.0 million and $99.6 million for 1993 and 1992, respectively.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
CASH FLOWS FROM FINANCING ACTIVITIES (CONTINUED) ------------------------------------------------
Net short-term and long-term borrowings under the Canadian revolving term credit facility increased in 1994 by $5.0 million over the year. The Company repaid $1.8 million of its revolving term credit facility during the first quarter of 1994, and drew down $14.3 million in the second and third quarters to fund the Company's increased capital spending and repurchases of stock. With the sale of the Claresholm property (see Note C ``Disposition of Assets'' in the Notes to the Financial Statements), the Company repaid $7.5 million in the 1994 fourth quarter.
Discretionary cash outflows for the 1995 calendar year are anticipated to equal or exceed cash flow from operating activities, therefore, the Company does not intend to make any repayments on the revolving term credit facility during 1995. Accordingly, the revolving term credit facility has been reclassified to long-term debt at December 31, 1994 for financial statement purposes (see Note G, ``Debt'' in the Notes to the Consolidated Financial Statements with respect to repayment requirements). There was no change in the Company's long-term publicly held note balances during 1994.
As announced in 1989, the Company's Board of Directors authorized the purchase of up to one million shares of the Company's Class A Stock or Class B (nonvoting) Stock. On July 27, 1994, the Board passed a resolution to authorize the repurchase from time to time, of up to one million shares of Class A Stock and/or Class B (nonvoting) Stock. This resolution replaced and is in lieu of any authority to repurchase stock granted in any prior resolution. A total of 220,000 shares were purchased during the second and third quarters of 1994 at an average price of $15.39, 77,500 of which were purchased subsequent to the July 27, 1994 resolution.
In 1993, the Company repurchased $18.4 million of its publicly held notes ($1.9 million of its 9 7/8 % notes and $16.5 million of its 10% notes) and 7,191 shares of its common stock. The Company also borrowed $5.7 million under its revolving term credit facility in December 1993.
During 1992, the Company used proceeds from asset sales to pay down a net $99.3 million in debt and repurchased $55.3 million of its publicly held notes ($43.9 million of its 9 7/8% notes and $11.4 million of its 10% notes). The Company also repaid its line of credit in full, representing a net $42.0 million reduction during 1992, and repaid other debt totalling $2.0 million. In addition, the Company repurchased 31,365 shares of its stock in the open market for $0.3 million during 1992.
LIQUIDITY ---------
The Company plans to fund its capital expenditures, working capital needs and interest payments through its operating cash flow and a combination of term debt and the revolving term credit facility. At December 31, 1994, the Company had $15.0 million in cash and short-term investments, and $11.2 million available under its Canadian revolving term credit facility (see Note F to the Consolidated Financial Statements).
PROSPECTIVE AND OTHER INFORMATION ---------------------------------
On December 21, 1994, the Company announced it had entered into a merger agreement with Houston-based Apache Corporation (``Apache``), whereby the outstanding shares of DEKALB Class A Stock and Class B (nonvoting) Stock will be converted into Apache Common Stock at a conversion rate as specified in the agreement. The Board of Directors is recommending approval and adoption of the merger, which is expected to be considered at a Special Meeting of the shareholders in the second quarter of 1995. Reference is made to the Form S-4 Registration Statement filed by Apache with the Securities and Exchange Commission on January 17, 1995 (Registration No. 33-57321).
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
PROSPECTIVE AND OTHER INFORMATION (CONTINUED) ---------------------------------------------
Given its successful drilling program and capital spending for 1994, the Company has more than replaced 1994 production of about 4,400 MBOE's. Deliverability at December 31, 1994 was 67 million cubic feet per day net working interest after royalty compared to 57 million cubic feet per day at December 31, 1993. The Company plans to maintain an active exploration, development and acquisitions program. Capital expenditures for the first half of 1995 are budgeted to be approximately $14 million.
The Company announced in November 1994 its intention to repurchase $22.1 million of its 10% public notes in the second quarter of 1995, at which time they will be callable at par. The Company is currently reviewing this option in light of increasing interest rates in both the U.S. and Canada. If this option is pursued, the repurchase will be funded through the Company's operating cash flow, cash reserves, and revolving term credit facility.
On April 12, 1994 the Company's Class B (nonvoting) Stock began trading on the Toronto Stock Exchange in addition to the NASDAQ/NMS. The additional listing is in recognition of the Company's focus on its Canadian asset base, and is intended to increase the Company's profile among Canadian analysts and attract additional Canadian investors.
Other Future Uncertainties --------------------------
The prices obtained for the sale of oil and natural gas have a significant impact on the Company's future earnings and cash flows. The Company sells its gas on the spot market and under short and long-term contracts. A majority of gas contracts do not have fixed prices; therefore, gas prices are subject to volatility depending on fluctuations in the gas market. Oil prices generally follow worldwide oil prices, which are subject to fluctuations resulting from world supply and demand. Oil and gas prices also affect the estimated present value of the Company's reserves, which is a component of the quarterly full cost ceiling test. Spot market prices for natural gas decreased significantly in the fourth quarter of 1994, and have continued to deteriorate subsequent to year end. An impairment of the Company's capitalized costs would not be required using current prices. However, should natural gas prices continue to decline from current levels, the Company could be required to record a non-cash writedown of its oil and gas properties during 1995. To protect against exposure to future price fluctuations, the Company has entered into hedge contacts for a portion of its oil and gas production.
The Company's future oil and gas production is dependent in part on the replacement of production with new reserves and its ability to market its deliverable quantities of production. The Company plans to concentrate on exploring for additional gas reserves and developing shut-in gas properties where economically feasible. The Company will also continue to pursue oil prospects where there is potential for significant reserve additions and immediate opportunities for development. In marketing its reserves, the Company plans to continue to increase geographical diversity within the customer portfolio, targeting, in particular, California and the U.S. Pacific Northwest markets. In addition, the Company intends to continue to shift more natural gas production into direct sales contracts, which generally are one year in length. 1995 production volumes are expected to more than equal 1994 volumes.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
AUDITORS' REPORT
To the Shareholders and Board of Directors of DEKALB Energy Company:
We have audited the consolidated balance sheets of DEKALB Energy Company as at December 31, 1994 and 1993, and the consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These consolidated 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 whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the consolidated financial position of DEKALB Energy Company as at December 31, 1994 and 1993, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in accordance with United States generally accepted accounting principles.
COOPERS & LYBRAND ----------------- Calgary, Alberta Coopers & Lybrand February 13, 1995
RESPONSIBILITIES FOR FINANCIAL STATEMENTS
The financial statements on the following pages for the years ended December 31, 1994, 1993, and 1992 were prepared by management in accordance with generally accepted accounting principles appropriate in the circumstances.
The integrity and objectivity of data in these financial statements and related financial data are the responsibility of management. The financial statements are presented on the accrual basis of accounting and, accordingly, include some amounts based on judgments of management. Management maintains what it believes to be an adequate system of internal accounting controls. More fundamentally, the Company seeks to ensure objectivity and integrity of its accounts by its selection of qualified personnel, by organizational arrangements that provide an appropriate division of responsibility, and by communicating its policies and standards throughout the organization.
DEKALB Energy Company has engaged Coopers & Lybrand, Chartered Accountants, to audit these financial statements. Their report is included herein which advises that the audit was conducted in accordance with generally accepted auditing standards. Those standards require that they plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. They include examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. They also include assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
The Board of Directors pursues its responsibility for these financial statements through its Audit Committee composed of outside directors. Coopers & Lybrand has full and free access to the Audit Committee and has met with it to discuss auditing and financial reporting matters.
DONALD MCMORLAND JOHN LETETA ---------------- ----------- Donald McMorland John Leteta President Vice President, Finance and Treasurer
EDDY Y. TSE ----------- Eddy Y. Tse Chief Accounting Officer
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Accounting Policies and Procedures
(1) Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions between consolidated companies have been eliminated.
(2) Statement of Cash Flows
The Company classifies highly liquid investments with original maturities of three months or less as cash and cash equivalents. Cash equivalents are stated at cost which approximates market. The cash flows from contracts that have been accounted for as hedges have been classified as cash flows from operating activities.
(3) Oil and Gas Properties
The Company uses the full cost method of accounting, under which the cost of all exploration and development activities (both successful and unsuccessful) is capitalized and subsequently amortized to expense using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related capitalized interest costs are excluded from the amortization base until the properties associated with these costs are evaluated and determined to be productive or impaired. Should the net evaluated capitalized costs (net of deferred income taxes) exceed the estimated after- tax present value of oil and gas reserves and unimpaired value of unevaluated properties on a country-by-country basis, the excess would be charged to expense. Included in the estimated present value are Canadian provincial tax credits expected to be realized beyond the date at which the legislation, under its provisions, could be repealed. To date, the Canadian provincial government has given no intention to repeal this legislation (see Supplementary Financial Information). Proceeds from disposals of oil and gas properties are applied as reductions of capitalized costs. Gains or losses are only recognized on the sale of oil and gas properties involving significant amounts of reserves.
(4) Future Removal and Site Restoration Costs
Estimated dismantlement, abandonment and clean-up costs, net of estimated salvage values, if any, are expensed on the unit-of- production basis using proved oil and gas reserves.
(5) Other Property, Plant and Equipment
It is the policy of the Company to capitalize expenditures for major renewals and betterments at cost and to charge to operating expenses the cost of current maintenance and repairs. Provisions for depreciation have been computed principally on the straight- line method based on expected useful lives. Rates used for depreciation are based principally on the following expected lives: Equipment - 2 to 10 years; Other - 20 years; and Leasehold improvements - term of lease.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A. Accounting Policies and Procedures (Continued)
The cost and accumulated allowances for depreciation and amortization relating to assets retired or otherwise disposed of are eliminated from the respective accounts at the time of disposition. The resultant gain or loss is included in current operating results.
(6) Income Taxes
Effective January 1, 1993, the Company adopted the liability method of accounting for income taxes under Statement of Financial Accounting Standard (SFAS) No. 109. The adoption of SFAS No. 109 resulted in a one time benefit adjustment of $5.3 million in the first quarter of 1993. No taxes have been accrued on the unremitted earnings of the Canadian subsidiary as these are intended to be permanently invested in Canada. The amount of the unrecognized deferred tax liability has not been calculated as its determination is not practicable.
Prior to 1993, income taxes were calculated in accordance with Accounting Principles Board Opinion No. 11. Investment tax credits were recognized using the flow through method whereby current income tax expense was reduced by investment tax credits utilized.
(7) Foreign Currency Translation
The Company's reporting currency is U.S. dollars. The functional currency for the Canadian subsidiary is Canadian dollars. Translation adjustments resulting from translating foreign currency financial statements into U.S. dollar equivalents are reported separately and accumulated in a separate component of shareholders' equity. Aggregate exchange gains and losses arising from the translation of foreign currency transactions, excluding long-term intercompany debt, are included in income.
(8) Earnings Per Share Calculation
Earnings (loss) per share is calculated by dividing the earnings (loss) by the weighted average shares outstanding during each year. The 1992 computation of weighted average shares outstanding excludes anti-dilutive shares.
(9) Gas Balancing
The Company uses the sales method to account for gas imbalances. The Company did not have any significant gas imbalances outstanding at December 31, 1993 or 1994.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A. Accounting Policies and Procedures (Continued)
(10) Concentration of Credit Risk
Substantially all of the Company's receivables are within the oil and gas industry. Although diversified within many companies, collectibility is dependent upon the general economic conditions of the industry. Beginning in December 1992, the Company has invested excess cash in high-grade securities through a U.S. investment firm in New York City, and in term deposits with a Canadian chartered bank.
(11) Hedge Contracts
The Company enters into various contracts to hedge a portion of its oil and gas production against fluctuating prices. The results of these contracts are included in revenues as the oil or gas is produced.
(12) Financial Statement Presentation
Certain prior year figures have been reclassified to conform to the 1994 financial statement presentation.
B. Plan of Merger
On December 21, 1994, the Company announced it had entered into a merger agreement with Houston-based Apache Corporation (``Apache''), whereby the outstanding shares of DEKALB Class A Stock and Class B (nonvoting) Stock will be converted into Apache Common Stock at a conversion rate as specified in the agreement. The Board of Directors is recommending approval and adoption of the merger, which is expected to be considered at a Special Meeting of the shareholders in the second quarter of 1995. Apache has filed a Form S-4 Registration Statement with the Securities and Exchange Commission on January 17, 1995 (Registration No. 33-57321).
For the year ended December 31, 1994, $0.5 million of merger costs incurred to year end were expensed in the Consolidated Financial Statements. If the merger proceeds, various additional restructuring costs associated with the merger will be expensed as incurred.
C. Disposition of Assets
In November 1994, the Company announced the sale of its interest in a gas plant, leasehold and other tangible property in the Claresholm area in the Province of Alberta, Canada. The sale was effective November 1, 1994 for proceeds of $9.0 million. During the third quarter of 1994, the Company sold its interest in leasehold and tangible property in the Buick Creek area of the Province of British Columbia, Canada for proceeds of $0.4 million. In March 1994, the Company disposed of its interest in leasehold and tangible property in the Rigel area of the Province of British Columbia, Canada for proceeds of $3.6 million. In accordance with the full cost method of accounting, the proceeds received for the 1994 dispositions were credited to the full cost pool; therefore, no gains or losses were recorded on the sales.
On August 5, 1993, the Company announced the sale of all its California gas wells to Samedan Oil Corporation for $5.1 million, effective July 1, 1993. Consistent with the full cost method of accounting on a cost center basis, the Company recorded a $0.5 million pre-tax and after-tax gain on the disposition of the California gas wells in the third quarter of 1993. The Company also closed down its exploration office in Bakersfield. The only U.S. assets retained by the Company after this sale are a working interest in a single non-operated oil well in California and acreage adjacent thereto.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
C. Disposition of Assets (Continued)
Sales revenues and volumes, lease operating expenses, and depreciation, depletion and amortization (DD&A) for the 1993 divested California properties were as follows:
On July 9, 1992, the Company announced that it had entered into a definitive agreement to sell substantially all of its U.S. oil and gas properties to Louis Dreyfus Gas Holdings Inc. (``Dreyfus''). On October 16, 1992, the Dreyfus transaction was approved by the shareholders at a special shareholders' meeting and the closing of the transaction was completed on the same day. The Company did not sell its California properties. The Company received $104 million of gross proceeds from the sale, which included approximately $6.0 million of cash flow from the properties from the effective date (July 1, 1992). In addition, Dreyfus assumed certain liabilities. A pre-tax loss of $34.9 million ($32.3 million after-tax) was recorded on the sale in 1992.
Sales revenues and volumes, lease operating expenses, and DD&A for the 1992 divested properties were as follows:
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
D. Non-Operating Items ($ in thousands)
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
E. Income and Other Taxes ($ in thousands)
Effective January 1, 1993, the Company adopted the liability method of accounting for income taxes under Statement of Financial Accounting Standards (SFAS) No. 109. Prior to 1993, deferred income taxes were calculated in accordance with Accounting Principles Board Opinion No. 11. The adoption of SFAS 109 resulted in a one time benefit adjustment of $5.3 million which was recognized in the first quarter of 1993.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
E. Income and Other Taxes (Continued) ($ in thousands)
Income and other taxes for continuing operations was a provision of $6,029 in 1994, $5,995 in 1993 and a benefit of $9,788 in 1992. Deferred tax expense (benefit) results from the following types of differences in the timing of the recognition of revenues and expense for tax and financial statement purposes.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
E. Income and Other Taxes (Continued) ($ in thousands)
Total tax provisions (benefits) resulted in effective tax rates differing from that of the statutory income tax rates. The reasons for these differences are:
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
E. Income and Other Taxes (Continued) ($ in thousands)
The components of the net deferred tax liabilities under SFAS No. 109 are as follows:
The Company has recorded a valuation allowance for all U.S. federal tax operating loss carryforwards and U.S. future deductible amounts net of future taxable income amounts under SFAS No. 109 since the Company has limited future taxable income in the United States to realize these benefits.
For U.S. tax purposes there are approximately $31.4 million in tax operating loss carryforwards remaining as at December 31, 1994. These losses, if not utilized, will expire in 2007. Investment tax credits of approximately $1.4 million are available to offset U.S. income taxes payable after December 31, 1994. If not utilized, these credits will expire by 2003.
For Canadian tax purposes there are approximately $.5 million of investment tax credits available to offset Canadian federal income taxes payable after December 31, 1994. If not utilized, these credits will begin to expire in 1995 through to 2002.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
G. Debt ($ in thousands)
(1) Term Debt
Aggregate maturities on the term debt for the years ending December 31, 1995 through 1998 and thereafter, are as follows:
On or after April 15, 1995, the Company will be permitted to redeem in full the $22.1 million outstanding of 10% long-term publicly held notes, at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. If this option is pursued, the proceeds for redemption of these notes will come from existing cash of approximately $ 15 million, operating cash flow and additional financing from the revolving term credit facility described below.
The term debt agreements contain restrictions on the disposition of assets of the Company and limitations on the amount of sale and leaseback transactions. These restrictions are not expected to affect the pending merger with Apache Corporation (see Note B, ``Plan of Merger'' in the Notes to the Consolidated Financial Statements).
In 1992, upon receipt of the proceeds from the disposition of the U.S. assets, the Company repurchased $55.3 million of its publicly held notes. An additional $18.4 million was purchased during 1993.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
G. Debt (Continued)
(2) Revolving Term Credit Facility
Effective November 19, 1992, DEKALB Energy Canada Ltd. (``DECL'') entered into a revolving term credit facility with the Royal Bank of Canada (the ``Lender``), which allows borrowings of up to $30.0 million Canadian funds or the equivalent amount in U.S. funds. DECL may borrow in Canadian dollars at Canadian prime (8.0% at December 31, 1994), in U.S. dollars at U.S. prime (8.50% at December 31, 1994) plus one-eighth of one percent or under a number of other financing alternatives. Commitment fees are paid on the unused portion of the commitment to the extent it exceeds $10.0 million Canadian dollars. This agreement replaced DECL's $13 million Canadian funds facility. The weighted average interest rate was 6.69%, 5.50% and 7.54% for the years ending December 31, 1994, 1993 and 1992, respectively.
At December 31, 1994, DECL had $14.3 million Canadian funds ($10.2 million U.S.) outstanding under this revolving term credit facility. The facility is guaranteed by DEKALB Energy Company. The current term of the facility is up for renewal on June 30, 1995, at which time the Company expects a twelve month extension, subject to the annual review of the Lender. However, if the term is not extended by the Lender, the commitment will be reduced to the amount of the borrowings then outstanding or two-thirds of DECL's reserve value, whichever is less. DECL is then required to pay down the commitment in 20 quarterly installments. The first installment is due six months after the cancellation date. The Company intends to repay the outstanding line of credit using internally generated cash. However, as discretionary cash outflows for the 1995 calendar year are expected to approximately equal or exceed the Company's cash flow from operating activities, the Company does not intend to make any repayments during 1995. Accordingly, the revolving term credit facility has been reclassified to long-term debt for financial statement purposes.
Under the terms of the revolving term credit facility, the Company may not enter into an amalgamation of any type without the prior written consent of the Lender. Such consent may not be reasonably withheld and is expected to be obtained in normal course with respect to the pending merger with Apache Corporation (see Note B, ``Plan of Merger'' in the Notes to the Consolidated Financial Statements).
The revolving term credit facility contains a debt to equity covenant for DECL during the term of the agreement, and a cash flow covenant during the repayment period after the termination of the facility. DECL must notify the Lender when various adverse events occur. The Lender, at its discretion, may require DECL to collateralize certain of its properties.
At December 31, 1994, the Company had no collateralized oil and gas properties.
In 1992, upon receipt of the proceeds from the disposition of U.S. assets, the Company repaid its U.S. line of credit.
H. Commitments and Contingencies and Off-Balance Sheet Risks
Commitments and Contingencies
(1) The Company and its subsidiaries are defendants in various legal actions arising in the course of their current and discontinued business activities. In the opinion of management, these actions will not result in a material effect on the consolidated financial position, results of operations, or liquidity of the Company.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
H. Commitments and Contingencies and Off-Balance Sheet Risks (Continued)
(2) At December 31, 1994, the Company had various offsetting tax matters pending relating to the Canadian operations which have not been provided for in the financial statements. In the opinion of management the net impact of these matters will not have a material effect on the consolidated financial position, the results of operations, or liquidity of the Company, and will be provided for in the financial statements if required upon resolution of each item.
(3) The Company has noncancellable agreements with terms ranging from 1 to 10 years to lease office space and equipment, and for terms ranging from 15 to 30 years for pipeline transportation capacity. Minimum payments due under the terms of the agreements are as follows:
Rental expense for operating leases for the years ended December 31, 1994, 1993, and 1992 was $347,000, $370,000 and $1,054,000 respectively.
(4) The Company maintains a voluntary retirement plan for its employees requiring the Company to contribute certain amounts each year to the plan (see Note K, ``Defined Contribution Plans''in the Notes to the Consolidated Financial Statements).
Off-Balance Sheet Risks
At December 31, 1994, the Company had in its name, stand-by letters of credit in the amount of $0.3 million, which covered 15 months of pipeline demand charges from Alberta Natural Gas Co. Ltd.
Commodity Price Hedge Contracts
The Company has from time to time entered into various commodity derivative contracts contracts to protect against fluctuations in prices for natural gas and crude oil. In 1994, the Company used swap contracts to hedge approximately 24% of its gross gas production and 13% of its gross oil production at prices averaging $2.22 per MCF and $18.71 per barrel, respectively. Gains of approximately $1.5 million have been included in operating revenues for the year.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
H. Commitments and Contingencies and Off-Balance Sheet Risks (Continued)
Commodity Price Hedge Contracts (Continued)
The Company has entered into NYMEX based swap contracts with a third party for the 1995 fiscal year as follows:
Unrealized profits on these contracts at year end based upon prices in effect at December 30, 1994 were approximately $1.9 million.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
H. Commitments and Contingencies and Off-Balance Sheet Risks (Continued)
Commodity Price Hedge Contracts (Continued)
The swap contracts are conducted with a major financial institution which the Company believes presents a minimal credit risk. The Company is exposed to potential market risk should commodity prices increase beyond the prices that have been hedged, or should differential spreads decrease below what has been hedged. Basis differential swap contracts are implemented to guarantee a price spread between NYMEX market prices and a desired point. This has the effect of fixing transportation costs related to the sale of a commodity to ensure a netback price at a specific sales location.
I. Capital Stock and Incentive Plans
Class A Stock and Class B (Nonvoting) Stock
The holders of Class A Stock and Class B (nonvoting) Stock have the same rights in all respects, including rights with respect to dividends and other distributions, except that (i) the holders of Class B (nonvoting) Stock have no voting rights other than as required by the Delaware General Corporation Law, (ii) the holders of Class A Stock may exchange, at their election, any of their shares for an equal number of shares of Class B (nonvoting) Stock on a continuing basis and (iii) the Board of Directors of the Company may distribute (1) voting stock of subsidiaries of the Company to the holders of Class A Stock of the Company and (2) non-voting stock of subsidiaries of the Company to the holders of Class B (nonvoting) Stock of the Company.
Preferred Stock
The Company has 500,000 shares of $1 par value preferred stock authorized and unissued.
Incentive Plans
In 1990, the Company adopted a Long-Term Incentive Plan ( the ``Plan'') which provides for the awarding, from time to time, of stock options, restricted stock, stock appreciation rights (SARs), performance awards and stock indemnification rights (SIRs). The Compensation Committee of the Board may make awards of SARs, SIRs, restricted stock, performance awards, or stock options to certain officers and other key employees of the Company. Stock options may be granted at no less than fair market value of the Company's stock at the date of grant and are exercisable within periods specified by the Compensation Committee. The Plan replaced an Incentive Stock Option Plan and a non-qualified stock option plan. All stock options granted prior to December 31,1990, were granted under these latter two plans and continue in effect, but no new stock options may be awarded under these plans. At December 31, 1994, 252,395 shares of Class A Stock subject to options and 7,050 shares of Class B (nonvoting) Stock subject to options were exercisable under the Plan. The Company had 646 shares available for future grants either as Class A or Class B shares, under the Plan at December 31, 1994.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
I. Capital Stock and Incentive Plans (Continued)
Certain current and former officers of the Company were participants in a Phantom Stock Plan. The Phantom Stock Plan expired in November of 1992. The Company paid $.5 million to the remaining participants.
Subsequent to the expiration of the previous Phantom Stock Plan, the Company granted 77,380 phantom units exercisable in 1993 at $16.00 per unit, to certain former officers of the Company. All of the new phantom units were exercised in 1993, resulting in a $.1 million payment. This payment had been accrued as part of the loss on the sale of the U.S. assets in 1992.
In 1994, the Company granted 20,000 phantom units to officers of the Company exercisable beginning in 1994 at a price range of $14.00 to $15.25 per unit. At December 31, 1994, none of these units had been exercised.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
J. Pension Plans
Prior to the sale of the U.S. assets in 1992, the Company's U.S. employees participated in a noncontributory pension plan which was designed to provide benefits based on such employees' career earnings. As part of the sale of the U.S. assets, this plan was terminated, and assets were distributed.
The Company maintains a noncontributory pension plan covering certain management employees which is not funded. Benefits are based on each participant's years of service, final average compensation (in the U.S.), or average of three highest paid years (in Canada) and estimated benefits received from certain other plans. At December 31, 1993, the U.S. did not have any active employees in the plan. Eight previous U.S. employees continue to receive benefits under the plan. The 1994 interest cost of $153,000 associated with the U.S. employees was accumulated as part of the loss on the sale of U.S. assets in 1992 and therefore did not result in an expense in 1994.
Total pension expense for the years ended December 31, 1994, 1993, and 1992, was $159,000, $85,000 and $2,134,000, respectively.
The components of total pension expense are as follows ($ in thousands):
Actuarial assumptions for 1994 and 1993 are as follows:
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
J. Pension Plans (Continued)
A reconciliation of accrued pension liability, included in other long-term liabilities on the financial statements, is as follows ($ in thousands):
K. Defined Contribution Plans
Prior to the sale of the U.S. assets in 1992, the Company's U.S. employees participated in a voluntary thrift plan which provided that the Company contribute a minimum of $.50 for every dollar contributed by employees up to 6% of their salaries. Additional discretionary amounts could have been contributed when warranted by results of operations. Company contributions charged to expense under this plan were $243,000 for the year ended December 31, 1992.
Following the sale of the U.S. assets in 1992, this plan was discontinued and the assets were distributed to the individuals. The remaining U.S. eligible employees participated in a voluntary thrift plan with the same basic design as the previous plan; however, it contained an aged based contribution in addition to the $.50 match and the additional discretionary payments. Following the 1993 sale of assets in California, this plan is no longer active. During 1994 the Company distributed the assets of this plan to its members. Company contributions charged to expense under this plan were $15,000 and $38,000 for the years ended December 31, 1994 and 1993, respectively.
The Company's Canadian employees participate in a voluntary retirement plan established in 1991. The Company contributes not less than 1% and not greater than 5.5% of the salary for each employee who participates in the plan, regardless of the employees' contribution to the plan. In addition, the Company contributes a minimum of $.50 for every dollar contributed by employees up to 3% of their salaries. Additional discretionary amounts may also be contributed when warranted by results of operations. Company contributions charged to expense under this plan were $403,000, $507,000, and $375,000 for the years ended December 31, 1994, 1993, and 1992, respectively.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
L. Operations by Geographic Area
Information on the Company's continuing operations by geographic area for the year ended December 31, 1992 is shown below. U.S. operations have been combined with Canada for 1994 and 1993 due to the immateriality of the U.S. operations in relation to the Company's operations as a whole. Operating earnings from continuing operations are total revenues less operating expenses of the geographic area, excluding interest and general corporate items.
In 1994, two Canadian customers each accounted for 11% of the Company's sales. In 1993, the Company had three Canadian customers who accounted for 18%, 16% and 11% of sales, respectively. In 1992, the Company had one Canadian customer who accounted for 11% of sales.
M. Discontinued Operations
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
M. Discontinued Operations (Continued)
Other
The Company sold the stock of its commodities brokerage business in 1986 and Lindsay Manufacturing Co. in 1989. The 1992 losses resulted from changes in estimated future expenses related to the above transactions. As a result of the Company's cumulative loss position in the U.S., no tax benefit was recognized for the losses.
N. Oil and Gas Disclosures
Capitalized costs at December 31, 1994 (all relating to assets located in Canada) which have been excluded from the amortization base as prescribed by the Securities and Exchange Commission Financial Reporting Release No. 14 are as follows:
The properties associated with the above excluded costs are being evaluated in the normal course of the Company's exploration activities. While it is not possible to determine the exact period in which these costs will be transferred to the amortization base, it is estimated that the majority will be included within five years after the costs were incurred.
Any material impairment to the properties associated with the excluded costs will be moved to the full cost amortization base.
O. Disclosures About Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash and Cash Equivalents
The carrying amount approximates the fair value due to the short term maturity of these instruments.
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
O. Disclosures About Fair Value of Financial Instruments (Continued)
Long-Term Debt
The fair value of the Company's publicly held notes at December 31, 1994 is estimated to be $51.0 million, or $0.3 million under stated book value, based upon estimates provided to the Company by independent sources. The fair value of the Company's revolving term credit facility approximates the carrying amount.
P. Postemployment Benefits
In November 1992, the Financial Accounting Standards Board introduced Statement No. 112, ``Employer's Accounting for Postemployment Benefits'' effective for fiscal years beginning after December 15, 1993. No provision for any future obligation has been made by the Company for postemployment benefits arising from the proposed merger with Apache (see Note B,``Plan of Merger '') as the amounts, if any, cannot be reasonably estimated. Other estimated postemployment benefits are not material.
Q. Future Removal and Site Restoration Costs
At December 31, 1994, the Company estimated future removal and site restoration costs to be $6.8 million ($1.0 million present value). These costs are included in DD&A expense using the unit- of-production method based on proved oil and gas reserves. The Company charged $0.4 million in 1994, $0.6 million in 1993 and $0.6 million in 1992.
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES As of or for the year ended December 31, 1994, 1993, and 1992 ($ in millions*)
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
The following table sets forth the changes in the Standardized Measure of Discounted Future Cash Flow relating to Proved Oil and Gas Reserves ($ in millions)
CAPITALIZED COSTS RELATED TO OIL AND GAS PROPERTIES ($ in thousands)
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
The following quarterly items are all pre-tax amounts:
The quarters ended March 31 and June 30, 1993 include Canadian and California operations. All 1994 results and the quarters ended September 30 and December 31, 1993 include Canadian operations and the remaining California well subsequent to the sale of the California gas assets effective July 1, 1993. A pre-tax and after-tax gain of $0.5 million was recognized in income in the third quarter of 1993 in connection with the sale. The first quarter of 1993 also includes a one time benefit adjustment of $5.3 million as a result of the Company's adoption of Financial Accounting Standard No. 109 ``Accounting for Income Taxes ''as of January 1, 1993.
For further discussion, see Management's Discussion and Analysis of Financial Condition and Results of Operations.
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
Information about Executive Officers is shown under the heading Executive Officers of the Registrant, in Item 4 of this filing.
There are four directors whose terms of office expire in 1995 and two directors whose terms of office will expire in 1997. Each has served continuously as a director of the Company since the date indicated beside the particular director's name. Also set forth below is the principal employment during the past five years of the directors.
Name and Principal Occupation Age Director Since Directors Whose Terms Expire in 1995:
Bruce P. Bickner 51 May 5, 1979 Mr. Bickner is Chairman of the Board of Directors. He was Chairman of the Board and Chief Executive Officer until January 1992 when he was also elected President. He relinquished the positions of President and Chief Executive Officer in November 1992. He has been Chairman, Chief Executive Officer and a Director of DEKALB Genetics Corporation for the past five years, as well as a director of Castle Bancgroup, Inc. He is a member of the Executive Committee of the Company.
H. Blair White 67 March 9, 1967 Mr. White is a senior partner in the law firm of Sidley & Austin. He is a Director of DEKALB Genetics Corpor- ation, R.R. Donnelley & Sons Company and Kimberly- Clark Corporation. Mr. White is Chairman of the Compensation Committee and an alternate member of the Executive Committee of the Company.
Donald McMorland 67 April 26, 1989 Mr. McMorland was elected President and Vice Chairman of the Board on May 13, 1994. He was Chairman of the Board of Alberta & Southern Gas Co. Ltd. from October 1, 1991 until June 30, 1994. He was Executive Vice President and Chief Operating Officer of that company until he was elected President and Chief Executive Officer in July 1990. He resigned as President and Chief Executive Officer in October 1993. He was also Senior Vice President and a director of Alberta Natural Gas Company Ltd. until he resigned as an officer in April 1991 and as a director in December 1991.
Director Whose Term Expires in 1995 (Class of 1996):
Thomas H. Roberts, Jr. (1) 70 January 5, 1951 Mr. Roberts is Vice Chairman of the Executive Committee of the Board of Directors. He is a director of IMC Global, Inc. and Pride Petroleum Services, Inc. Mr. Roberts is a member of the Executive Committee and Chairman of the Audit Committee of the Company.
Directors Whose Terms Expire in 1997:
Charles C. Roberts (1) 70 September 7,1957 Mr. Roberts is Chairman of the Executive Committee of the Board of Directors. He is also a member of the Compensation Committee of the Company.
William J. Wooten 70 April 26, 1989 Mr. Wooten was president of the Moran Corporation until June 1987, at which time he became a petroleum consultant. He is a member of the Compensation and Audit Committees of the Company.
(1) Thomas H. Roberts, Jr. and Charles C. Roberts are brothers-in-law.
COMPLIANCE WITH SECTION 16 OF THE EXCHANGE ACT
Section 16 (a) of the Securities Exchange Act of 1934 requires the Company's officers, directors and persons who own more than ten percent of a registered class of the Company's equity securities (``Reporting Persons'') to file reports of ownership and changes in ownership with the SEC. Reporting persons are required by SEC regulation to furnish the Company with copies of all Section 16 (a) reports they file. Based solely on its review of copies of such forms received by it, the Company believes that during 1994 its Reporting Persons complied with all Section 16 (a) reporting requirements applicable to them, except that Mr. Leteta inadvertently filed late his Form 3 Initial Statement of Beneficial Ownership of Securities.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
The following table sets forth the annual and long term compensation paid by the Company and its subsidiaries for the years indicated to those persons set forth below:
SUMMARY COMPENSATION TABLE (1)
(1) Where applicable, Canadian dollars were translated into U.S. dollars at the 1992, 1993 and 1994 average exchange rates of .8278, .7748 and .7319, respectively, which were the rates used for the Company's income statements during those years.
(2) Mr. Craig was hired in November 1992.
(3) Mr. Tkachyk left the Company's employ on May 13, 1994.
(4) Mr. McMorland was appointed President and Vice Chairman of the Board on May 13, 1994.
(5) Mr. Finnegan passed away on September 17, 1994.
(6) 1994 All Other Compensation total of $211,150 consists of termination payments of $203,286 and $7,864 credited to the Supplementary Retirement Plan.
(7) 1994 All Other Compensation is a $10,352 contribution to the Supplemental Retirement Plan.
(8) 1994 All Other Compensation is a $16,031 contribution to Supplementary Retirement Plan.
(9) 1994 All Other Compensation is a $6,518 contribution to the Supplementary Retirement Plan.
(10) 1994 All Other Compensation total of $17,204 consists of: $6,138 contribution to the Canadian Registered Retirement Savings Plan; and $11,066 credited to the Supplementary Retirement Plan.
OPTION/SAR GRANTS DURING 1994
AGGREGATED OPTION/SAR EXERCISES IN 1994 AND DECEMBER 31, 1994 OPTION/SAR VALUE
If the proposed merger with Apache referred to in Item 7 is consummated, Apache will assume each outstanding Company stock option that remains unexercised. In addition, each holder of a Company stock option, including those named in the above table, may elect, prior to the effectiveness of such merger, to surrender their Company stock options, in whole or in part, without regard to whether such options are then fully exercisable, in exchange for shares of Apache Common Stock. The treatment of Company stock options in connection with the proposed merger with Apache is more fully described in the Proxy/Statement Prospectus included in the Registration Statement on Form S-4 (Registration No. 33-57321) filed by Apache with the Securities and Exchange Commission under the Securities Act of 1933, as amended, with respect to the Merger.
ESTIMATED ANNUAL RETIREMENT BENEFITS FOR YEARS OF SERVICE INDICATED
The following table shows the estimated annual retirement benefits payable upon retirement to participants in the Company's retirement plans for the indicated levels of remuneration and years of service.
The defined benefit plan for named executives is based upon the average annual compensation of the three highest paid years. The compensation covered by the plan is salary and bonus. Such amounts for each of the named executive officers are set forth in the summary compensation table.
The credited years of service for each of the named executive officers is:
The benefits in the plan are calculated by determining the annualized earnings of the three highest paid years and multiplying this by the number of years of service times two percent. This benefit would be offset by the Canada Pension Plan benefits, the Canadian Old Age Security Plan benefits, and benefits associated with employer contributions to a Registered Retirement Savings Plan and Supplementary Retirement Plan. The latter two plans are defined contribution plans. The benefit table assumes that the participant will retire at age 65. If not, the benefit will be reduced by three percent for every year between ages 55 and 60 and one percent between ages 60 and 65.
EMPLOYMENT AGREEMENTS
Messrs. Nash, Craig, and Evans do not have written employment agreements with the Company. However, the Company has agreed with them that their 1995 base salaries shall be $92,300, $90,900 and $93,000, respectively. They have performance-related bonus opportunities which could be as high as $32,400, $27,300, and $28,100, respectively.
On May 13, 1994 Mr. McMorland was appointed Vice Chairman of the Board and President of the Company. His compensation is covered under a consulting contract dated June 1, 1994. This contract may be terminated by either party upon one month's prior written notice. The Company is committed to pay a monthly minimum fee of $6,000.00 plus $640 per day in excess of 28 days during any fiscal quarter. In addition, the Company covers all of Mr. McMorland's direct business expenses. In addition, in May 1994 Mr. McMorland was granted 10,000 phantom units, which are Stock Appreciation Rights, at $14.00 per unit. These units were 100% vested on November 18, 1994.
Each individual is paid in Canadian dollars. Amounts shown in this paragraph are in U.S. dollars calculated by converting Canadian dollars to U.S. dollars at $0.71.
COMPENSATION OF DIRECTORS
Except as noted herein, directors of the Company are paid $13,000 annually, plus $1,000 per day for attending meetings of the Board of Directors. Directors are paid $800 for attending meetings of committees of the Board of Directors, or for attending other meetings at the request of the Company, plus expenses for attending such meetings. Bruce P. Bickner, Chairman of the Board, in lieu of being paid the fees referenced above, will be paid $70,000 for his additional duties as Chairman.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
Mr. Charles C. Roberts was a member of the Compensation Committee of the Board of Directors during 1994 and was an officer of the Company. He held the office of Chairman of the Executive Committee during 1994. The only compensation he received in such capacity was the compensation normally paid to members of the Board of Directors. During his employment by the Company prior to his retirement in March 1988, Charles C. Roberts held various officer positions, including Vice Chairman of the Board.
H. Blair White, a Director of the Company, is a partner in the law firm of Sidley & Austin. Sidley & Austin provided legal services to the Company during the past year.
Donald McMorland was an officer of Alberta and Southern Gas Co. Ltd. ("A&S") until he resigned in October 1993. Mr. McMorland remained as Chairman of the Board of A&S until June 30, 1994. As of November 1, 1993, A&S had essentially ceased its gas marketing function in Canada. A&S is wholly-owned by Pacific Gas and Electric Company ("PG&E"). Pacific Gas Transmission Company ("PGT") is wholly-owned by PG&E. The Company entered into a 30- year firm transportation agreement with PGT beginning November 1, 1993. The agreement provides that PGT will transport gas for the Company from the Canadian border to Kern River, California. Yearly payments to PGT are expected to be approximately $2.0 million. In 1994 the Company paid PGT $2.2 million. DEKALB paid PG&E $0.5 MILLION IN 1994 for short-term transportation within California.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth as of December 31, 1994 the beneficial ownership of the Class A Stock and the Class B (nonvoting) Stock of the Company (including shares as to which a right to acquire ownership exists (e.g., through the exercise of stock options) within the meaning of Rule 13d-3 (d)(1) under the Securities Exchange Act) of each director, of the six executive officers named in the various compensation tables, and of all directors and all executive officers as a group:
(1) Unless otherwise noted, the named individual has sole voting and investment power with respect to the shares of Class A Stock and sole investment power with respect to the shares of Class B (nonvoting) Stock listed. The Securities and Exchange Commission defines "beneficial owner of a security" as including any person who has sole or shared voting or investment power with respect to such security.
(2) Includes 54,810 shares of Class A Stock subject to an option at an exercise price of $12.25 per share; 38,140 shares of Class A Stock subject to an option at an exercise price of $8.53 per share; and 7,050 shares of Class B (nonvoting) Stock subject to an option at an exercise price of $7.39 per share, all of which may be exercised within 60 days after December 31, 1994.
(3) Includes 3,000 shares of Class A Stock subject to an option at an exercise price of $11.50 per share and 5,417 shares of Class A Stock subject to an option at an exercise price of $14.00 per share which may be exercised within 60 days after December 31, 1994.
(4) Includes 6,773 shares of Class A Stock subject to an option at an exercise price of $12.25 per share; 7,058 shares of Class A Stock subject to an option at an exercise price of $14.00 per share; 2,500 shares of Class A Stock subject to an option at an exercise price of $22.25 per share; 1,500 shares of Class A Stock subject to an option at an exercise price of $20.00 per share; and 3,929 shares of Class A Stock subject to an option at an exercise price of $13.00 per share, all of which may be exercised within 60 days after December 31, 1994.
(5) Includes 10,345 shares of Class A Stock subject to an option at an exercise price of $12.25 per share; 500 shares of Class A Stock subject to an option at an exercise price of $2.096 per share; 1,200 shares of Class A Stock subject to an option at an exercise price of $22.25 per share; 1,500 shares of Class A Stock subject to an option at an exercise price of $20.00 per share; and 7,681 shares of Class A Stock subject to an option at an exercise price of $13.00 per share; 17,490 shares of Class A Stock subject to an option at an exercise price of $14.00 per share, all of which may be exercised within 60 days after December 31, 1994.
(6)Includes 7,900 shares of Class A Stock subject to an option at an exercise price of $12.25 per share; 4,255 shares of Class A Stock subject to an option at an exercise price of $14.00 per share; 500 shares of Class A Stock subject to an option at an exercise price of $2.096 per share; 2,500 shares of Class A Stock subject to an option at an exercise price of $19.125 per share; 1,900 shares of Class A Stock subject to an option at an exercise price of $20.00 per share; and 6,671 shares of Class A Stock subject to an option at an exercise price of $13.00, all of which may be exercised within 60 days after December 31, 1994.
(7) Charles C. Roberts has shared voting and investment power (with Mary R. Roberts) with respect to 42,168 shares of Class A Stock and shared investment power (with Mary R. Roberts) with respect to 625 shares of Class B (nonvoting) Stock. Includes 18,100 shares of Class A Stock subject to an option at an exercise price of $8.53 per share that may be exercised within 60 days after December 31, 1994. As of December 31, 1994, Charles C. Roberts, his spouse and their descendants and their spouses, and trusts created for their benefit, owned an aggregate of (excluding shares subject to option) 872,454 shares (37.911%) of the Company's then outstanding Class A Stock.
(8) Thomas H. Roberts, Jr. and Charles C. Roberts are brothers- in-law.
(9) Thomas H. Roberts, Jr. has sole voting and investment power with respect to 164,011 shares of Class A Stock, sole investment power with respect to 67,603 shares of Class B (nonvoting) Stock, shared voting and investment power (with Michael J. Roberts) with respect to 25,920 shares of Class A Stock. Includes 23,300 shares of Class A Stock subject to an option at $8.53 per share that may be exercised within 60 days after December 31, 1994. As of December 31, 1994, Thomas H. Roberts, Jr. and his descendants and their spouses, and trusts created for their benefit, owned an aggregate of (excluding shares subject to option) 748,954 shares (32.544%) of the Company's then outstanding Class A Stock. Not included in these shares are 123,500 shares of Class A Stock as to which Catherine H. Roberts-Suskin (the daughter of Mr. Roberts) has disclaimed beneficial ownership. See note (4) on Page 64.
(10) Includes shares reported on the last Form 4 filed by Mr. Tkachyk prior to the date of his termination of employment.
(11) Included in these shares are 260,659 shares of Class A Stock and 7,050 shares of Class B (nonvoting) Stock subject to options that may be exercised within 60 days after December 31, 1994.
PRINCIPAL STOCKHOLDERS
The following table sets forth as of December 31, 1994 the beneficial ownership of the Company's Class A Stock of each person known by the Company to own beneficially more than 5% of such class of securities. Included are shares of Class A Stock subject to an option which may be exercised within 60 days after December 31, 1994.
(1) The Securities and Exchange Commission defines "beneficial owner of a security" as including any person who has sole or shared voting or investment power with respect to such security.
(2) Thomas H. Roberts, Jr. is the father of Thomas H. Roberts, III and the uncle of Douglas C. Roberts, John T. Roberts and Virginia Roberts Holt. Douglas C. Roberts, Virginia Roberts Holt and John T. Roberts are brothers and sister and are the cousins of Thomas H. Roberts, III.
(3) Includes 23,300 shares of DEKALB Class A Stock subject to an option at $8.53 per share.
(4) Based on a Schedule 13D filed with the Securities and Exchange Commission. Such Schedule indicates that Amy L. Domini and William B. Perkins beneficially own such shares as co-trustees of trusts which hold such shares and that the grantors, beneficiaries, and in certain cases, the co- trustees of such trusts include Catherine H. Roberts-Suskin and Susan Shawn Roberts. Such Schedule 13D indicates that Catherine H. Roberts-Suskin also beneficially owns 60,256 of such shares as co-trustee of certain of such trusts and may be deemed to beneficially own an additional 123,500 of such shares solely by virtue of her power to remove and replace the trustees of one of those trusts, but that she disclaims beneficial ownership of such 123,500 shares. See note (10) on page 62.
(5) Douglas C. Roberts has sole voting and investment power with respect to 179,152 of such shares of Class A Stock and Lynne K. Roberts has sole voting and investment power with respect to the remaining 98,824 shares of Class A Stock. Douglas C. Roberts and Lynne K. Roberts are husband and wife.
(6) Virginia Roberts Holt has sole voting and investment power with respect to 101,053 of such shares of Class A Stock and Terrance K. Holt has sole voting and investment power with respect to the remaining 176,584 shares of Class A Stock. Virginia Roberts Holt and Terrance K. Holt are husband and wife.
(7) John T. Roberts has sole voting and investment power with respect to 131,180 of such shares of Class A Stock and Robin R. Roberts has sole voting and investment power with respect to the remaining 143,493 shares of Class A Stock. John T. Roberts and Robin R. Roberts are husband and wife.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Item 11, ``COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION'', with respect to Mr. White and Mr. McMorland.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) Financial Statements
Financial statements and schedules other than those listed are omitted for the reason that they are not required, are not applicable, or that equivalent information has been included in the financial statements or notes thereto.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (3) Exhibits
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (3) Exhibits (continued)
Footnotes: ----------
(1) Incorporated by reference to Exhibit to Amendment No. 1 to Form 10-K for the fiscal year ended August 31, 1986, dated May 19, 1987.
(2) Incorporated by reference to Exhibit to Form 10-K for the fiscal year ended December 31, 1988, dated March 13, 1989.
(3) Incorporated by reference to Exhibit 4 A to Registration Statement on Form S-3 (Registration No. 33 - 12534).
(4) Incorporated by reference to Exhibit to Form 10-Q for the quarter ended March 31, 1990, dated May 11, 1990.
(5) Incorporated by reference to Exhibit to Form 10-K for the fiscal year ended December 31, 1991, dated March 11, 1992.
(6) Incorporated by reference to Exhibit to Form 8-K dated October 16, 1992.
(7) Incorporated by reference to Exhibit to Form 10-K for the fiscal year ended December 31, 1992 dated March 12, 1993.
(8) Incorporated by reference to Exhibit to Form 10-K for the fiscal year ended December 31, 1994, dated March 7, 1994.
(9) Incorporated by reference to Exhibit to Form 8-K dated December 21, 1994.
*Indicates management contracts, compensatory plans or arrangements.
(b) Reports on Form 8-K
A Form 8-K dated September 17, 1994 was filed detailing the filing requirement for Item 5 - the announcement of the death of Michael E. Finnegan, Executive Vice President and Chief Financial Officer of the Company.
A Form 8-K dated December 21, 1994 was filed detailing the filing requirement for Item 5 - Agreement and Plan of Merger entered into among Apache Corporation, XPX Acquisitions, Inc. (``Sub''), a wholly owned subsidiary of Apache, and the Company providing for the merger of the Sub into the Company in a transaction under Delaware Law by which the Company would become a wholly owned subsidiary of Apache; and Item 7 - Financial Statements and Exhibits related to the above transaction.
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.
DEKALB Energy Company
Date: March 7, 1995
By: DONALD MCMORLAND ---------------- Donald McMorland President
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 on this 7th day of March, 1995.
Signature Title --------- -----
JOHN LETETA Vice President Finance and ----------- Treasurer John Leteta
EDDY Y. TSE Chief Accounting Officer ----------- Eddy Y. Tse
DIRECTORS
BRUCE P. BICKNER THOMAS H. ROBERTS, JR. ---------------- ---------------------- Bruce P. Bickner Thomas H. Roberts, Jr.
DONALD MCMORLAND ---------------- -------------- Donald McMorland H. Blair White
CHARLES C. ROBERTS ------------------ ----------------- Charles C. Roberts William J. Wooten
AUDITORS' REPORT
To the Shareholders and Board of Directors of DEKALB Energy Company:
Our report on the consolidated financial statements of DEKALB Energy Company is included on page 22 of this Form 10-K. In connection with our audits of such financial statements, we have also audited the related financial statement schedule listed on page 65 of this Form 10-K.
In our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included herein.
Calgary, Alberta COOPERS & LYBRAND February 13, 1995 ----------------- Coopers & Lynrand
EXHIBIT 10.11 DEKALB ENERGY COMPANY TEMPORARY CONSULTING CONTRACT BETWEEN DEKALB ENERGY COMPANY AND DONALD MCMORLAND
THIS CONTRACT is entered into effective as of June 1, 1994, by and among DEKALB Energy Canada Ltd. and DEKALB Energy Company (collectively hereinafter called ``DEKALB''), on the one hand and McMorland Consulting Services Ltd. (hereinafter called the ``Consultant''), on the other hand, to provide consulting services (hereinafter called the ``Work'') upon the terms and conditions herein set forth:
1. SCOPE OF WORK -------------
(a) The Consultant shall provide the services of a senior consultant to DEKALB to perform such services as may be assigned to it by the Chairman of the Board of DEKALB or by the Board of Directors of DEKALB.
(b) The Consultant shall assign Donald McMorland to perform the Work. The Consultant shall not have the right to have the Work performed by an individual other than Donald McMorland. Therefore, this Contract shall immediately terminate if Donald McMorland dies, becomes disabled or is otherwise unable to perform his duties.
(c) Donald McMorland, in his individual capacity, shall hold the office and perform the duties of President of DEKALB and shall perform the all of his duties as such in accordance with applicable law, DEKALB's By-laws and the directives of the Chairman of the Board of DEKALB and the Board of Directors of DEKALB. Since DEKALB shall provide no employee compensation to Donald McMorland for performing that function, Consultant shall indemnify DEKALB. and hold DEKALB harmless from any claim for such compensation as an employee that might be made by Donald McMorland.
2. TERM ---- (a) Notwithstanding the date that this Contract is executed, it shall be in effect commencing June 1, 1994.
(b) The provisions respecting liability, indemnification, settlement of accounts, taxes and confidentiality and all obligations which have accrued hereunder prior to the date of termination of the Contract shall survive the termination of the Contract and shall remain enforceable thereafter.
(c) The parties hereby agree that each party shall have the right, in their absolute discretion, to terminate this Contract by providing the other party with one month's prior written notice.
(d) The parties further agree that when this Contract is terminated, with or without cause, DEKALB shall have no obligation to make any form of severance payment to Consultant.
3. REMUNERATION ------------ DEKALB shall pay the Consultant, as full and complete compensation for the Work, an amount equal to the fee set forth below.
The fee shall be determined on a per diem basis subject to a monthly minimum fee of $8,400 per month, exclusive of the Goods and Services Tax (``GST'').
EXHIBIT 10.11 DEKALB ENERGY COMPANY TEMPORARY CONSULTING CONTRACT BETWEEN DEKALB ENERGY COMPANY AND DONALD MCMORLAND (Continued)
In the event the Consultant is required to provide services in excess of twenty-eight (28) days duration during any fiscal quarter, the Consultant shall be compensated for each full day in excess of the twenty-eight (28) day threshold at the rate of $900 per day or $450 per half day.
All amounts quoted herein are quoted in Canadian funds and shall be payable in Canadian funds.
4. EXPENSES -------- (a) Subject to Subclauses (b) and (c), below, the Consultant shall also be entitled to receive reimbursement for all reasonable expenses incurred in the performance of the Work, including reasonable health and travel insurance coverages, provided, however, that, where reasonably possible, such expenses shall first be approved by DEKALB.
(b) All travel undertaken by the Consultant on behalf of DEKALB shall conform to the travel policies, standards and practices established by DEKALB from time to time.
(c) The expenses reimbursed to the Consultant shall be exclusive of any GST paid by the Consultant if the Consultant is a goods and services tax registrant. In such a case, the Consultant shall identify separately as a part of the invoice any GST that the Consultant is required to collect in respect to the Consultant's charges for reimbursable expenses.
5. INVOICING AND PAYMENT --------------------- (a) Every month the Consultant shall invoice DEKALB for the total amount payable as determined in Clause 3 and Clause 4, above. The invoice shall provide an arithmetic calculation of fees payable and a detailed list of expenses, including receipts and allocation of GST as stipulated.
The invoice, in duplicate, shall be submitted to:
DEKALB Energy Canada Ltd. 700 - 9th Avenue S.W. Calgary, Alberta T2P 3V4 Attn: Michael E. Finnegan
(b) Subject to its right to hold back amounts owing as set forth in Clause 6, DEKALB shall use all reasonable efforts to pay each invoice within forty-five (45) days of its receipt. DEKALB shall have the right to question the propriety of any charge made in an invoice for a period of one (1) year following termination of this Contract, notwithstanding payment of the invoice.
6. HOLDBACK -------- DEKALB shall be entitled to withhold payment to the Consultant for any portion of the invoice which it disputes.
EXHIBIT 10.11 DEKALB ENERGY COMPANY TEMPORARY CONSULTING CONTRACT BETWEEN DEKALB ENERGY COMPANY AND DONALD MCMORLAND (Continued)
7. CONFIDENTIALITY AND OWNERSHIP OF WORK ------------------------------------- (a) All pertinent resources, information, material and papers prepared or provided by the Consultant in pursuance of this Contract shall be the sole property of DEKALB or its affiliates.
(b) The Consultant shall maintain in the strictest confidence all information made available or acquired from DEKALB or its affiliates, for the performance of the Work and all information resulting from the performance of the Work, and shall use such information only in the performance of the work.
8. LIABILITY AND INDEMNIFICATION -----------------------------
(a) The Consultant shall be indemnified by DEKALB in accordance with the applicable provisions of the Restated Certificate of Incorporation of DEKALB Energy Company.
(b) Donald McMorland, in his capacity as an officer of DEKALB shall be indemnified in accordance with the applicable provisions of the Restated Certificate of Incorporation of DEKALB Energy Company and in accordance with the Indemnification Agreement dated April 26, 1989 signed by him.
9. Taxes -----
(a) The Consultant shall pay and be responsible for income and payroll taxes (except such taxes specifically assessed against DEKALB or its affiliates) and other taxes of a similar or dissimilar nature.
(b) DEKALB shall have no obligation to pay Goods and Services Tax on invoices submitted pursuant to Clause 5 unless the Consultant provides identification of its Goods and Services Tax Registration Number on the respective invoice and identifies the total amount of Goods and Services Tax included in the invoice.
10. COMPLIANCE WITH LAWS AND POLICIES --------------------------------- (a) In performing the Work, the Consultant, and its employees, shall comply with all the DEKALB policies and all applicable laws, ordinances, codes and regulations of all jurisdictions having or asserting jurisdiction in respect of the Work. If unfamiliar with DEKALB's policies, the Consultant shall request, review and abide by all pertinent DEKALB policies, including but not limited to, the code of business conduct and policy on travel arrangements.
(b) The Consultant's breach of any material provision of this Contract shall, at DEKALB's discretion, be deemed to constitute cause for immediate termination of this Contract.
EXHIBIT 10.11 DEKALB ENERGY COMPANY TEMPORARY CONSULTING CONTRACT BETWEEN DEKALB ENERGY COMPANY AND DONALD MCMORLAND (Continued)
11. APPLICABLE LAW --------------
(a) The validity and interpretation of this Contract and the legal relation of the parties shall be governed by the laws in force from time to time in the Province of Alberta.
(b) The Courts of the Province of Alberta and Canada shall have exclusive jurisdiction to determine all matters in dispute hereunder and the parties hereby attorn to the jurisdiction of such Courts.
12. INDEPENDENT CONTRACTOR ----------------------
In furnishing its services hereunder, the Consultant shall be acting as an independent contractor in relation to DEKALB and not as an employee of DEKALB. Accordingly, the Consultant shall have no authority to act for or on behalf of DEKALB or to bind DEKALB without its express written consent and shall not be considered as having employee status for the purpose of any employee benefit plan applicable to DEKALB's employees generally. It is understood by the parties that Consultant shall only devote a portion of its time to its services to DEKALB hereunder and remains free to perform services for others, whether as a consultant or otherwise; provided that, services shall not be provided to others if it would create a conflict of interest with Consultant's responsibilities to DEKALB or if it would result in the disclosure of DEKALB's Confidential Information.
13. MISCELLANEOUS -------------
(a) All notices or other communications required or permitted under this Contract shall be served in writing by personal service or registered mail, return receipt requested. Notice by mail shall be addressed to each party at the address set forth below.
(b) This Contract supersedes all other agreements previously made between the parties relating to the subject matter contained herein. No amendment, modification or termination of, or addition to, this Contract shall be valid unless and until executed in writing by the parties to this Contract.
(c) This Contract shall be binding upon and inure to the benefit of the parties hereto, including any of their successors and permitted assignees.
(d) This Contract may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.
(e) The parties hereto acknowledge that this Contract and the terms contained herein may be made public in accordance with the applicable securities laws.
EXHIBIT 10.11 DEKALB ENERGY COMPANY TEMPORARY CONSULTING CONTRACT BETWEEN DEKALB ENERGY COMPANY AND DONALD MCMORLAND (Continued)
IN WITNESS WHEREOF, the parties have executed this Contract effective as of the date set forth above.
DEKALB Energy Company McMorland Consulting 700 - 9th Avenue S.W. Services Ltd. Calgary, Alberta T2P 3V4 3440 Lakeside Crescent, S.W. Canada Calgary, Alberta T3E 6A6 Canada
BRUCE P. BICKNER DONALD MCMORLAND --------------------- ----------------- Bruce P. Bickner Donald McMorland Chairman of the Board President
DEKALB Energy Canada Ltd. 700 - 9th Avenue S.W. Calgary, Alberta T2P 3V4 Canada
BRUCE P. BICKNER --------------------- Bruce P. Bickner Chairman of the Board
EXHIBIT 10.12 DEKALB ENERGY COMPANY TEMPORARY CONSULTING CONTRACT BETWEEN DEKALB ENERGY COMPANY AND JOHN LETETA
(DEKALB Energy Company Letterhead)
November 28, 1994
John Leteta 4 Lake Lucerne Close SE Calgary, Alberta T2J 3H8
Dear John:
This letter will confirm our offer of temporary employment in the position of Vice President, Finance and Treasurer, effective September 20, 1994.
Your annual rate of compensation will be $150,000 (Cdn.) which will be payable semi-monthly. You will be paid 10% of the total compensation you receive as vacation pay on your final pay cheque. Your company benefits will remain unchanged from your retiree benefit status: extended medical insurance coverage for you and your spouse, and $50,000 basic life insurance. You will continue to be deducted once per month for current benefit premiums.
Either party may terminate this agreement on one month's notice.
Your employment will not reduce the benefits from the Retiring Allowance Agreement Plan and the Supplementary Retirement Plan.
If you are in agreement with this offer, please sign one copy of this letter in the space provided below and return it to me at your earliest convenience.
Yours truly, The above agreed to and accepted this 29 day of November, 1994
DONALD MCMORLAND JOHN LETETA ---------------- ----------- Donald McMorland John Leteta President
EXHIBIT 11 DEKALB Energy Company STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
EXHIBIT 21 SUBSIDIARIES OF DEKALB ENERGY COMPANY
The following table sets forth principal subsidiaries of the registrant and indicates as to each such subsidiary the state or other jurisdiction under the laws of which it was organized and the percentage of voting securities thereof owned by the registrant.
EXHIBIT 24.1 CONSENT OF AUDITORS
We consent to the incorporation by reference in the registration statement of DEKALB Energy Company on Form S-8, File Nos. 2-63440 (Post-Effective Amendment No. 6), No. 2-58358 (Post-Effective Amendment No. 1), No. 2-71978 (Post-Effective Amendment No. 1), and No. 33-36642 and Registration Statement No. 33-12534 (Amendment No. 3) on Form S-3 of our report dated February 13, 1995, on our audits of the consolidated financial statements and financial statement schedules of DEKALB Energy Company as of December 31, 1994 and 1993 and for each of the three years in the period ended December 31, 1994, which report is included in the Annual Report on Form 10-K.
Calgary, Alberta COOPERS & LYBRAND March 7, 1995 ----------------- Coopers & Lybrand
EXHIBIT 24.2 DEKALB ENERGY COMPANY CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
(Ryder Scott Letterhead)
We hereby consent to the reference to Ryder Scott Company under ``Supplemental Financial Information - Estimated Net Quantities of Proved Reserves'' of DEKALB Energy Company in this Form 10-K and to the inclusion of Ryder Scott Company's Report of Independent Petroleum Engineers as an Exhibit in this Form 10-K.
RYDER SCOTT COMPANY ------------------- PETROLEUM ENGINEERS
Ryder Scott Company Petroleum Engineers
Dated: February 15, 1995
EXHIBIT 28 DEKALB ENERGY COMPANY REPORT OF INDEPENDENT PETROLEUM ENGINEERS
(Ryder Scott Letterhead)
February 6, 1995
DEKALB Energy Canada Ltd. 700 - 9th Avenue S.W. Calgary, Alberta T2P 3V4
Gentlemen:
At your request, Ryder Scott Company Petroleum Engineers (Ryder Scott) has reviewed estimates of proved hydrocarbon liquid and gas reserves as of January 1, 1995 attributable to interests of DEKALB Energy Canada Ltd. (DEKALB) in certain wells or locations. In our opinion, the overall proved reserves for the reviewed properties as estimated by DEKALB are reasonable. The estimates of reserves reviewed by Ryder Scott were prepared by engineers and geologists on the staff of DEKALB. The wells or locations for which estimates of reserves were reviewed by Ryder Scott comprised approximately 83.9 percent of the total discounted future net income at 10 percent attributable to the total interests of DEKALB, according to economic forecasts supplied by DEKALB. The summary tables below present the estimated net remaining proved reserves as of January 1, 1995 prepared by the staff of DEKALB and reviewed by Ryder Scott for the total company. Hydrocarbon liquid volumes are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas where the gas reserves are located.
SEC CASE Estimated Net Remaining Proved Reserves Attributable to the Interests of DEKALB Energy Canada Ltd. As of January 1, 1995
The estimated quantities of reserves in this report are related to hydrocarbon prices. DEKALB has assured us that December 1994 hydrocarbon prices were used in the preparation of their projections as required by SEC guidelines; however, actual future prices may vary significantly from December 1994 prices. Therefore, quantities of reserves actually recovered may differ significantly from the estimated quantities presented in this report.
EXHIBIT 28 DEKALB ENERGY COMPANY REPORT OF INDEPENDENT PETROLEUM ENGINEERS (Continued)
Review Procedure and Opinion ----------------------------
In our opinion, DEKALB `s estimates of future reserves for the wells and locations reviewed by Ryder Scott were prepared in accordance with generally accepted procedures for the estimation of future reserves. In general, we were in acceptable agreement on an overall company net equivalent barrel basis (at 6 MCF per barrel) with the estimates prepared by DEKALB's staff.
Certain technical personnel of DEKALB are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. Ryder Scott consulted with these technical personnel and had access to their work papers and supporting data in the course of our review.
In performing our review, we relied upon data furnished by DEKALB with respect to property interests owned, production and well tests from examined wells, geological maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.
Reserve Estimates -----------------
In general, the reserves for the wells and locations reviewed by Ryder Scott were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such methods were more appropriate.
The estimates of reserves by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by the volumetric method in those cases where there was inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.
The reserves presented herein are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.
The proved reserves, which are attributable to the wells and locations reviewed by Ryder Scott, conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins and are based on the following definition criteria:
EXHIBIT 28 DEKALB ENERGY COMPANY REPORT OF INDEPENDENT PETROLEUM ENGINEERS (Continued)
Proved reserves of crude oil, condensate, natural gas, and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Reservoirs are considered proved if economic producibility is supported by actual production or formation tests. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by fluid contacts, if any, and (2) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data become available. Proved natural gas reserves are comprised of non-associated, associated, and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of natural gas liquids, for lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in significant quantities and are removed prior to sale. Reserves that can be produced economically through the application of improved recovery techniques are included in the proved classification when these qualifications are met: (1) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and (2) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including (1) pressure maintenance, (2) cycling, and (3) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. Estimates of proved reserves do not include crude oil, natural gas, or natural gas liquids being held in underground storage.
General -------
In general, the estimates of reserves for the wells and locations reviewed by Ryder Scott are based on data available through September 1994.
Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed by Ryder Scott.
Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
This report was prepared for the exclusive use of DEKALB. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
KENT A WILLIAMSON
Kent A. Williamson, P.E. Group Vice President