SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------------------------
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
_X__SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1994
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
____SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________to________
Commission file number: 0-2886
DEKALB Energy Company
(Exact name of registrant as specified in its charter)
Delaware 36-0987809
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
700-9th Avenue S.W.
Calgary, Alberta Canada T2P 3V4
(Address of principal executive offices) (Postal Code)
Registrant's telephone number, including area code: (403) 261-1200
Securities registered pursuant to Section 12 (b) of the Act: None
Securities registered pursuant to Section 12 (g) of the Act:
Title of each class
-------------------
Class A Stock, no par value
Class B (nonvoting) Stock, no par value
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K._______
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes __X__ No _____
As of February 28, 1995, 2,283,470 shares of the registrant's
Class A Stock and 7,102,755 shares of Class B (nonvoting) Stock
were outstanding and the aggregate market value of all voting
stock held by non-affiliates was $25,027,785 based upon the
closing price on the NASDAQ Over-the-Counter markets on the last
trading day of February. (The officers, directors and 10%
shareholders of the registrant are considered affiliates for
purposes of this calculation.)
DOCUMENTS INCORPORATED BY REFERENCE
Exhibit Index is located on pages 65 to 67 . Total number of
pages is 83 .
1
<PAGE>
DEKALB Energy Company
TABLE OF CONTENTS
Part I Page
------ ----
Item 1. Business............................................... 3
Item 2. Properites............................................. 5
Item 3. Legal Proceedings...................................... 7
Item 4. Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant .................. 8
Part II
-------
Item 5. Market for Registrant's Stock and Related Stockholders'
Matters .............................................. 10
Item 6. Selected Financial Data............................... 11
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 14
Item 8. Financial Statements and Supplementary Financial
Information........................................... 22
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................... 53
Part III
--------
Item 10. Directors and Executive Officers of the Registrant... 53
Item 11. Executive Compensation............................... 55
Item 12. Security Ownership of Certain Beneficial Owners and
Management........................................... 60
Item 13. Certain Relationships and Related Transactions....... 64
Part IV
-------
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K.............................. 65
Signatures .......................................... 68
2
<PAGE>
PART I
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
3
<PAGE>
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.
4
<PAGE>
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.
<TABLE>
Undeveloped Acreage (a) Developed Acreage
----------------------- -----------------
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----
<S> <C> <C> <C>
259,618 156,468 383,447 251,646
</TABLE>
(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.
<TABLE>
Oil Wells (1) Gas Wells (1)
------------- -------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C>
882 151 393 257
</TABLE>
(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.
5
<PAGE>
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:
<TABLE>
Net Productive Wells Drilled Net Dry Wells Drilled Net Total Wells Drilled
---------------------------- ----------------------------- ----------------------------
Exploratory Development Exploratory Development Exploratory Development
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
1994 (1) 13 28 7 2 20 30
----
1993 (1) 8 6 11 1 19 7
----
1992
----
Canada 2 1 3 2 5 3
United
States 1 3 1 3 2 6
----------- ----------- ----------- ----------- ----------- -----------
TOTAL 3 4 4 5 7 9
<FN>
As of December 31, 1994 DEKALB was participating in the
completion of 3 gross (1.2 net) wells in Canada. Subsequent to
year end, 1 of the wells resulted in an oil discovery and 2 of
the wells were declared dry and abandoned.
(1) 1993 U.S. well data is not significant and has been combined
with the Canadian well data. No U.S. wells were drilled in
1994.
</TABLE>
Sales
The following table summarizes DEKALB's net oil and gas sales for
the years ended December 31, 1994, 1993, and 1992:
<TABLE>
1994 1993 1992
---- ---- -------------------
(1) (1) Canada U.S.(2)
------ --------
<S> <C> <C> <C> <C>
Oil and Condensate (MBBLS) 731 742 776 633
Natural Gas Liquids (MBBLS) 231 247 220 132
Gas (MMCF) 20,492 20,969 17,309 6,671
<FN>
(1) 1994 and 1993 U.S. volumes are not significant and have been
combined with the Canadian volumes.
(2) 1992 includes six months of U.S. sales on divested
properties, and 12 months of California properties.
</TABLE>
6
<PAGE>
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:
<TABLE>
1994 1993 1992
---- ---- ------------------------
(1) (1) Canada U.S.
------ ------
<S> <C> <C> <C> <C>
Avg. price/bbl of oil and condensate* $ 15.52 $ 15.98 $ 18.37 $ 16.97
Avg. price/bbl of natural gas liquids $ 8.87 $ 9.82 $ 9.79 $ 11.00
Avg. price/MCF of natural gas * $ 1.53 $ 1.44 $ 1.16 $ 1.58
Lease operating expense/
equivalent bbl of oil $ 2.66 $ 2.78 $ 2.98 $ 3.85
<FN>
(1) 1994 and 1993 U.S. operating data is not significant and has
been combined with the Canadian data.
* Includes the effect of hedging contracts. Prices before the
effect of hedging were $15.43 for oil and condensate and $1.47
for natural gas in 1994. A hedging contract for natural gas
began in December 1993 and had no effect on 1993 prices. Oil
and condensate prices before the effect of hedging were $18.74
for Canada and $17.45 for the U.S. in 1992.
</TABLE>
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. 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.
7
<PAGE>
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.
8
<PAGE>
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.
9
<PAGE>
PART II
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.
<TABLE>
1st 2nd 3rd 4th
B. Stock Data (NASDAQ) Qtr. Qtr. Qtr. Qtr.
------------------- ---- ---- ---- ----
<S> <C> <C> <C> <C>
For the year ended
December 31, 1994
Market price range - Low 13.25 13.25 15.00 14.75
- High 18.50 15.50 16.50 21.50*
For the year ended
December 31, 1993
Market price range - Low 10.75 14.25 15.75 13.00
- High 15.00 18.75 17.25 17.375
<FN>
*On December 20, 1994, the NASDAQ closing price of the Class B
(nonvoting) Stock was $15.75. On December 21, 1994, the Company
announced it had entered into a merger agreement with Apache
Corporation; the Class B shares closed at $21.50 on this day.
</TABLE>
10
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
As of or for the year ended December 31,
1994 1993 1992 1991 1990
----------- ----------- ----------- ----------- -----------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Operations
Operating revenues
Oil and liquids sales $ 13,398 $ 14,291 $ 28,605 $ 51,231 $ 60,107
Natural gas sales 31,491 30,215 30,678 41,718 40,773
Other 1,401 1,397 1,450 1,743 2,023
----------- ----------- ----------- ----------- -----------
Total operating revenues 46,290 45,903 60,733 94,692 102,903
Operating expenses
Lease operations and
other direct charges 11,654 12,467 18,833 29,802 28,699
Depreciation, depletion
and amortization 14,603 15,142 22,522 41,080 39,933
Provision for impairment of
oil and gas properties - - 53,320 94,241 -
General and administrative 3,179 3,468 6,441 12,656 13,555
(Gain) loss on disposal of
U.S. assets - (513) 34,942 - -
----------- ----------- ----------- ----------- -----------
Operating income (loss) 16,854 15,339 (75,325) (83,087) 20,716
Non-operating expenses
(income) 4,012 3,672 3,716 4,652 (5,732)
Income and other taxes 6,029 5,995 (9,788) (25,153) 10,922
----------- ----------- ----------- ----------- -----------
Earnings (loss) from
continuing operations 6,813 5,672 (69,253) (62,586) 15,526
Earnings (loss) from
discontinued operations - - (1,050) - 11,633
Cumulative effect of change
in accounting principle - 5,334 - - -
----------- ----------- ----------- ----------- -----------
Net earnings (loss) $ 6,813 $ 11,006 $ (70,303) $ (62,586) $ 27,159
=========== =========== =========== =========== ===========
Returns
Return on sales (1) 14.72% 12.36% (114.03%) (66.1%) 15.1%
Return on assets (2) 3.24% 2.59% (16.29%) (11.3%) 3.8%
Return on equity (3) 6.77% 5.93% (37.56%) (24.9%) 6.4%
Financial Position
Working capital $ 9,688 $ 6,912 $ 11,020 $ (2,570) $ 2,680
Current ratio 1.62 1.28 1.58 0.92 1.06
Net property, plant
and equipment $ 185,382 $ 177,915 $ 182,130 $ 383,362 $ 500,848
Total assets $ 211,589 $ 210,174 $ 218,985 $ 425,031 $ 558,892
Net long-term debt $ 61,547 $ 51,325 $ 69,725 $ 167,407 $ 191,799
Shareholders' equity $ 96,831 $ 100,599 $ 95,587 $ 184,357 $ 251,251
Total debt as a % of
capitalization (4) 38.86% 36.16% 42.30% 47.90% 43.40%
Oil and gas capital
expenditures (9) $ 41,220 $ 19,461 $ 17,031 $ 34,157 $ 201,803
Standardized measure of
discounted future net
cash flows (pre-tax) $ 204,084 $ 266,979 $ 210,373 $ 325,561 $ 503,760
</TABLE>
11
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA (continued)
<TABLE>
OPERATING DATA
Average Prices
---------------------------------------------------------------------------------------
As of or for the year Oil & Condensate Natural Gas Liquids Natural Gas
ended December 31, ($ per barrel) (7) ($ per barrel) ($ per thousand cubic feet)
--------------------------- ---------------------------- ---------------------------
<S> <C> <C> <C>
1994 (10) 15.52 8.87 1.53 (12)
1993 (10) 15.98 9.82 1.44
1992
- Canada 18.37 9.79 1.16
- U.S. (10) 16.97 11.00 1.58
Total Company 17.74 10.26 1.28
1991
- Canada 19.97 10.45 1.22
- U.S. 18.97 12.54 1.67
Total Company 19.32 11.72 1.41
1990
- Canada 21.72 11.80 1.37
- U.S. 21.22 10.78 1.83
Total Company 21.38 11.37 1.57
</TABLE>
<TABLE>
Sales
-------------------------------------------------------------------------------------------------
Oil & Condensate Natural Gas Liquids Natural Gas Oil & Gas Equivalents
(thousands of barrels) (thousands of barrels) (million cubic feet) (thousands of barrels)(5)
---------------------- ---------------------- ---------------------- ----------------------
<S> <C> <C> <C> <C>
1994 (10) 731 231 20,492 4,377
1993 (10) 742 247 20,969 4,484
1992
- Canada 776 220 17,309 3,881
- U.S. (10) 633 132 6,671 1,877
---------------------- ---------------------- ---------------------- ----------------------
TOTAL 1,409 352 23,980 5,758
1991
- Canada 797 228 17,030 3,863
- U.S. 1,502 354 12,511 3,941
---------------------- ---------------------- ---------------------- ----------------------
TOTAL 2,299 582 29,541 7,804
1990
- Canada 835 214 14,626 3,487
- U.S. 1,780 155 11,354 3,827
---------------------- ---------------------- ---------------------- ----------------------
TOTAL 2,615 369 25,980 7,314
</TABLE>
<TABLE>
PROVED RESERVES
Oil, Condensate
& Natural Gas Liquids Natural Gas Oil & Gas Equivalents
(thousands of barrels) (million cubic feet) (thousands of barrels) (5)
---------------------- ---------------------- ----------------------
<S> <C> <C> <C>
1994 (11) 10,716 299,896 60,698
1993 (11) 13,234 277,411 59,469
1992
- Canada 13,984 271,825 59,288
- U.S. - 4,518 753
---------------------- ---------------------- ----------------------
TOTAL 13,984 276,343 60,041
1991
- Canada 14,384 280,730 61,172
- U.S. 11,693 80,464 25,104
---------------------- ---------------------- ----------------------
TOTAL 26,077 361,194 86,276
1990
- Canada 15,381 295,110 64,566
- U.S. 13,881 93,732 29,503
---------------------- ---------------------- ----------------------
TOTAL 29,262 388,842 94,069
</TABLE>
12
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA (continued)
<TABLE>
As of or for the year ended December 31,
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Data per Share
Book value per share (6) $ 10.32 $ 10.47 $ 9.95 $ 19.19 $ 25.72
Cash dividends declared $ - $ - $ - $ 0.08 $ 0.29
Weighted average shares
outstanding 9,583 9,675 9,630 9,618 10,351
Earnings (loss) from
continuing operations $ 0.71 $ 0.59 $ (7.19) $ (6.51) $ 1.50
Earnings (loss) from
discontinued operations - - (0.11) - 1.12
Cumulative effect of change
in accounting principle - 0.55 - - -
--------- --------- --------- --------- ---------
Net Earnings (loss) $ 0.71 $ 1.14 $ (7.30) $ (6.51) $ 2.62
========= ========= ========= ========= =========
</TABLE>
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 $1.47 for the combined
operations.
Reference is made to Management's Discussion and Analysis of
Financial Condition and Results of Operations and to the
Financial Statements and Supplementary Financial Information for
a discussion of the Company's operations and financial position.
13
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
<TABLE>
SUMMARY OF FINANCIAL DATA
-------------------------
For the years ended December 31,
($ in millions) 1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Revenues $ 46.3 $ 45.9 $ 60.7
Operating income
(loss) $ 16.9 $ 15.3 $(75.3)
Earnings (loss)
from continuing
operations $ 6.8 $ 5.7 $(69.3)
Loss from
discontinued
operations $ - $ - $ (1.1)
Cumulative effect of
change in accounting
principle $ - $ 5.3 $ -
Net earnings (loss) $ 6.8 $ 11.0 $(70.3)
Cash flows from
continuing operations $ 20.2 $ 31.5 $ 28.7
</TABLE>
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).
14
<PAGE>
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 ($32.3 million after-
tax).
Sales revenues and volumes, lease operating expenses and
depreciation, depletion and amortization (DD&A) associated with
the U.S. divested properties for the six months ended June 30,
1993 and 1992, are shown under Note C, Disposition of Assets in
the Notes to the Consolidated Financial Statements.
DRILLING ACTIVITY
-----------------
Consistent with its focus on long-term growth through exploration
and development, the Company participated in the drilling of 68
exploration and development wells (49.96 net wells) during 1994,
with a success rate of 78% (82% on a net well basis). Fifty-six
gas targets and twelve oil targets were drilled, primarily in the
Nevis and Kaybob areas of Alberta, and in northeast British
Columbia. Of particular significance was a successful 100%
Company-owned and operated well drilled in the first quarter on
the Hunter prospect in northeast British Columbia, where 26 feet
of gas pay in the Halfway zone was encountered, with an
established production test rate of 6.4 MMCF per day before
royalties at 375 psi flowing tubing pressure. The well is
expected to be tied in during the first half of 1995.
The Company participated in the drilling of 26 net wells in 1993
and 16 net wells in 1992.
15
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
OPERATING REVENUES
------------------
<TABLE>
Total Company Price and Sales Data (1)
--------------------------------------
For the years ended December 31,
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Oil and condensate price ($ per Bbl)* $15.52 $15.98 $17.74
Oil and condensate volumes (Mbbls) 731 742 1,409
Natural gas liquids price ($ per Bbl) $8.87 $9.82 $10.26
Natural gas liquids volumes (Mbbls) 231 247 352
Gas price ($ per Mcf)* $1.53 $1.44 $1.28
Gas volumes (Mcf) 20,492 20,969 23,980
<FN>
* Includes the effect of hedging contracts
(1)1993 includes price and sales data on the divested
California properties for 6 months, and 12 months of
data relating to Canada and the one remaining oil well
in California. 1992 includes 6 months of U.S. data
relating to divested properties, and 12 months of
Canadian and California data.
</TABLE>
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.
16
<PAGE>
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.
17
<PAGE>
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.
18
<PAGE>
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.
19
<PAGE>
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).
20
<PAGE>
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.
21
<PAGE>
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
22
<PAGE>
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
23
<PAGE>
<TABLE>
DEKALB Energy Company
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands, except per share amounts)
For the years ended December 31,
1994 1993 1992
--------- -------- ---------
<S> <C> <C> <C>
OPERATING REVENUES (Note H)
Oil and liquids sales $ 13,398 $ 14,291 $ 28,605
Natural gas sales 31,491 30,215 30,678
Other 1,401 1,397 1,450
--------- --------- ---------
Total operating revenues 46,290 45,903 60,733
OPERATING EXPENSES
Lease operations and other direct charges 11,654 12,467 18,833
Depreciation, depletion and amortization 14,603 15,142 22,522
Provision for impairment of oil and gas properties - - 53,320
General and administrative 3,179 3,468 6,441
(Gain) loss on disposal of U.S. assets (Note C) - (513) 34,942
--------- --------- ---------
Operating income (loss) 16,854 15,339 (75,325)
Interest expense, net (Note D) 4,047 3,795 6,938
Other income, net (Note D) (35) (123) (3,222)
--------- --------- ---------
Earnings (loss) from continuing operations before income
and other taxes 12,842 11,667 (79,041)
Income and other taxes (Note E) 6,029 5,995 (9,788)
Earnings (loss) from continuing operations 6,813 5,672 (69,253)
--------- --------- ---------
Loss from discontinued operations (net of applicable income
taxes) (Note M) - - (1,050)
Cumulative effect of change in accounting principle (Note E) - 5,334 -
--------- --------- ---------
NET EARNINGS (LOSS) $ 6,813 $ 11,006 $(70,303)
========= ========= =========
Earnings (loss) per share:
Earnings (loss) from continuing operations $ 0.71 $ 0.59 (7.19)
Loss from discontinued operations - - (0.11)
Cumulative effect of change in accounting principle - 0.55 -
--------- --------- ---------
NET EARNINGS (LOSS) PER SHARE $ 0.71 $ 1.14 $ (7.30)
========= ========= =========
Weighted average shares outstanding (in thousands) 9,583 9,675 9,630
<FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
24
<PAGE>
<TABLE>
DEKALB Energy Company
CONSOLIDATED BALANCE SHEETS
($ in thousands)
ASSETS
As of December 31,
1994 1993
------------ -----------
<S> <C> <C>
Current assets:
Cash and cash equivalents (Note O) $ 14,980 $ 22,664
Accounts receivable 9,509 7,874
Other current assets 928 866
------------ -----------
Total current assets 25,417 31,404
Other assets 790 855
Property, plant, and equipment:
Oil and gas assets, full cost method
Proved properties, being amortized 312,649 298,235
Unproved properties and properties under development,
not being amortized (Note N) 11,454 9,048
Other property and equipment 2,791 2,817
Less accumulated depreciation, depletion and amortization (141,512) (132,185)
------------ -----------
Net property, plant and equipment 185,382 177,915
------------ -----------
TOTAL ASSETS $ 211,589 $ 210,174
============ ===========
</TABLE>
<TABLE>
LIABILITIES AND SHAREHOLDER
<S> <C> <C>
Current liabilities:
Short-term borrowings (Note G) $ - $ 5,663
Accounts payable 11,820 13,868
Other current liabilities (Note F) 3,909 4,961
------------ -----------
Total current liabilities 15,729 24,492
Other liabilities 10,386 10,913
Deferred income taxes (Note E) 27,096 22,845
Long-term debt (Notes G and O) 61,547 51,325
------------ -----------
TOTAL LIABILITIES 114,758 109,575
------------ -----------
Commitments and contingencies (Note H)
Shareholders' equity (Note I):
Capital stock:
Class A; $.625 stated value; 6,000,000 shares
authorized; 2,381,106 shares issued at December 31, 1994;
2,418,000 shares issued at December 31, 1993 1,488 1,511
Class B (nonvoting); $.625 stated value; 13,000,000 shares
authorized; 11,297,377 shares issued at December 31, 1994;
11,260,483 shares issued at December 31, 1993 7,061 7,038
Capital in excess of stated value 51,657 51,657
Retained earnings 149,367 142,554
Currency translation adjustments (19,337) (12,141)
------------ -----------
190,236 190,619
Treasury shares, at cost (4,292,258 shares in 1994 and
4,072,258 shares in 1993) (93,405) (90,020)
TOTAL SHAREHOLDERS' EQUITY 96,831 100,599
------------ -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 211,589 $ 210,174
============ ===========
<FN>
The accompanying notes are an integral part of the financial statements
</TABLE>
25
<PAGE>
<TABLE>
DEKALB Energy Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in thousands)
CASH FLOWS from OPERATING ACTIVITIES For the years ended December 31,
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
Net earnings (loss) $ 6,813 $ 11,006 $ (69,253)
Adjustments to reconcile net earnings (loss) to net
cash flows from operating activities:
Depreciation, depletion and amortization 14,603 15,142 22,522
Provision for impairment of oil and gas properties - - 53,320
Provision (benefit) for deferred income taxes 5,554 5,226 (8,342)
Cumulative effect of change in accounting principle - (5,334) -
(Gain) loss on disposal of U.S. assets - (513) 34,942
Other 300 (86) (1,176)
---------- ---------- ----------
27,270 25,441 32,013
Changes in assets and liabilities:
Accounts receivable and other current assets (2,167) 949 12,017
Other assets 65 6,024 (4,553)
Accounts payable and other current liabilities (2,383) (1,311) (17,330)
Other liabilities (430) (1,251) 3,427
Current taxes payable - - 2,635
---------- ---------- ----------
Cash flows from continuing operations 22,355 29,852 28,209
---------- ---------- ----------
Cash flows from discontinued operations 70 840 480
---------- ---------- ----------
NET CASH FLOWS from OPERATING ACTIVITIES 22,425 30,692 28,689
---------- ---------- ----------
CASH FLOWS from INVESTING ACTIVITIES
Purchases of property, plant and equipment (43,027) (22,875) (25,106)
Proceeds from sale of property, plant and equipment 13,671 912 7,750
Proceeds from sale of U.S. assets - 6,175 97,181
Increase (decrease) in short-term payables for
purchases of property, plant and equipment (2,115) 1,685 443
Proceeds from sale of investments - - 7,500
---------- ---------- ----------
NET CASH FLOWS from INVESTING ACTIVITIES (31,471) (14,103) 87,768
---------- ---------- ----------
CASH FLOWS from FINANCING ACTIVITIES
Purchases of stock (3,385) (79) (328)
Proceeds from exercise of stock options - 1 79
Increase in long-term debt 10,479 - 35,000
Net increase (decrease) in short-term borrowings (5,478) 5,455 (1,631)
Payments made on long-term debt and net capital
lease changes - (18,400) (132,688)
NET CASH FLOWS from FINANCING ACTIVITIES 1,616 (13,023) (99,568)
---------- ---------- ----------
NET EFFECT of EXCHANGE RATES on CASH (254) 226 (134)
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents (7,684) 3,792 16,755
---------- ---------- ----------
Cash and cash equivalents, prior year 22,664 18,872 2,117
---------- ---------- ----------
CASH and CASH EQUIVALENTS, CURRENT YEAR $ 14,980 $ 22,664 $ 18,872
========== ========== ==========
Note: Cash paid during the period for:
Income and other taxes $ 614 $ 694 $ 713
Interest $ 5,764 $ 6,472 $ 9,708
Capitalized interest $ 1,146 $ 1,515 $ 2,961
<FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
26
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
Issued
------------------------------------
Class A Class B
(nonvoting) Capital
Stock Stock in Excess Currency Treasury Stock
----------------- ----------------- of Stated Retained Translation --------------------
Shares Amount Shares Amount Value Earnings Adjustments Shares Amount
-------- -------- -------- -------- --------- --------- ----------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1991 2,649 $1,655 11,027 $6,892 $52,377 $201,851 $12,016 (4,067) $(90,434)
Net Loss (70,303)
Exchange Class A for Class B (107) (67) 107 67
Exercise of Stock Options (665) 31 712
Treasury Shares Purchased (31) (328)
Translation Adjustment (18,241)
Other 2 2 53
-------- -------- -------- -------- --------- --------- ----------- -------- ---------
DECEMBER 31, 1992 2,544 $1,590 11,134 $6,959 $51,765 $131,548 $(6,225) (4,067) $(90,050)
Net Income 11,006
Exchange Class A for Class B (126) (79) 126 79
Exercise of Stock Options (108) 2 109
Treasury Shares Purchased (7) (79)
Translation Adjustment (5,916)
-------- -------- -------- -------- --------- --------- ----------- -------- ---------
DECEMBER 31, 1993 2,418 $1,511 11,260 $7,038 $51,657 $142,554 $(12,141) (4,072) $(90,020)
Net Income 6,813
Exchange Class A for Class B (37) (23) 37 23
Treasury Shares Purchased (220) (3,385)
Translation Adjustment (7,196)
-------- -------- -------- -------- --------- --------- ----------- -------- ---------
DECEMBER 31, 1994 2,381 $1,488 11,297 $7,061 $51,657 $149,367 $(19,337) (4,292) $(93,405)
<FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
27
<PAGE>
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.
28
<PAGE>
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.
29
<PAGE>
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 $0.5
million pre-tax and after-tax gain on the disposition of the
California gas wells in the third quarter of 1993. The Company
also closed down its exploration office in Bakersfield. The only
U.S. assets retained by the Company after this sale are a working
interest in a single non-operated oil well in California and
acreage adjacent thereto.
30
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
C. Disposition of Assets (Continued)
Sales revenues and volumes, lease operating expenses, and
depreciation, depletion and amortization (DD&A) for the 1993
divested California properties were as follows:
<TABLE>
Six Months Ended
($ in millions) June 30, 1993
----------------
<S> <C>
Revenue $1.6
Lease Operating Expense $0.3
DD&A $0.9
Sales Volumes
-------------
Natural Gas (MMCF) 850
</TABLE>
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 ($32.3 million after-tax) was recorded on the sale in
1992.
Sales revenues and volumes, lease operating expenses, and DD&A
for the 1992 divested properties were as follows:
<TABLE>
Six Months Ended
($ in millions) June 30, 1992
----------------
<S> <C>
Revenues $20.1
Lease Operating Expense $6.6
DD&A $8.3
Sales Volumes
-------------
Oil and Condensate (MBbls) 494
Natural Gas Liquids (MBbls) 125
Natural Gas (MMCF) 5,006
</TABLE>
31
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
D. Non-Operating Items ($ in thousands)
<TABLE>
(1) Interest Expense, Net For the years ended December 31,
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Interest expense* $ 4,692 $ 4,588 $ 7,456
Interest income (645) (793) (518)
-------- -------- ---------
Total interest expense, net $ 4,047 $ 3,795 $ 6,938
======== ======== =========
<FN>
*Interest of $1,145,000, $1,515,000, and $2,961,000 was
capitalized in 1994, 1993 and 1992, respectively. In 1992,
interest of $2,067,000 was charged to the loss on the sale of the
U.S. assets.
</TABLE>
<TABLE>
(2) Other Income, Net For the years ended December 31,
1994 1993 1992
------- --------- --------
<S> <C> <C> <C>
Gas contract and
transportation adjustments (201) (91) 300
Equity earnings - - (756)
Gain on sale of equity
investment - - (1,914)
Adjustment to prior accruals (211) - (960)
Merger costs* 537 - -
Gain on settlement of
litigation (514) - -
Foreign exchange (gains) losses 354 (66) 84
All other, net - 34 24
------- --------- --------
Total other income, net $ (35) $ (123) $(3,222)
======= ========= ========
<FN>
*See Note B, ``Plan of Merger'' in the Notes to the Consolidated
Financial Statements.
</TABLE>
32
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
E. Income and Other Taxes ($ 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.
<TABLE>
For the years ended December 31,
1994 1993 1992
---------- ---------- ---------
Income and other taxes by
jurisdiction are as follows:
<S> <C> <C> <C>
Current: ---------- ---------- ---------
Federal $ (140) $ 140 $ (4,786)
State 100 50 46
Foreign 515 579 3,293
---------- ---------- ---------
475 769 (1,447)
Deferred:
Federal - - 2,340
Foreign 5,554 5,226 (10,681)
---------- ---------- ---------
5,554 5,226 (8,341)
---------- ---------- ---------
Income and other taxes 6,029 5,995 (9,788)
---------- ---------- ---------
SFAS No. 109 adjustment - (5,334) -
---------- ---------- ---------
Total income and other taxes $ 6,029 $ 661 $ (9,788)
========== ========== =========
</TABLE>
33
<PAGE>
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.
<TABLE>
For the years ended De
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
Related to oil and gas operations
including depletion and
intangible drilling costs $ 5,475 $ 5,326 $ 4,534
Tax depreciation greater than
(less than) book depreciation - (412) (3,172)
Provision for impairment of
oil and gas properties - - (21,108)
Asset dispositions - (515) 1,135
Capitalized interest 459 515 475
Capitalized overhead - - 366
Deferred tax benefit not
realizable - - 2,340
Losses for which no U.S.
tax benefits were recorded - - 7,934
Other accruals (380) 312 (845)
Total timing differences --------- --------- ---------
from continuing operations $ 5,554 $ 5,226 $ (8,341)
========= ========= =========
</TABLE>
<TABLE>
For the years ended Decmber 31,
1994 1993 1992
---------- ---------- ----------
Income and other taxes is comprised of the following:
<S> <C> <C> <C>
Income taxes $ (140) $ 140 $ (2,096)
Capital and other taxes* 615 629 649
Deferred income taxes 5,554 5,226 (8,341)
---------- ---------- ----------
Total income and other taxes $ 6,029 $ 5,995 $ (9,788)
========== ========== ==========
<FN>
*Consists of Canadian Large Corporations Tax, franchise taxes and withholding taxes.
</TABLE>
34
<PAGE>
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:
<TABLE>
Percent of Pretax Earnings
For the years ended December 31,
1994 1993 1992
------ ------ ------
% % %
<S> <C> <C> <C>
Statutory rate* 44.3 44.3 (34.0)
Statutory deductions in excess
of accounting charges (1.9) (5.3) -
Tax refund limitation** 0.9 8.2 19.6
Other non-income tax 3.7 4.4 0.1
Other - (0.2) 1.9
------ ------ ------
Effective rate for
continuing operations 47.0 51.4 (12.4)
SFAS No. 109 adjustment - (45.7) -
------ ------ ------
47.0 5.7 (12.4)
====== ====== ======
<FN>
* 1994 and 1993 Canadian statutory rate; 1992 U.S. federal statutory rate
** Tax refund limitations result from losses for which no U.S. tax benefit has been recorded
</TABLE>
<TABLE>
Earnings (loss) from continuing
operations before inccome taxes
for the years ended December 31,
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
U.S. $ (253) $ (2,151) $ (59,707)
Canada 13,095 13,818 (19,334)
---------- ---------- ----------
Earnings (loss) from continuing
operations before taxes $ 12,842 $ 11,667 $ (79,041)
========== ========== ==========
</TABLE>
35
<PAGE>
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:
<TABLE>
For the years ended December 31,
Deferred Tax Assets: 1994 1993
----------- -----------
<S> <C> <C>
Current
Allowance for uncollectible
accounts receivable $ (30) $ (241)
Non-Current
Liabilities (2,717) (3,366)
Tax net operating loss
carryforward (10,665) (7,201)
Investment tax credits
carryforward (1,656) (1,539)
----------- -----------
Total deferred assets (15,068) (12,347)
Valuation allowance 13,460 10,954
----------- -----------
Net deferred tax assets (1,608) (1,393)
Deferred Tax Liabilities
Non-current oil &
gas properties 28,704 24,238
----------- -----------
Net deferred tax liability $ 27,096 $ 22,845
=========== ===========
</TABLE>
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 $.5 million of
investment tax credits available to offset Canadian federal
income taxes payable after December 31, 1994. If not utilized,
these credits will begin to expire in 1995 through to 2002.
36
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
F. Other Current Liabilities ($ in thousands)
As of December 31,
1994 1993
------ ------
<S> <C> <C>
Interest $1,772 $1,772
Compensation 410 371
Insurance reserves 541 1,285
Taxes 485 247
Liabilities on disposition of U.S. assets 541 718
Other 160 568
------ ------
Total other current liabilities $3,909 $4,961
====== ======
</TABLE>
G. Debt ($ in thousands)
<TABLE>
As of December 31,
1994 1993
-------- --------
<S> <C> <C>
Term debt (1):
Publicly held notes - 10.0%
interest, due in 1998 $22,100 $22,100
Publicly held notes - 9.875%
interest, due in 2000 29,225 29,225
Revolving term credit facility (2) 10,222 5,663
-------- --------
61,547 56,988
Less current maturities - 5,663
-------- --------
Net long-term debt $61,547 $51,325
======== ========
</TABLE>
(1) Term Debt
Aggregate maturities on the term debt for the years ending
December 31, 1995 through 1998 and thereafter, are as follows:
<TABLE>
1995 1996 1997 1998 1999 Thereafter
--------- -------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C>
$ - $ - $ - $22,100 $ - $29,225
</TABLE>
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.
37
<PAGE>
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.
38
<PAGE>
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:
<TABLE>
($ in thousands) 1995 1996 1997 1998 1999 Thereafter
------ ------ ------ ------ ------ ---------
<S> <C> <C> <C> <C> <C> <C>
Lease commitments $ 390 $ 381 $ 408 $ 399 $ 398 $ 131
Pipeline
commitments 3,905 3,092 3,013 2,835 2,816 55,157
------ ------ ------ ------ ------ ---------
Total $ 4,295 $ 3,473 $ 3,421 $ 3,234 $ 3,214 $ 55,288
====== ====== ====== ====== ====== =========
</TABLE>
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.
39
<PAGE>
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:
<TABLE>
Contracts entered into as at December 31, 1994:
Type of Hedge Period Terms Hedge Price
---------------------- ------ --------- -----------
<S> <C> <C> <C>
NYMEX crude oil price 12/94 Sell 200 $17.95
swap 05/95 bbls/day U.S./Bbl
NYMEX crude oil price 07/94 Sell 200 $19.18
swap 01/95 bbls/day U.S./Bbl
NYMEX/Empress gas 11/94 Sell 20 $0.56
differential swap 10/95 MMBTU/day U.S./MMBTU
NYMEX/Permian gas 09/94 Sell 12 $0.200
differential swap 02/95 MMBTU/day U.S./MMBTU
NYMEX gas price swap 03/95 Sell 10 $1.93
10/95 MMBTU/day U.S./MMBTU
NYMEX gas price swap 04/95 Sell 10 $1.9375
10/95 MMBTU/day U.S./MMBTU
</TABLE>
Unrealized profits on these contracts at year end based upon
prices in effect at December 30, 1994 were approximately $1.9
million.
<TABLE>
Contracts entered into subsequent to December 31, 1994:
Type of Hedge Period Terms Hedge Price
---------------------- ------ --------- -----------
<S> <C> <C> <C>
NYMEX crude oil price 01/95 Sell 200 $25.50
swap 07/95 bbls/day CDN./Bbl
(1)(2)
NYMEX crude oil price 01/95 Sell 200 $25.23
swap 12/95 bbls/day CDN./Bbl (2)
NYMEX crude oil price 03/95 Sell 400 $25.95
swap 08/95 bbls/day CDN./Bbl
(1)(2)
NYMEX/Empress gas 03/95 Buy 10 $0.800
differential swap 10/95 MMBTU/day U.S./MMBTU
<FN>
(1) These contracts have options, on behalf of the counterparty,
to extend the contracts for an additional six months.
Assuming all options were extended, the additional volumes of
oil could total 109,200 barrels.
(2) These contracts are priced in Canadian funds to provide for
additional protection against fluctuations in the exchange
rate between Canadian and U.S. dollars.
</TABLE>
40
<PAGE>
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.
41
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
I. Capital Stock and Incentive Plans (Continued)
<TABLE>
DEKALB Energy Company
CAPITAL STOCK AND INCENTIVE PLAN
Class Prices
------------------ --------------------------
A B A B
--------- ------- --------------- -----
<S> <C> <C> <C> <C>
Shares under option at December 31, 1991 298,245 7,050 $1.00 - $31.75 $7.39
Activity:
Granted 219,850 - $11.50 - $16.50 -
Cancelled (132,370) - $13.00 - $31.75 -
Reissued 13,875 - $13.00 - $16.00 -
Exercised (33,980) - $1.00 - $ 7.39 -
--------- ------- --------------- -----
Shares under option at December 31, 1992 365,620 7,050 $2.096 - $22.25 $7.39
--------- ------- --------------- -----
Activity:
Granted 103,725 - $12.25 - $16.75 -
Cancelled (154,037) - $12.25 - $22.25 -
Exercised (15,843) - $2.096 - $16.00 -
--------- ------- --------------- -----
Shares under option at December 31, 1993 299,465 7,050 $2.096 - $22.25 $7.39
--------- ------- --------------- -----
Activity:
Granted 194,870 - $14.00 - $15.50 -
Cancelled (58,952) - $13.75 - $22.25 -
Exercised - - - -
--------- ------- --------------- -----
Shares under option at December 31, 1994 435,383 7,050 $2.096 - $22.25 $ 7.39
========= ======= =============== =====
</TABLE>
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.
42
<PAGE>
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):
<TABLE>
For the years ended December 31,
1994 1993 1992
----- ----- -----
<S> <C> <C> <C>
Service cost - benefits earned during the year $ 26 $ 19 $ 256
Prior service cost 64 - -
Interest cost on projected benefit obligations 62 65 416
Net amortization and deferral 7 1 (19)
----- ----- -----
Total pension expense $ 159 $ 85 $ 653
===== ===== =====
</TABLE>
Actuarial assumptions for 1994 and 1993 are as follows:
<TABLE>
For the years ended December 31,
1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Discount rate 7.00% 7.00% 8.00%
Average salary growth rate 4.50% 4.50% 5.50%
</TABLE>
43
<PAGE>
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):
<TABLE>
Unfunded Plan
As of December 31,
1994 1993
---------- ----------
<S> <C> <C>
Actuarial present value of benefits
based on service to date and present pay levels:
Vested $ 2,919 $ 2,952
Nonvested - -
---------- ----------
Accumulated benefit obligation 2,919 2,952
Additional amounts related to projected pay increases 176 241
---------- ----------
Projected benefit obligation 3,095 3,193
Plan assets at fair value - -
Plan assets (less than) benefit obligation (3,095) (3,193)
Unrecognized (gain) loss from experience (67) 31
Unrecognized net (asset) liability 6 (58)
---------- ----------
Accrued pension (liability) included in the Consolidated Balance Sheets $ (3,156) $ (3,220)
========== ==========
</TABLE>
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 $375,000 for the years ended
December 31, 1994, 1993, and 1992, respectively.
44
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
L. Operations by Geographic Area
Information on the Company's continuing operations by geographic
area for the year ended December 31, 1992 is shown below. U.S.
operations have been combined with Canada for 1994 and 1993 due
to the immateriality of the U.S. operations in relation to the
Company's operations as a whole. Operating earnings from
continuing operations are total revenues less operating expenses
of the geographic area, excluding interest and general corporate
items.
In 1994, two Canadian customers each accounted for 11% of the
Company's sales. In 1993, the Company had three Canadian
customers who accounted for 18%, 16% and 11% of sales,
respectively. In 1992, the Company had one Canadian customer who
accounted for 11% of sales.
<TABLE>
As of or for the years
ended December 31, Operating
Operating Earnings Identifiable
($ in thousands) Revenues (Loss) Assets
--------- --------- -------------
<S> <C> <C> <C>
1994 $ 46,290 $ 16,854 $ 211,589*
========= ========= =============
1993 $ 45,903 $ 15,339 $ 210,174*
========= ========= =============
1992
United States $ 22,773 $(57,801) $ 29,787
Canada 37,960 (17,524) 189,198
--------- --------- -------------
$ 60,733 $(75,325) $ 218,985
========= ========= =============
<FN>
* Identifiable assets include $15.0 million and $22.6 million of
cash and cash equivalents on deposit in the U.S. in 1994 and
1993, respectively.
Note: Included in 1992 Canadian operating revenues
were $1.6 million of sales of natural gas from Canada to the
U.S. which were recorded at fair market value. The resale
of such gas to outside parties was eliminated from U.S.
sales.
</TABLE>
M. Discontinued Operations
<TABLE>
Summary of Earnings
For the years ended December 31,
($ in thousands) 1994 1993 1992
------ ------ -------
<S> <C> <C> <C>
Earnings (loss) from
Lindsay Manufacturing Co.
(Loss) on divestiture $ - $ - $ (300)
Commodities Brokerage
(Loss) on divestiture - - (750)
Earnings (loss) from ------ ------ -------
discontinued operations $ - $ - $(1,050)
====== ====== =======
</TABLE>
45
<PAGE>
DEKALB Energy Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
M. Discontinued Operations (Continued)
Other
The Company sold the stock of its commodities brokerage business
in 1986 and Lindsay Manufacturing Co. in 1989. The 1992 losses
resulted from changes in estimated future expenses related to the
above transactions. As a result of the Company's cumulative loss
position in the U.S., no tax benefit was recognized for the
losses.
N. Oil and Gas Disclosures
Capitalized costs at December 31, 1994 (all relating to assets
located in Canada) which have been excluded from the amortization
base as prescribed by the Securities and Exchange Commission
Financial Reporting Release No. 14 are as follows:
<TABLE>
($ in thousands)
Interest
Fiscal Year Leasehold Exploration Related to
of Acquisition Costs Costs Excluded Costs Total
-------------- --------- ----------- -------------- ------
Canada
<S> <C> <C> <C> <C>
Prior $ 46 $ 302 $ 71 $ 419
1992 258 564 168 990
1993 1,483 829 472 2,784
1994 4,723 1,306 1,232 7,261
-------- --------- ----------- -------
Total $ 6,510 $ 3,001 $ 1,943 $11,454
======== ========= =========== =======
</TABLE>
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.
46
<PAGE>
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.
47
<PAGE>
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
<TABLE>
Estimated Net Quantities of Proved Reserves*
As of or for the years ended December 31,
1994 (1) 1993 (1) 1992
-------- -------- ----------------------------
Oil, Condensate and Total U.S. Canada
Natural Gas Liquids -------- -------- --------
(thousands of barrels)
<S> <C> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Beginning of year 13,234 13,984 26,077 11,693 14,384
Revisions of previous
estimates (2,239) (300) (12) - (12)
Sales of reserves (90) (46) (10,928) (10,928) -
Purchase of minerals
in place 83 188 382 - 382
Extensions, discoveries
and other aditions 690 397 227 - 227
Production (962) (989) (1,762) (765) (997)
-------- -------- -------- -------- --------
End of year 10,716 13,234 13,984 - 13,984
======== ======== ======== ======== ========
Proved developed reserves:
Beginning of year 13,221 13,972 25,094 10,723 14,371
======== ======== ======== ======== ========
End of year 10,612 13,221 13,972 - 13,972
======== ======== ======== ======== ========
</TABLE>
<TABLE>
Natural Gas 1994 (1) 1993 (1) 1992
-------- -------- ------------------------------
(millions of cubic feet) Total U.S. Canada
Proved developed and -------- -------- --------
<S> <C> <C> <C> <C> <C>
Beginning of year
undeveloped reserves: 277,411 276,343 361,194 80,464 280,730
Revisions of previous
estimates 6,880 2,198 1,026 732 294
Sales of reserves (11,526) (3,660) (71,429) (71,342) (87)
Purchase of minerals
in place 2,710 4,405 1,617 - 1,617
and other additions
Extensions, discoveries 44,912 19,094 7,239 1,335 5,904
Production (20,491) (20,969) (23,304) (6,671) (16,633)
-------- -------- -------- -------- --------
End of year 299,896 277,411 276,343 4,518 271,825
======== ======== ======== ======== ========
Proved developed reserves:
Beginning of year 263,070 263,305 341,353 73,962 267,391
======== ======== ======== ======== ========
End of year 274,611 263,070 263,305 4,518 258,787
======== ======== ======== ======== ========
<FN>
* Proved oil and gas reserve quantities for all three years
presented were estimated by the Company's engineers. The total
proved reserve quantities for 1994, 1993 and 1992 were reviewed
and determined to be reasonable by Ryder Scott Company
Petroleum Engineers, independent petroleum engineers, in
accordance with Securities and Exchange Commission guidelines.
(1) U.S. reserve information has been combined with Canada for
1993 due to the immateriality of the U.S. reserves in
relation to the total Company reserves. No U.S. reserves
have been assigned at December 31, 1994.
</TABLE>
48
<PAGE>
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*)
<TABLE>
1994
Total
--------
<S> <C> <C> <C>
Future cash inflows $ 536.5 (4)
Future production costs 133.8
Future development costs 22.8
--------
Future net cash flows before income taxes 379.9
Discount at 10% per annum 175.8
--------
Present value of future net cash flows before income taxes 204.1 (4)
Present value of future income taxes** 44.5
--------
Standardized measure of discounted future net cash flows $ 159.6
========
1993 (5)
Total
--------
Future cash inflows $ 672.0 (4)
Future production costs 134.8
Future development costs 20.4
--------
Future net cash flows before income taxes 516.8
Discount at 10% per annum 249.8
--------
Present value of future net cash flows before income taxes 267.0 (4)
Present value of future income taxes** 64.6
--------
Standardized measure of discounted future net cash flows $ 202.4
========
United
1992 States Canada Total
-------- -------- --------
Future cash inflows $ 8.9 $ 648.1 (4) $ 657.0
Future production costs 2.0 172.1 174.1
Future development costs 0.4 22.2 22.6
------- -------- --------
Future net cash flows before income taxes 6.5 453.8 460.3
Discount at 10% per annum 1.3 248.6 249.9
------- -------- --------
Present value of future net cash flows before income taxes 5.2 205.2 (4) 210.4
Present value of future income taxes** - 44.7 44.7
------- -------- --------
Standardized measure of discounted future net cash flows $ 5.2 $ 160.5 $ 165.7
======= ======== ========
<FN>
* As developed by using the following conventions:
(1) Estimates are made of quantities of proved reserves at fiscal
year-end and for future periods during which these reserves are
expected to be produced, based on year-end economic conditions.
(2) Pricing of future production of proved reserves is based on the
prices in effect at fiscal year-end in accordance with Securities
and Exchange Commission (SEC) Guidelines and do not reflect current
prices. Estimated future production and development costs reflect
current economic conditions.
(3) The provision for income taxes has been computed by applying
future statutory tax rates under the present law to the future
taxable income to be generated from producing proved reserves
giving effect to applicable permanent differences.
(4) Included in future cash inflows is approximately $25.7 million,
$39.4 million and $45.6 million ($9.8 million, $12.0 million and
$14.1 million after discount at 10% per annum) for 1994, 1993 and
1992 respectively of Canadian provincial tax credits expected to
be realized beyond the date at which the legislation, under its
provisions, could be repealed.
(5) U.S. net cash flows have been included with Canada for 1993 due
to their immateriality in relation to the total net cash flows for
the Company as a whole. No future net cash flows were assigned to
the U.S. at December 31, 1994.
** Canadian undiscounted future income taxes in 1994, 1993, and 1992
were $91.7 million, $135.3 million and $119.8 million,
respectively.
</TABLE>
49
<PAGE>
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
The following table sets forth the changes in the Standardized Measure
of Discounted Future Cash Flow relating to Proved Oil and Gas Reserves
($ in millions)
<TABLE>
As of or for the years ended December 31,
Revision Purchases
Current Changes of Discoveries of Sales of Accretion
Beginning Year in Prices Estimated and Minerals Minerals of Income End of
of Year Sales and Costs Quantities Extensions in Place* in Place Discount taxes Other Year
-------- -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1994 (1)
Total $ 202.4 $ (31.1) $ (58.4) $ 0.7 $ 28.3 $ 1.8 $ (13.7) $ 23.4 $ 16.6 $ (10.4) $ 159.6
======== ======== ======== ======== ======== ======== ======== ======== ======== ======== ========
1993(1)
Total $ 165.7 $ (31.8) $ 54.1 $ 2.6 $ 20.3 $ 4.8 $ (4.2) $ 18.3 $ (19.9) $ (7.5) $ 202.4
======== ======== ======== ======== ======== ======== ======== ======== ======== ======== ========
1992
U.S. $ 114.3 $ (15.0) $ (1.3) $ - $ 2.1 $ - $ (95.3) $ 0.4 $ - $ - $ 5.2
Canada $ 161.0 $ (27.4) $ 22.5 $ 2.4 $ 5.8 $ 3.3 $ - $ 16.6 $ (6.9) $ (16.8) $ 160.5
-------- -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Total $ 275.3 $ (42.2) $ 21.2 $ 2.4 $ 7.9 $ 3.3 $ (95.3) $ 17.0 $ (6.9) $ (16.8) $ 165.7
======== ======== ======== ======== ======== ======== ======== ======== ======== ======== ========
<FN>
* Includes any unevaluated costs associated with acquired properties.
(1) U.S. data has been included with Canada for 1993 due to its
immateriality in relation to the total data for the Company as a
whole. No future net cash flows were assigned to the U.S. at
December 31, 1994.
</TABLE>
CAPITALIZED COSTS RELATED TO OIL AND GAS PROPERTIES
($ in thousands)
<TABLE>
As of December 31, 1994 1993 (2)
-------- --------
<S> <C> <C>
Evaluated Properties $ 312,649 $ 298,235
Unevaluated Properties (1) 11,454 9,048
Total properties 324,103 307,283
Less reserves for accumulated
depreciation, depletion
and amortization 139,555 130,079
-------- --------
End of year $ 184,548 $ 177,204
======== ========
<FN>
(1) Unevaluated costs represent acquisition and exploration costs
which are excluded from the current amortization base as
described in Note N.
(2) U.S. costs have been included with Canada for 1994 and 1993
due to their immateriality in relation to the total costs for
the Company as a whole.
</TABLE>
50
<PAGE>
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
<TABLE>
COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES (1)
($ in thousands)
For the years ended December 31,
1994 (2) 1993 (2) 1992
-------- -------- ---------------------------
Total U.S. Canada
-------- -------- -------
<S> <C> <C> <C> <C> <C>
Leasehold costs $ 7,337 $ 2,686 $ 906 $ - $ 906
Purchases of minerals
in place 770 2,075 1,912 - 1,912
Exploration 13,399 8,168 7,709 2,649 5,060
Development 19,714 6,532 6,504 3,361 3,143
------- -------- ------- -------- -------
Total $41,220 $ 19,461 $17,031 $ 6,010 $11,021
======= ======== ======= ======== =======
<FN>
(1) Costs do not include capitalized interest. Capitalized general and
administrative costs of $2,335,000, $2,422,000 and $1,853,000 for 1994,
1993 and 1992, respectively, have been included.
(2) U.S. costs for 1993 have been combined with Canada due to the
immateriality of the U.S. costs in relation to the total Company
costs as a whole. No U.S. costs were incurred in 1994.
</TABLE>
<TABLE>
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES ($ in thousands)
For the years ended December 31,
1994 (5) 1993 (5) 1992
----------- ----------- ----------------------------------
Total U.S. Canada
----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Revenues (4) $ 46,290 $ 45,903 $ 60,733 $ 22,773 $ 37,960
Lease operations and other
direct charges (1) 11,654 12,467 18,833 7,218 11,615
Depreciation, depletion
and amortization 14,603 15,142 22,522 9,683 12,839
Provision for impairment of
oil and gas properties - - 53,320 24,728 28,592
Income and other taxes (2) 8,833 8,164 (13,756) (7,067) (6,689)
---------- ---------- ---------- ---------- ----------
Results of Operations for oil
and as producing activities $ 11,200 $ 10,130 $ (20,186) $ (11,789) $ (8,397)
========== ========== ========== ========== ==========
"Full Cost" Amortization Rate (3) $ 3.33 $ 3.37 $ 5.16 $ 3.31
========== ========== ========== ==========
<FN>
(1) Excludes general and administrative and interest costs.
(2) This provision is not an indication of the total corporate income
tax provision and is provided at statutory tax rates.
(3) Dollars per equivalent barrel (gas converted to oil at 6,000 cubic
feet per barrel).
(4) Included in 1992 Canadian operating revenues were $1.6 million of
sales of natural gas from Canada to the U.S. which were recorded
at fair market value. The resale of such gas to outside parties
was eliminated from U.S. sales.
(5) U.S. results of operations for 1994 and 1993 have been combined
with Canada due to the immateriality of the U.S. results in
relation to the total Company results as a whole.
</TABLE>
51
<PAGE>
DEKALB Energy Company
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
<TABLE>
QUARTERLY RESULTS OF OPERATIONS
Three months ended the last day of
March June September December
--------- --------- --------- ---------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Year ended December 31, 1994
----------------------------
Operating revenues $ 11,130 $ 12,107 $ 12,206 $ 10,847
Operating expenses 6,536 6,614 7,811 8,475
Earnings from continuing operations 1,750 2,416 1,890 757
Net earnings 1,750 2,416 1,890 757
Earnings per common share:
Earnings from continuing operations $ 0.18 $ 0.25 $ 0.20 $ 0.08
Net earnings 0.18 0.25 0.20 0.08
Year Ended December 31, 1993
----------------------------
Operating revenues $ 11,827 $ 11,949 $ 10,245 $ 11,882
Operating expenses 7,443 8,514 6,902 7,705
Earnings from continuing operations 1,413 1,336 1,074 1,849
Net earnings 6,747 1,336 1,074 1,849
Earnings per common share:
Earnings from continuing operations $ 0.15 $ 0.14 $ 0.11 $ 0.19
Net earnings 0.70 0.14 0.11 0.19
</TABLE>
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.
52
<PAGE>
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
NONE
PART III
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.
53
<PAGE>
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.
54
<PAGE>
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)
<TABLE>
Long Term
Compensation
Annual Compensation Awards
------------------- ------------
Number of
Securities
Name and Principal Position at Underlying All Other
December 31, 1994 Year Salary Bonus Options/SAR's Compensation
------------------------------ ---- ---------- --------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Donald McMorland (4) 1994 $ 82,699 $ - 10,000 $ -
President, and Vice Chairman
of the Board
Bruce A. Craig (2) 1994 $ 94,119 $ 20,640 35,500 $ 10,352 (7)
Vice President Marketing of 1993 89,102 17,156 - 743
DEKALB Energy Canada Ltd. 1992 10,618 - 3,000 -
Lawrence G. Evans 1994 $ 93,197 $ 25,521 21,175 $ 16,031 (8)
Vice President Production of 1993 83,678 23,121 10,160 10,703
DEKALB Energy Canada Ltd. 1992 85,263 24,476 5,318 7,743
Michael E. Finnegan (5) 1994 $ 75,424 $ 29,642 17,490 $ 6,518 (9)
Executive Vice President, Chief 1993 85,228 23,977 10,345 13,380
Financial Officer, and Treasurer 1992 85,428 25,382 7,681 9,078
Richard G. Nash 1994 $ 100,150 $ 32,679 12,765 $ 17,204 (10)
Vice President Exploration and 1993 97,625 32,540 11,850 12,133
Land of DEKALB Energy Canada Ltd. 1992 104,303 34,448 9,306 9,596
Vincent J. Tkachyk (3) 1994 $ 81,607 $ 38,944 16,879 $ 211,150 (6)
President 1993 137,438 46,525 14,000 38,456
1992 153,132 48,235 26,020 43,127
</TABLE>
55
<PAGE>
(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.
56
<PAGE>
OPTION/SAR GRANTS DURING 1994
<TABLE>
Potential Realizable
Value of Assumed
Annual Rates of
Stock Price
Appreciation for
Individual Grants Option Term
------------------------------------------------------------------------------------ ---------------------
Percentage
Number of of Total
Securities Options/SARs Exercise
Underlying Granted to or Base
Options/SARs Employees Price Per Expiration
Name Granted in 1994 Share Date 5% 10%
-------------------- ------------ ------------ ----------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C>
Donald McMorland (1) 10,000 (5) $ 14.00 (1) (1) (1)
Bruce A. Craig 16,250 (2) 8.3% $ 14.00 02-23-99 $ 62,888 $ 138,775
19,250 (6) 9.9% $ 15.25 11-07-99 $ 81,043 $ 179,410
Lawrence G. Evans 21,175 (2) 10.9% $ 14.00 02-23-99 $ 81,949 $ 180,835
Michael E. Finnegan 17,490 (3) 9.0% $ 14.00 09-17-95 $ 12,243 $ 24,486
Richard G. Nash 12,765 (2) 6.6% $ 14.00 02-23-99 $ 49,401 $ 109,103
Vincent J. Tkachyk 16,879 8.7% $ 14.00 08-11-94 (4) $ - $ -
<FN>
(1) Stock Appreciation Rights became fully exercisable on
November 18, 1994 and may only be exercised between November
18, 1994 and 90 days after Mr. McMorland ceases to be
President of DEKALB Energy Company.
(2) These options for shares of Class A Stock of the Company
granted on February 24, 1994 vest in one-third increments
annually beginning February 24, 1995.
(3) All unexercised options became exercisable upon the death of
Mr. Finnegan.
(4) The option automatically expired 90 days after Mr. Tkachyk's
employment terminated.
(5) Mr. McMorland was one of two employees who received Stock
Appreciation Rights (SARs). He received 50% of such issued
SARs.
(6) These options for shares of Class A Stock of the Company
granted on November 8, 1994 vest in one-third increments
annually beginning November 8, 1995.
</TABLE>
57
<PAGE>
AGGREGATED OPTION/SAR EXERCISES IN 1994 AND DECEMBER 31, 1994
OPTION/SAR VALUE
<TABLE>
Number of Unexercised
Securities Underlying Value of Unexercised
Options/SARs Held In-The-Money Options/SARs
at December 31, 1994 at December 31, 1994
Shares
Acquired on Value
Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
----------- -------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Donald McMorland - $ - 10,000 - $ 72,500 $ -
Bruce A. Craig - $ - 3,000 35,500 $ 19,875 $ 233,313
Lawrence G. Evans - $ - 11,315 29,338 $ 64,767 $ 225,944
Michael E. Finnegan - $ - 38,716 - $ 294,728 $ -
Richard G. Nash - $ - 15,521 23,300 $ 107,848 $ 185,385
Vincent J. Tkachyk (1)- $ - - - $ - $ -
<FN>
(1) All of Mr. Tkachyk's stock options expired August 11, 1994.
None were exercised since they were not-in-the-money.
</TABLE>
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.
<TABLE>
Years of Service
-------------------------------------------------
Remuneration 15 20 25 30 35
------------ ------- -------- ------- -------- -------
<S> <C> <C> <C> <C> <C>
$ 110,000 $ 33,000 $ 44,000 $ 55,000 $ 66,000 $ 77,000
125,000 37,500 50,000 62,500 75,000 87,500
140,000 42,000 56,000 70,000 94,000 98,000
155,000 46,500 62,000 77,500 93,000 108,500
170,000 51,000 68,000 85,000 102,000 119,000
185,000 55,500 74,000 92,500 111,000 129,500
200,000 60,000 80,000 100,000 120,000 140,000
215,000 64,500 86,000 107,500 129,000 150,500
</TABLE>
58
<PAGE>
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:
<TABLE>
<S> <C>
Bruce A Craig 2
Lawrence G. Evans 14
Richard G. Nash 8
</TABLE>
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.
59
<PAGE>
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. 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:
<TABLE>
Number of Shares of Stock Owned Beneficially
and Percentages of Class Outstanding on
December 31, 1994 (1)
------------------------------------------------
Class A % Class B %
------- ------- ------- -------
<S> <C> <C> <C> <C>
Bruce P. Bickner (2) 97,547 4.239 9,050 0.127
Bruce A. Craig (3) 8,417 0.366 - -
Larry G. Evans (4) 21,760 0.946 300 0.004
Michael E. Finnegan (5) 38,716 1.682 - -
Donald McMorland - - 1,000 0.014
Richard G. Nash (6) 23,726 1.031 - -
Charles C. Roberts (7)(8) 60,268 2.619 625 0.009
Thomas H. Roberts, Jr. (8)(9) 187,311 8.139 67,603 0.952
H. Blair White 10,000 0.435 - -
William J. Wooten - - 200 0.003
Vincent J. Tkachyk (10) - - 2,645 0.037
All of the above and all other executive
officers as a group (14) persons (11) 482,435 20.963 85,323 1.202
</TABLE>
60
<PAGE>
(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.
61
<PAGE>
(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.
62
<PAGE>
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.
<TABLE>
Percentage of
Outstanding Shares
Shares Owned of
Name and Address Beneficially (1) Class A Stock
------------------------------ ---------------- -----------------
<S> <C> <C>
Thomas H. Roberts, Jr. (2)(3) 187,311 8.139
Box 486, 9 Arrowhead Lane
DeKalb, Illinois 60115
Amy L. Domini, 273,204 11.872
William B. Perkins (4)
230 Congress Street
Boston, Massachusetts 02110
Douglas C. Roberts 277,976 12.079
Lynne K. Roberts (2)(5)
1449 Janet Street
Sycamore, Illinois 60178
Virginia Roberts Holt 277,637 12.064
Terrance K. Holt (2)(6)
2329 Clover Lane
Northfield, Illinois 60093
John T. Roberts 274,673 11.935
Robin R. Roberts (2)(7)
2090 Mulsanne Drive
Zionsville, Indiana 46077
Thomas H. Roberts, III (2) 198,390 8.621
2621 Club Lake Trail
McKinney, Texas 75070
</TABLE>
(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.
63
<PAGE>
(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. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Item 11, ``COMPENSATION COMMITTEE INTERLOCKS AND INSIDER
PARTICIPATION'', with respect to Mr. White and Mr. McMorland.
64
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
(a) (1) Financial Statements
<TABLE>
The following financial statements of DEKALB Energy Company are
included in Part II, Item 8:
Page
----
<S> <C>
Auditors' Report (8) 22
Responsibilities for Financial Statements 23
Consolidated Statements of Operations for the
years ended December 31, 1994, 1993, and 1992 24
Consolidated Balance Sheets as of
December 31, 1994 and 1993 25
Consolidated Statements of Cash Flows for
the years ended December 31, 1994, 1993 and 1992 26
Consolidated Statements of Shareholders'
Equity for the years ended December 31, 1994,
1993, and 1992 27
Notes to Consolidated Financial Statements 28-47
Unaudited Supplementary Financial Information 48-52
(a) (2) Financial Statement Schedules
Auditors' Report (8) 69
Schedule II- Valuation and Qualifying Account 70
</TABLE>
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.
65
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) (3) Exhibits
<TABLE>
Page
----
<S> <C>
3.1 Restated Certificate of Incorporation of the
Registrant (2)
3.2 Restated By-laws of the Registrant (1)
4.1 Indenture dated as of April 1, 1988, between
the Registrant and Continental Illinois Bank
and Trust Company of Chicago as Trustee relating
to $50 million Long-Term Notes at 10%
and $75 million of Long-Term Notes at 9.875% (3)
4.2 Extendible Revolving Term Credit Agreement
between DEKALB Energy Canada Ltd.
and the Royal Bank of Canada (7)
10.1 Stock Option Plan (1)*
10.2 Form of Stock Option Agreement (1)*
10.3 Letter Agreement between DEKALB
Energy Company and Vincent J. Tkachyk (7)*
10.4 Deferred Management Compensation Plan (2)*
10.5 Employment Agreement between DEKALB Energy
Company and Bruce P. Bickner (5)*
10.6 Employment Agreement between DEKALB Energy
Company and John H. Witmer, Jr. (5)*
10.7 Long-Term Incentive Plan (4)*
10.8 Firm Transportation Service Agreement between
the Registrant and Pacific Gas
Transmission Company (7)
10.9 Asset Purchase and Sale Agreement (U.S.
properties) between the Registrant
and Louis Dreyfus Gas Holdings Inc. (6)
10.10 DEKALB Energy Company Profit Based Thrift Plan (7)
10.11 Temporary Consulting Contract between
DEKALB Energy Company and Donald McMorland (8)* 71
10.12 Temporary Consulting Contract between DEKALB
Energy Company and John Leteta (8)* 76
10.13 Agreement and Plan of Merger among Apache
Corporation, XPX Acquisition
and the Registrant (9)
11 Statement re Computation of Per Share Earnings 77
21 Subsidiaries of Registrant 78
24.1 Consent of Auditors 79
24.2 Consent of Independent Petroleum Engineers 80
27.1 Financial Data Schedule
28 Report of Independent Petroleum Engineers 81
</TABLE>
66
<PAGE>
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.
67
<PAGE>
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
68
<PAGE>
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
69
<PAGE>
<TABLE>
DEKALB Energy Company
SCHEDULE II - VALUATION and QUALIFYING ACCOUNT
years ended December 31, 1994, 1993, and 1992
($ in thousands)
Column A Column B Column C Column D Column E
-------- -------- -------- -------- --------
Additions
------------------------
Balance at Charged to Charged to Balance at
Beginning costs and Other End
Description of Period Expenses Accounts Deductions of Period
------------------------------------ ----------- ----------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1994:
Deducted in the balance sheet
from the assets to which they
apply:
Allowance for doubful accounts
and notes receivable $ 709 $ - $ - $ (620) (c) $ 89
=========== =========== ============ ========== ============
Allowance for assets of
discontinued business $ 4,379 $ - $ 69 $ - $ 4,448
=========== =========== ============ ========== ============
Year ended December 31, 1993:
Deducted in the balance sheet
from the assets to which they
apply:
Allowance for doubful accounts
and notes receivable $ 679 $ 30 $ - $ - $ 709
=========== =========== ============ ========== ============
Allowance for assets of
discontinued business $ 3,637 $ - $ 840 $ (98) (b) $ 4,379
=========== =========== ============ ========== ============
Year ended December 31, 1992:
Deducted in the balance sheet
from the assets to which they
apply:
Allowance for doubful accounts
and notes receivable $ 385 $ 630 $ - $ (336) (a) $ 679
=========== =========== ============ ========== ============
Allowance for assets of
discontinued businesses $ 3,507 $ - $ 761 $ (631) $ 3,637
=========== =========== ============ ========== ============
<FN>
Notes:
(a) Uncollectible items written off, less recoveries of items
previously written off.
(b) Realized losses charged to the reserve.
(c) Recovery of items previously provided for in the reserve
balance.
</TABLE>
70
<PAGE>
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'').
71
<PAGE>
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.
72
<PAGE>
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.
73
<PAGE>
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.
74
<PAGE>
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
75
<PAGE>
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 $50,000 basic life insurance. You will
continue to be deducted once per month for current benefit
premiums.
Either party may terminate this agreement on one month's notice.
Your employment will not reduce the benefits from the Retiring
Allowance Agreement Plan and the Supplementary Retirement Plan.
If you are in agreement with this offer, please sign one copy of
this letter in the space provided below and return it to me at
your earliest convenience.
Yours truly, The above agreed to and
accepted this 29 day of
November, 1994
DONALD MCMORLAND JOHN LETETA
---------------- -----------
Donald McMorland John Leteta
President
76
<PAGE>
EXHIBIT 11
DEKALB Energy Company
STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
<TABLE>
For the years ended December 31,
Average Shares Outstanding
-------------------------- 1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
1.Average shares outstanding 9,503,533 9,605,900 9,629,754
2.Net additional shares outstanding assuming all
stock options exercised and proceeds used to
purchase treasury stock (a) 79,456 69,250 -
---------- ---------- ----------
3. Average number of shares outstanding 9,582,989 9,675,150 9,629,754
========== ========== ==========
4.Fully diluted number of shares 9,590,936 9,678,131 9,671,130
========== ========== ==========
5.Net earnings (loss) per share computation:
($ in thousands)
Earnings (loss) from continuing operations $ 6,813 $ 5,672 $ (69,253)
Loss from discontinued operations - - (1,050)
Cumulative effect of change in accounting
principle - - 5,334
---------- ---------- ----------
Net earnings (loss) $ 6,813 $ 11,006 $ (70,303)
========== ========== ==========
6.Net earnings (loss) per average share outstanding
as reported in summary of operations:
Earnings (loss) from continuing operations $ 0.71 $ 0.59 $ (7.19)
Loss from discontinued operations - - (0.11)
Cumulative effect of change in accounting
principle - 0.55 -
---------- ---------- ----------
Net earnings (loss) per share $ 0.71 $ 1.14 $ (7.30)
========== ========== ==========
7.Net earnings (loss) per fully diluted average share:
Earnings (loss) from continuing operations $ 0.71 $ 0.59 $ (7.16)
Loss from discontinued operations - - (0.11)
Cumulative effect of change in accounting
principle - 0.55 -
---------- ---------- ----------
Net earnings (loss) per share $ 0.71 $ 1.14 $ (7.27)
========== ========== ==========
<FN>
Notes:
(a) The 1992 computation of average number of shares outstanding
excludes anti-dilutive shares.
</TABLE>
77
<PAGE>
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.
<TABLE>
Percentage of
Voting Securities
Jurisdiction of Owned by the
Incorporation Registrant
--------------- -----------------
<S> <C> <C>
DEKALB Energy Canada Ltd. Alberta 100%
DEKALB Energy Texas Inc. Delaware 100%
</TABLE>
78
<PAGE>
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
79
<PAGE>
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
80
<PAGE>
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
<TABLE>
Reviewed by Ryder Scott Not Reviewed Total
----------------------- ------------------- -------------------
Hydrocarbon Sales Hydrocarbon Sales Hydrocarbon Sales
Liquids Gas Liquids Gas Liquids Gas
MBarrels MMCF MBarrels MMCF MBarrels MMCF
------------ -------- ----------- ------ ----------- -------
<S> <C> <C> <C> <C> <C> <C>
Total
Proved
Reserves 8,473 249,689 2,243 50,207 10,716 299,896
</TABLE>
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.
81
<PAGE>
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:
82
<PAGE>
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
83
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 14,980
<SECURITIES> 0
<RECEIVABLES> 9,509
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 928
<PP&E> 326,894
<DEPRECIATION> (141,512)
<TOTAL-ASSETS> 211,589
<CURRENT-LIABILITIES> 15,729
<BONDS> 61,547
<COMMON> 8,549
0
0
<OTHER-SE> 88,282
<TOTAL-LIABILITY-AND-EQUITY> 211,589
<SALES> 44,889
<TOTAL-REVENUES> 46,290
<CGS> 0
<TOTAL-COSTS> 26,257
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,047
<INCOME-PRETAX> 12,842
<INCOME-TAX> 6,029
<INCOME-CONTINUING> 6,813
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,813
<EPS-PRIMARY> .71
<EPS-DILUTED> .71
</TABLE>
