<PAGE> 1
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
SECURITIES EXCHANGE ACT OF 1934 FOR THE
FISCAL YEAR ENDED JUNE 30, 1996
Commission File Number 1-7836
(_)TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ENDED __________
SAGE ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware 75-1542170
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
10101 Reunion Place, Suite 800
San Antonio, Texas 78216
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (210) 340-2288
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -------------------
8 1/2% Convertible Subordinated Debentures Due 2005 American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
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 the
filing requirements for at least the past 90 days.
Yes (X) No (_)
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 definitve proxy or information statement's
incorporated by reference in Part III of this Form 10-K or any amendment to
this form 10-K {X}
No voting stock was held by nonaffiliates of the Registrant as of September 30,
1996.
Indicate the number of shares outstanding of each of issuer's classes of common
stock, as of the close of the period covered by this report.
Class Outstanding at June 30, 1996
----- ----------------------------
Common Stock ($.01 par value) 1,399
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<PAGE> 2
SAGE ENERGY COMPANY
ANNUAL REPORT (S.E.C. Form 10-K)
INDEX
Item Number and Description
PART I
<TABLE>
<CAPTION>
Page
- ----
<S> <C> <C>
Item 1. Business................................................ 1
Item 2. Properties.............................................. 7
Item 3. Legal Proceedings....................................... 12
Item 4. Submission of Matters to a Vote of Security Holders..... 12
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters..................................... 12
Item 6. Selected Financial Data................................. 14
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 15
Item 8. Financial Statements and Supplementary Data............. 23
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure..................... 43
PART III
Item 10. Directors and Executive Officers of the Registrant...... 43
Item 11. Executive Compensation.................................. 44
Item 12. Security Ownership of Certain Beneficial Owners
and Management.......................................... 47
Item 13. Certain Relationships and Related Transactions.......... 47
PART IV and SIGNATURES
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................. 48
SIGNATURES........................................................ 50
</TABLE>
<PAGE> 3
PART I
Item 1. Business.
(a) General Description and Development of Business
Sage Energy Company (hereinafter "Sage" or the "Company"), a Delaware
corporation, is engaged in the exploration for, and development, production and
sale of, oil and gas. The Company was organized in 1977 as a Texas Corporation
but in December 1991, it reincorporated in the State of Delaware. The Company,
on a continuing basis, acquires and makes its own geological and geophysical
evaluations of oil and gas properties, and thereafter forms and participates in
exploration and development joint ventures for which the Company generally acts
as operator. Except for certain recent drilling activities, the Company
generally has not participated in exploration activities with respect to
prospects for which it is not the operator, and has been the major participant
in substantially all of the oil and gas properties for which it is the
operator.
The Company's activities are primarily undertaken in Texas, although it
also conducts operations in other states. In Texas, the Company's activities
are in the Permian Basin of West Texas, the Austin Chalk Trend of South Texas,
and in the Gulf Coast region. The Company also has horizontal activities in
the Giddings Austin Chalk area. The Company owns interests in Southeastern New
Mexico and holds some undeveloped acreage in North Dakota, South Dakota and
Louisiana.
The Company formerly conducted a contract drilling business through
Sterling Drilling Company, now a division of the Company, and presently owns
four oil and gas drilling rigs (after selling three in fiscal 1996) with depth
capabilities ranging from 9,000 to 14,500 feet. Three of these rigs were
previously employed in exploratory and development drilling for both the
Company's own operations and for unaffiliated customers. Additionally, in May
1996 the Company sold its six service rigs used for completion and remedial
work. As of June 30, 1996, all but one of the Company's drilling rigs were
deactivated.
Revenues generated from the oil and gas operations of the Company are
highly dependent upon the prices of and demand for oil and gas. Various
factors beyond the control of the Company affect prices of oil and gas,
including the worldwide supply of oil and gas, the ability of members of OPEC
to agree to and maintain price and production controls, political instability
or armed conflict in oil producing regions, the price of foreign imports, the
levels of consumer demand, the price and availability of alternative fuels,
availability of pipeline capacity and changes in existing Federal regulation
and price controls. Prices for oil and gas have fluctuated greatly during the
past several years and markets for oil and gas may continue to be volatile.
Unsettled energy markets make it particularly difficult to estimate future
prices of oil and gas. In addition, demand for natural gas and natural gas
products can fluctuate significantly with seasonal and annual variations in
weather patterns because those products are used in large part as heating
fuels.
Sage's principal offices are located at 10101 Reunion Place, Suite 800,
San Antonio, Texas, 78216 and its telephone number is (210) 340-2288.
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(b) Financial Information About Industry Segments
Sage's business segments for the periods indicated consist of oil and gas
production and contract drilling. The following table sets forth the revenues,
operating profit and identifiable assets of these business segments for these
periods.
<TABLE>
<CAPTION>
Years Ended June 30,
-------------------------------------
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Oil and Gas Production
Revenues...................... $27,815,000 $25,675,000 $30,089,000
Operating profit ............. 9,936,000 6,483,000 7,337,000
Identifiable assets........... 39,383,000 34,124,000 34,694,000
Contract Drilling
Revenues...................... 2,723,000 2,450,000 3,169,000
Intersegment sales............ 887,000 818,000 1,327,000
Operating profit ............. 432,000 179,000 712,000
Identifiable assets........... 1,331,000 2,148,000 1,846,000
</TABLE>
(c) Narrative Description of Business
Principal Products and Markets
The Company's principal products are oil and natural gas. The principal
markets for such products are those where the Company's oil and gas properties
are physically located, and the methods of distribution of such products are by
the sale of such products at the wellhead to appropriate gathering companies
operating in the geographic area of the Company's production. The ability of
the Company to market oil and gas depends on numerous factors beyond the
control of the Company. The effect of such factors cannot be accurately
predicted or anticipated. These factors include the availability of other
domestic and foreign production, the competitive fuels market, the proximity
and capacity of pipelines, fluctuations in supply and demand, the availability
of a ready market, the effect of Federal and state regulations on production,
refining, transportation and sales, and national and worldwide economic and
political conditions.
Oil
For several years, oil prices have been volatile. During fiscal 1996 oil
prices increased over the prior fiscal year. The Company cannot predict future
price levels.
Substantially all of the Company's crude oil and condensate production is
sold at monthly posted prices to a variety of purchasers under arrangements
which are typical and customary in the oil industry. The Company disburses
revenues on a major portion of the crude oil it sells, which the Company
believes enables it to contract with various purchasers at a higher negotiated
price. Such arrangements are generally for short primary terms of less than
3-6 months and month-to-month thereafter as the Company believes that short
contract time periods enable the Company to negotiate a higher price for its
crude oil production. Under these arrangements, the Company has been able to
2
<PAGE> 5
obtain price premiums from purchasers and has flexibility to switch purchasers
if it so desires. Approximately 59% of the Company's proved reserves at June
30, 1996 consisted of crude oil. In addition, approximately 66% of the
Company's oil and gas revenues resulted from the production and sale of crude
oil in fiscal 1996. Consequently, the financial results of the Company are
influenced to a greater degree by crude oil prices than those for natural gas.
Gas Production
The Company's gas production is sold primarily under market sensitive
agreements (both long-term and short-term) with a variety of purchasers,
including pipelines and their affiliates, independent marketing companies and
other purchasers who have the ability to purchase all gas produced by the
Company.
The market for the Company's natural gas production is somewhat seasonal
in nature as the demand and prices for natural gas and natural gas products
generally increase during the winter months. The Company however, has been
able to sell all its gas production generally at monthly market area prices.
If the Company completes a gas well in an area distant from existing gas
pipelines, the well may remain shut-in for lack of a market until such time as
a pipeline with available capacity is extended to the area.
In view of the many uncertainties affecting the supply and demand for
oil, gas and refined petroleum products, the Company is unable to predict
future oil and gas prices or guarantee that the Company will be able to market
all oil or gas produced by it.
Marketing of Production
Production from the Company's properties is marketed consistent with
industry practices, which include the sale of oil at the wellhead to third
parties and the sale of gas to third parties at negotiated prices based on
factors normally considered in the industry (such as the availability of
buyers, market prices, price regulations, distance from the well to the
pipeline, well pressure, estimated reserves, quality of gas, length of
contract, and prevailing supply and conditions).
Employees
As of June 30, 1996, the Company employed 78 full-time employees,
including 4 petroleum engineers, 5 geologists, 4 landmen, 1 attorney, 4
accountants, 1 drilling and 7 production superintendents, and 34 field and 18
administrative personnel. The Company believes its relations with its
employees are excellent. No Company employees are covered by union contracts.
Competition
The Company's competitors in oil and gas exploration, development and
production include the major oil companies and numerous independent oil and gas
companies, individual proprietors and drilling programs. Competition is
particularly intense with respect to the sale of oil and gas production and the
acquisition of oil and gas leases suitable for exploration and of producing
properties. Moreover, competition for leases is extremely intense in the
Austin Chalk Trend of South Texas, where the Company undertakes significant
activities. In addition, there is intense competition for the hiring of
experienced personnel. Generally, the Company will encounter strong
competition from various independent operators and major oil companies in
raising capital and in acquiring producing properties and properties suitable
for development by the Company. Many of such competitors possess and employ
financial and personnel resources substantially in excess of those available to
the Company and may, therefore, be able to pay greater amounts for
3
<PAGE> 6
desirable leases and to evaluate, bid for, purchase and define a greater number
of potential producing prospects than the Company's financial or personnel
resources permit.
The Company substantially decreased its contract drilling operations in
1988 and subsequently moved substantially all of its drilling equipment to
Company-owned yards in West Texas. In the last six (6) months of fiscal 1993
the Company began contract drilling operations and continued these operations
in fiscal 1994, 1995 and 1996 with one drilling rig. If the Company were to
significantly reenter the contract drilling business, its principal market
would likely be the Permian Basin of West Texas and Southeastern New Mexico.
This market is highly fragmented and extremely competitive.
Numerous companies compete in the contract drilling business primarily on
the basis of contract rates, suitability and availability of equipment,
experience and reputation. Since the spring of 1982, competition within the
industry has been intense due to a sharp sustained imbalance between supply and
demand for contract drilling services. The oversupply of rigs is a result of
rig overbuilding during the peak drilling years of 1980 and 1981, and depressed
demand primarily as a result of lower oil and gas prices. As a result of this
excess supply of drilling rigs (as compared to the number of available drilling
contracts), drilling rates remain low and contractual risks which contractors
are forced to accept remain high. Although the number of land rigs in the
United States has substantially decreased since 1982, until the competition in
this market abates and drilling rates increase, the Company does not intend to
have substantial participation in the contract drilling industry.
Principal Customers
The following table sets forth certain information with respect to the
Company's customers whose purchases of goods and services during fiscal 1996
exceeded 10% of revenues.
<TABLE>
<CAPTION>
Sales as a
Type of Percent of
Service or Relationship Total
Name of Customer Product Sold to Company Revenue
- ---------------- ------------ ----------- -------
<S> <C> <C> <C>
Scurlock Permian Oil Company.... Crude Oil None 47.28%
Aquila Southwest Pipeline....... Natural Gas None 12.04%
</TABLE>
The Company markets and will continue to market its oil and gas production to a
number of purchasers and does not believe that the loss of any single purchaser
of its crude oil, natural gas or condensate would adversely affect its
operations in any material respect.
Backlog Orders and Government Contracts
The Company has no amount of firm backlog orders, and is a party to no
material contracts for which the termination of or renegotiation of profits may
be made at the election of any government.
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<PAGE> 7
Regulation
General
The production and sale of oil and gas is regulated by various state and
Federal authorities. The executive and legislative branches of the Federal
government have periodically proposed and considered various programs for
development and use of alternative fuels, energy conservation and limitations
or taxes on crude oil imports. The Company cannot predict what effect, if any,
such programs, if implemented, would have on the Company.
Price and Regulatory Controls
Natural gas sold by the Company has been subject to regulation by the
Federal Energy Regulatory Commission under the Natural Gas Act of 1938 (the
"NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). Prices on the
majority of the Company's gas sales were decontrolled on January 1, 1985.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and the
regulation of spacing, plugging and abandonment of such wells. The statutes
and regulations of the States of Texas and New Mexico and certain other states
limit the rate at which oil and gas can be produced from the Company's
properties.
Several major regulatory changes have been implemented by the Federal
Energy Regulatory Commission (the "FERC") from 1985 to the present that affect
the economics of natural gas production, transportation and sales. In
addition, the FERC continues to promulgate revisions to various aspects of the
rules and regulations affecting those segments of the natural gas industry,
most notably interstate natural gas transmission companies, which remain
subject to the FERC's jurisdiction. These initiatives may also affect the
intrastate transportation of gas under certain circumstances. The stated
purpose of many of these regulatory changes is to promote competition among the
various sectors of the gas industry. The ultimate impact of these complex and
overlapping rules and regulations, many of which are repeatedly subjected to
judicial challenge and interpretation, cannot be predicted.
Most states in which the Company conducts or may conduct oil and gas
activities regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. In addition, most states regulate the rate of production
and may establish maximum daily production allowable from both oil and gas
wells on a market demand or conservation basis. There has been no limit on
allowable daily oil production on the basis of market demand since mid-1972,
although at some locations production continues to be regulated for
conservation purposes.
5
<PAGE> 8
Environmental Regulation
The Company's producing and drilling operations are subject to
environmental protection regulations established by Federal, state and local
agencies. The Company believes that it is currently in substantial compliance
with all applicable Federal, state and local environmental regulations. The
Company does not believe that environmental regulations in their present form
have or will have any material effect upon its future capital expenditures or
earnings. Any new legislation or regulations, together with penalties for
noncompliance, will increase the cost of oil and gas development and
production. The Company's competitors are subject to the same regulations to
which the Company is subject, and therefore such regulations do not materially
affect the Company's competitive position. The Company does not project any
material capital expenditures for environmental control facilities for the
remainder of the current fiscal year.
(d) Financial Information About Foreign and Domestic Operations
and Export Sales
Revenues (with sales to unaffiliated customers and sales or transfers to
other geographic areas calculated separately), profitability and identifiable
assets of the Company are all attributable to the Company's operations in the
geographic area consisting of Texas, New Mexico, North Dakota, South Dakota,
Louisiana and Oklahoma (See Note 13 of the Financial Statements).
The Company has no foreign operations or export sales.
6
<PAGE> 9
Item 2. Properties.
Drilling Results
The following tables set forth the results (by number of wells) of Sage's
exploratory and development drilling (where the Company acted as operator) for
the periods indicated. In fiscal 1996, the Company had additional nonoperating
working interests in twelve (12) wells which are not noted below and three (3)
of which were dry. Due to the unpredictability of oil and gas exploration and
development, such results may not be indicative of the results which may be
achieved in the future.
EXPLORATORY WELLS*
<TABLE>
<CAPTION>
Oil Gas Dry Total
--- --- --- -----
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Year ended June 30,
1992............. -- -- -- -- 1 .75 1 .75
1993............. -- -- -- -- 1 1.00 1 1.00
1994............. -- -- -- -- 4 2.05 4 2.05
1995............. 3 1.50 3 1.50 2 1.50 8 4.50
1996............. 3 1.43 -- -- 1 .57 4 2.00
</TABLE>
DEVELOPMENT WELLS*
<TABLE>
<CAPTION>
Oil Gas Dry Total
--- --- --- -----
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Year ended June 30,
1992............. 23 16.74 -- -- -- -- 23 16.74
1993............. 20 13.92 -- -- -- -- 20 13.92
1994............. 15 9.86 1 .46 -- -- 16 10.32
1995............. 10 6.29 -- -- -- -- 10 6.29
1996............. 15 7.71 1 .40 1 .50 17 8.61
</TABLE>
As used in the industry, the term "exploratory well" refers to a well
drilled either (a) in search of a new and as yet undiscovered pool of oil or
gas or (b) with the hope of greatly extending the limits of a pool already
developed. A "development well" is a well drilled as an additional well to the
same reservoir as the producing wells on a lease, or drilled on an offset lease
usually not more than one drilling location away from a well producing from the
same reservoir.
As of June 30, 1996, there was one (1) gross (.80 net) developmental well
in the drilling stage.
- ------------------------------
* "Gross Wells" refers to the total wells in which Sage has a working
interest. "Net Wells" refers to the percentage of working interest owned by
Sage in the gross wells.
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<PAGE> 10
Oil and Gas Reserves
The total proved oil reserves of the Company increased during the fiscal
year ended June 30, 1996 due in large part to new discoveries and extensions.
This increase, along with revisions of previous estimates, was offset
somewhat by production during the year. New gas discoveries and extensions and
revisions of previous estimates were not sufficient to offset gas production
and sales of minerals-in-place. Proved oil and gas reserves of the Company
(all of which are located in New Mexico, South Dakota, and Texas) have been
estimated as of June 30, 1994, 1995 and 1996 by the Company. The estimates of
oil and gas reserves for each of the fiscal years have been based on the most
recently available oil and gas prices for such year.
ESTIMATED PROVED DEVELOPED AND UNDEVELOPED RESERVES
<TABLE>
<CAPTION>
Year Ended Year Ended Year Ended
June 30, 1996 June 30, 1995 June 30, 1994
------------- ------------- -------------
Net oil, Net Oil, Net Oil,
Condensate Condensate Condensate
and Natural Net and Natural Net and Natural Net
Gas Liquids Gas Gas Liquids Gas Gas Liquids Gas
(Mbbls) (Mmcf) (Mbbls) (MMcf) (Mbbls) (MMcf)
----- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Total proved reserves
developed and
undeveloped:
Beginning of period.. 6,178 32,132 5,325 30,280 5,966 29,055
Revisions of previous
estimates............ 377 2,353 (258) 2,807 (86) 4,388
Purchases of minerals-
in-place............. - - 1,391 2,400 - -
New discoveries and
extensions........... 847 2,681 723 1,970 687 2,273
Production............ (994) (5,037) (1,003) (5,325) (1,242) (5,436)
Sales of minerals-in-
place................ (7) (4,689) - - -
----- ------ ------ ------ ------ ------
End of period......... 6,401 27,440 6,178 32,132 5,325 30,280
===== ====== ====== ====== ====== ======
Proved developed
reserves:
Beginning of period... 3,640 25,273 3,465 23,572 3,428 19,739
===== ====== ====== ====== ====== ======
End of period......... 4,000 23,250 3,640 25,273 3,465 23,572
===== ====== ====== ====== ====== ======
</TABLE>
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<PAGE> 11
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, from deepening existing wells
to a different reservoir, or where a relatively large expenditure is required
to (a) recomplete an existing well or (b) install production or transportation
facilities for primary or improved recovery projects.
"Natural gas reserves" as used herein represent casinghead gas production
from oil wells and gas produced from gas wells.
Reserve estimates are based on industry accepted evaluation methods.
Reserves were determined for the producing properties by extrapolation of an
established production decline trend, where applicable, analogy with similar
wells, or by volumetric calculations using basic reservoir parameters such as
porosity, water saturation, net pay thickness and estimated areal extent of the
reservoir. Reserves for non-producing properties are generally determined by
volumetric calculations and/or by analogy with offset wells.
Discounted Net Future Cash Flows for
Fiscal Year Ended June 30, 1996
The discounted net future cash flows are based on estimated oil and gas
reserves as calculated by management's reserve study. The reserve study
contains imprecise estimates of quantities and rates of production of reserves.
Therefore, the standardized measure of discounted future net cash flows is not
necessarily reflective of the fair value of the Company's proved oil and gas
properties.
<TABLE>
<CAPTION>
Year Ended June 30, 1996
------------------------
(In Thousands)
<S> <C>
Estimated cash flows $187,135
Less:
Related estimated future
development and production
costs (71,509)
Estimated income taxes (35,091)
--------
Estimated net cash flows 80,535
Discount to reduce estimated
net cash flows to present
value (26,609)
--------
Discounted present value of
estimated net cash flows $ 53,926
========
</TABLE>
In computing the above future net revenues from proved reserves
attributable to the Company's interest, prices were based on the most recently
available average oil and gas prices received by lease for such year.
Operating expense information was based on the twelve-month period ended
May 31, 1996. These operating expenses, including direct expenses and
indirect overhead expenses, were held constant for the life of the properties.
Neither salvage values of the producing facilities, nor the cost of abandoning
the properties were included in the estimates. Severance and ad valorem taxes
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<PAGE> 12
were deducted in the lease reserves and economic projections at actual
percentage rates charged the previous year or standard state rates. Investments
for recompletions and undeveloped locations were included where applicable. No
deduction has been made for depletion or depreciation. In addition, indirect
costs such as general corporate overhead have not been considered.
In making these estimates, the Company utilized internal records for
property identification, working and revenue interests, ad valorem and
severance tax rates and operating expenses as compiled by the Company.
Production Volumes
The following table sets forth the oil and gas production of the Company
for the periods indicated.
<TABLE>
<CAPTION>
Years Ended June 30,
--------------------
1996 1995 1994 1993 1992
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Oil, Bbls.... 993,838 1,003,074 1,242,037 1,517,890 1,533,780
Gas, Mcf..... 5,037,305 5,325,469 5,436,173 6,305,158 4,780,999
</TABLE>
The Company's average sales prices during the fiscal years ended June 30,
1994, 1995, and 1996 were $15.49, $17.22 and $18.48 per barrel of oil and
$2.11, $1.69 and $2.03 per Mcf of gas, respectively. The average prices for
the Company's oil and gas sales for the month of June 1996 were $19.88 per
barrel of oil and $2.51 per Mcf of gas. At June 27, 1996, the posted price for
West Texas Intermediate crude oil was $19.50 per barrel. The range of natural
gas prices received by the Company for the month of June 1996 was $.53 to $5.30
per Mcf. The average sales prices per barrel of oil referred to herein do not
reflect the effect of payments made or received under the Company's commodity
floor agreement which was in effect for the last three months of the fiscal
year ended June 30, 1994 and first six months of the fiscal year ended June 30,
1995.
The average recurring production costs per barrel equivalent (gas
production is converted to barrel equivalents at 6 Mcf per barrel of oil) for
the fiscal years ended June 30, 1994, 1995 and 1996 were $2.86, $2.78 and $3.23
respectively.
Oil and Gas Properties
The following table sets forth the Company's total gross and net producing
oil and gas wells and its total gross and net developed and undeveloped acreage
as of the end of the periods indicated. Various sales of the Company's oil and
gas properties in fiscal 1993 resulted in a decrease in the Company's total
gross and net producing wells and its total gross and net developed acreage.
<TABLE>
<CAPTION>
Producing Wells Developed Undeveloped
--------------- --------- -----------
Oil Gas Acreage Acreage
--- --- ------- -------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
As of June 30,
1992.......... 578 449.98 51 46.06 58,496 48,344 53,969 44,491
1993.......... 248 181.28 47 41.75 54,399 43,718 53,099 44,883
1994.......... 214 152.05 45 36.46 54,807 43,400 60,072 43,463
1995.......... 293 186.22 47 39.10 57,215 44,897 211,566 124,887
1996.......... 282 189.72 22 15.15 46,973 34,202 201,200 142,785
</TABLE>
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<PAGE> 13
The following table sets forth the Company's gross and net developed and
undeveloped oil and gas acreage by state as of June 30, 1996. "Gross" refers
to the total number of acres in which the Company owns an interest and "net"
refers to the sum of the fractional interests it owns in the acres.
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage Acreage Total
------- ------- -----
Gross Net Gross Net Gross Net
Acres Acres Acres Acres Acres Acres
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
New Mexico........... 3,683 2,727 800 365 4,483 3,092
Louisiana............ - - 987 949 987 949
Texas
Permian Basin...... 6,396 4,243 34,707 24,557 41,103 28,800
South Texas........ 36,574 26,947 47,071 32,857 83,645 59,804
North Dakota......... - - 70,204 49,214 70,204 49,214
South Dakota......... 320 285 47,437 34,843 47,757 35,128
------ ------ ------- ------- ------- -------
Total................ 46,973 34,202 201,206 142,785 248,179 176,987
====== ====== ======= ======= ======= =======
</TABLE>
Supply Contracts and Investment Reserves
The Company has no long-term supply or similar agreements with foreign
governments or authorities. The Company has no share of reserves or
investments which are accounted for by the equity method.
Contract Obligations
The Company is not obligated to provide a fixed or determinable quantity
of oil or gas in the future under any existing contracts or agreements.
Title to Properties
As is customary in the oil and gas industry, only a perfunctory title
examination is conducted at the time the properties believed to be suitable for
drilling operations are acquired by the Company. Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative
work is performed with respect to any significant title defects before
proceeding. A thorough title examination has been performed with respect to
substantially all of the Company's producing properties. The Company believes
that the title to its properties is good and indefeasible in accordance with
standards generally accepted in the oil and gas industry, subject to such
exceptions which, in the opinion of counsel employed in the various areas in
which Sage conducts its exploration activities, are not so material as to
detract substantially from the use of such property. The properties owned by
the Company are subject to royalty, overriding royalty and other outstanding
interests customary in the industry. The properties are also subject to
burdens such as liens to TCB under the Restated Credit Agreement and incident
to operating agreements, current taxes, development obligations under oil and
gas leases and other encumbrances, easements and restrictions. The Company
does not believe that any of these burdens materially interfere with the use of
the properties.
Drilling Rigs
The Company currently owns four drilling rigs. During fiscal 1995 the
Company sold nine of its rigs and purchased two additional rigs. In fiscal 1996
the Company sold three additional rigs. Because of decreased activity in
11
<PAGE> 14
the contract drilling business, as of June 30, 1996, all but one of the rigs,
(Rig 15), have been withdrawn from immediate availability to outside parties
and stacked in the Company's equipment yards in West Texas. Rig 15 has been
retrofitted to drill horizontal wells and is presently drilling in the Austin
Chalk Area of South Texas. The following table sets forth certain information
with respect to all of the Company's drilling rigs as of year end.
<TABLE>
<CAPTION>
Rig # Draw Works Depth Capacity
----- ---------- --------------
<S> <C> <C>
Rig 3 National 370 9,000'
Rig 15 Brewster N-75 14,500'
Rig 18 National 610 13,000'
Rig 22 National 610 13,000'
</TABLE>
The Company also sold its six service rigs used for completion and
remedial work in May 1996 and now contracts for this work.
Item 3. Legal Proceedings.
On June 30, 1996 and thereafter through the date of this report on Form
10K, the Company was not a party to, nor were its assets subject to any
material pending legal proceedings (other than ordinary and routine litigation
incidental to its business).
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to the sole shareholder of the Company during
the fourth quarter of fiscal year ended June 30, 1996.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Description of Common Stock
The authorized capital stock of the Company consists of 12,000 shares of
Common Stock, $.01 par value, of which 1,399 shares were outstanding on June
30, 1996. Holders of Common Stock are entitled to one vote per share on all
matters submitted to a vote of stockholders. Cumulative voting for election of
directors is not permitted; therefore, the holders of a majority of shares of
Common Stock are able to elect all of the directors. The Common Stock carries
no preemptive rights and is not convertible, redeemable or assessable. The
holders of Common Stock are entitled to receive such dividends as may be
declared by the Board of Directors out of funds legally available therefore.
Presently, all of such shares are held of record by Sage Acquisition Company.
The Company presently acts as transfer agent for the common stock.
12
<PAGE> 15
Dividends
The Company may consider the payment of cash dividends (in accordance
with applicable law and upon obtaining any necessary consents under its credit
facility) in the future. The payment of such dividends, if any, will be
determined by the Company as general business conditions, the development of
the Company's business, the financial condition of the Company and other
factors may warrant. The Company paid cash dividends to its sole shareholder
of $320,000 in each of fiscal 1994 and fiscal 1995.
Convertible Subordinated Debentures
On October 21, 1980, the Company issued $30,000,000 of 8 1/2% convertible
subordinated debentures (the "Debentures"), of which $18,030,000 is
outstanding at June 30, 1996. The Debentures are convertible into cash at the
rate of $260 per $1,000 face value of the Debentures.
The Debentures are traded on the American Stock Exchange under the symbol
"SAG.A." The following table sets forth the range of the high and low sales
prices for each quarterly period during the last two fiscal years:
<TABLE>
<CAPTION>
Sales
-----
High Low
---- ---
<S> <C> <C>
Quarter Ended:
September 30, 1994......... 80 74
December 31, 1994.......... 82 74 1/4
March 31, 1995............. 82 78 1/4
June 30, 1995.............. 84 1/2 80 1/2
September 30, 1995......... 86 82 1/2
December 31, 1995.......... 85 3/4 83
March 31, 1996............. 87 85
June 30, 1996.............. 90 85 1/4
</TABLE>
The transfer agent for the Debentures is Texas Commerce Bank - National
Association. On June 30, 1996, there were approximately 108 holders of record
of the outstanding Debentures.
13
<PAGE> 16
Item 6. Selected Financial Data.
<TABLE>
<CAPTION>
SAGE ENERGY COMPANY
(In thousands Except Per Share Data)
Years Ended June 30,
---------------------------------------------------
1996 1995 1994 1993 1992
---------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenues $31,536 $ 28,803 $32,342 $ 43,399 $ 36,896
Income before extra-
ordinary item and
cumulative effect of
change in accounting $ 4,385 $ 1,248 $ 870 $ 6,735 $ 2,868
Net income $ 4,426 $ 1,248 $ 5,261 $ 6,735 $ 2,868
Net cash provided by
operating activities $13,546 $ 9,241 $14,010 $ 21,917 $ 15,364
Net cash used in
investing activities $(8,184) $(10,959) $(9,804) $ (4,539) $(16,839)
Net cash used in
financing activities $ (500) $ (370) $(5,137) $(12,994) $ (2,575)
Income before extra-
ordinary item and
cumulative effect of
change in accounting
per common share $ 3,134 $ 892 $ 622 $ 4,814 $ 2,050
Net income per
common share $ 3,163 $ 892 $ 3,761 $ 4,814 $ 2,050
</TABLE>
In fiscal 1994, the Company recorded an extraordinary item for the
purchase and retirement of Debentures and a cumulative effect of change in
accounting for the adoption of Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes" of approximately $4,250,000. These items are
more fully described in Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations." In fiscal 1994, the Company
purchased and retired $1,234,000 face amount of the Debentures which resulted in
an extraordinary gain net of income taxes of $141,000. In fiscal 1996, the
Company purchased and retired $500,000 face amount of the Debentures which
resulted in an extraordinary gain net of income taxes of $41,000.
___________________________________________________________________
14
<PAGE> 17
<TABLE>
<CAPTION>
Selected Balance Sheet Data
June 30,
-----------------------------------------------
1996 1995 1994 1993 1992
-----------------------------------------------
<S> <C> <C> <C> <C> <C>
Current assets $19,787 $11,540 $13,855 $16,675 $13,344
Current liabilities $10,086 $ 5,285 $ 6,761 $12,491 $15,600
Working capital $ 9,701 $ 6,254 $ 7,094 $ 4,184 $(2,256)
(deficit)
Total assets $50,175 $41,791 $43,486 $49,632 $56,373
Bonds payable $18,030 $18,530 $18,580 $19,814 $19,814
Long-term debt, net of
current portion $ - $ - $ - $ - $ 7,375
Stockholder's equity $18,236 $13,810 $12,882 $ 7,941 $ 3,158
</TABLE>
The Company has paid cash dividends of $1,800,000, $500,000, $320,000 and
$320,000 in fiscal years June 30, 1991, 1992, 1994 and 1995 respectively. The
Company paid no cash dividends in the fiscal year ended June 30, 1996.
Item 7. Managements's Discussion and Analysis of Financial Condition and
Results of Operations.
Financial Position
Fiscal Year Ended June 30, 1996 and Fiscal Year Ended June 30, 1995
The Company's current ratio was 1.96 to 1 at the end of the fiscal year
ended June 30, 1996 as compared to the June 30, 1995 current ratio of 2.18 to
1. Cash on hand at the end of the 1996 fiscal year was $7,966,000 and
$3,104,000 at June 30, 1995.
During the fiscal year ended June 30, 1996, the Company used cash from
operations to, among other things, drill and rework wells, acquire leases and
related properties for drilling, acquire producing properties, pay estimated
Federal income taxes related to fiscal 1996 ($1,498,000), repurchase debentures
($430,000) and pay bonuses to four of its officers and directors ($520,000).
Specifically, the Company spent approximately $12,158,000 for capital
expenditures as described below.
The increase in trade accounts receivable from $1,827,000 in June 1995 to
$3,561,000 in June 1996 was principally due to an increase of $1,434,000 in
related party accounts receivable of certain officers and directors
attributable to their participation in certain wells drilled by the Company.
Oil and gas sales receivables increased mainly due to increased oil and gas
prices and production volumes in June 1996 versus June 1995.
The Company's net fixed assets increased during fiscal 1996 primarily as
a result of additions to the Company's producing oil and gas properties which
resulted from drilling and recompletion work and from acquisitions of leases.
This increase was partially offset by depletion and depreciation charges of
$7,537,000 and by write-offs of plugged and abandoned properties, non
productive properties, expired leases of approximately $2,417,000, sales of
three drilling rigs and six serivce units and related equipment (approximately
15
<PAGE> 18
($243,000) and the sale of the Company's Oklahoma gas properties ($438,000) and
North Dakota properties ($443,000). (See discussion under the heading
"Liquidity and Capital Resources").
Only one of the Company's drilling rigs was active at the end of fiscal
1996. Until the competition in the drilling market abates and drilling rates
increase, the Company does not intend to have substantial participation in the
contract drilling industry.
During March, 1995, the Financial Accounting Standards Board issued
Statement of Financial accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
The Company is required to adopt Statement 121 for the fiscal year beginning
July 1, 1996. Statement 121 requires that long-lived assets and certain
identifiable intangibles to be held and used by an entity be reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Furthermore, Statement 121
also requires that long-lived assets and certain indentifiable intangibles to
be disposed of be reported at the lower of carrying amount or fair value less
cost to sell, except for assets that are covered by APB Opinion 30. The
Company has not completed all of the complex analysis required to estimate the
impact of the new Statement, however, the adoption of Statement 121 is not
expected to have any adverse impact on the Company's financial position or the
results of operations at the time in which it is adopted.
Comparison of Years Ended
June 30, 1996, 1995 and 1994
As noted above, the current ratio at the end of fiscal years 1996 and
1995 was 1.96 to 1 and 2.18 to 1, respectively. The current ratio at the end
of fiscal year 1994 was 2.05 to 1. The Company had $7,966,000 in cash at the
end of fiscal 1996 and no short-term borrowings. The Company had $3,104,000 in
cash at the end of fiscal 1995 and no short-term borrowings. Cash at the end of
fiscal 1994 was $5,192,000 and no short-term borrowings. Cash was consumed in
fiscal 1996 for the reasons stated above. During the fiscal year ended June 30,
1995, the Company used cash from operations to, among other things, drill and
rework wells, acquire leases and related properties for drilling, acquire
producing properties, two drilling rigs, pay estimated Federal income taxes
related to fiscal 1995 ($2,200,000), pay a dividend to its sole shareholder
($320,000) and pay bonuses to four of its officers and directors ($400,000). In
fiscal 1994, cash from operations was used to, among other things, drill and
rework wells, acquire leases and related properties for drilling, reduce
short-term debt, repurchase debentures, and pay estimated Federal income taxes
for fiscal 1994, pay a dividend to the Company's sole shareholder and pay
bonuses to four of the Company's officers and directors. There were no current
maturities of long-term debt at June 30, 1994, June 30, 1995 or June 30, 1996.
Net fixed assets increased in fiscal 1996 for the reasons stated above.
The Company's net fixed assets increased during fiscal 1995 primarily as a
result of additions to the Company's producing oil and gas properties which
result from drilling and recompletion work, and from acquisitions of leases and
producing properties and two drilling rigs. This increase was partially offset
by depletion and depreciation charges of $8,638,000, and by write-offs of
plugged and abandoned properties, non productive properties, expired leases of
approximately $2,955,000 and sales of nine drilling rigs (approximately
$701,000) (See discussion under the heading "Liquidity and Capital Resources").
Only one of the Company's drilling rigs was active at the end of fiscal 1995.
Statement of Financial Accounting Standards No. 109 (FAS 109),
"Accounting
16
<PAGE> 19
for Income Taxes", required a change from the deferred method under APB Opinion
11 to the asset and liability method of accounting for income taxes. Under the
asset and liability method of FAS 109, deferred income taxes are recognized for
the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. Under FAS
109, the effect on deferred taxes of a change in tax rates is recognized in
income in the period that includes the enactment date. The Company has applied
the provisions of FAS 109 in fiscal 1994 without restating prior years'
financial statements. The adoption of FAS 109 reduced the net deferred tax
liability by approximately $4,250,000; this amount has been reported separately
as the cumulative effect of the change in the method of accounting for income
taxes in the statement of operations for the year ending June 30, 1994.
Results of Operations
June 30, 1996 and June 30, 1995
The Company's oil and gas revenues were higher in fiscal 1996 than the
prior comparable fiscal year primarily as a result of higher oil and gas
prices. As compared to the prior comparable year, lower oil and gas production
had a negative effect on revenue of approximately $756,000 and higher oil and
gas prices had a positive effect of approximately $3,096,000. Production was
lower primarily as a result of decreased drilling acitivies and the natural
decline in the Austin Chalk Trend Area where a majority of the Company's
horizontal drilling activity takes place and due to the sale of the Company's
Oklahoma gas properties effective August 1995. Average oil prices were higher
than the prior comparable year, $18.48 vs. $17.22.
The Company sold three (3) of its drilling rigs for a net consideration
of approximately $610,000 in fiscal 1996 reflecting a gain of $447,000 (before
income tax effect) which has been included in interest and other income. The
Company now owns four (4) rigs and has no current plans for future rig sales.
In May 1996 the Company sold its six (6) well servicing units and related
vehicles for $779,250, reflecting a gain of approximately $700,000 before
income tax effect. The Company will now contract with third parties for its
well servicing needs. Additionally, the Company sold its Oklahoma gas
properties in August 1995 for $925,000 which generated a gain of $489,000
before tax effect. Fiscal 1995 results reflected a gain of $1,059,000 (before
income tax effect) on the sale of nine (9) drilling rigs.
Nonproductive exploration and property abandonment costs decreased as
compared to a year ago due primarily to the decreased write-offs of
nonproductive exploration, property abandonment and expired leases.
Interest expense in fiscal 1996 decreased by approximately $34,000 as
compared to the prior comparable year due primarily to decreased debt. The
Company reacquired and cancelled $500,000 in principal amount of its
outstanding 8 1/2% Subordinated Debentures due 2005 (the "Debentures") in
fiscal 1996 and $50,000 in fiscal 1995 thus decreasing the annual interest
expense attributable to the Debentures by $46,750. The Company may incur
additional indebtedness under its revolving line of credit described below to
finance its exploration, development, and possible property acquisition
activities. Interest expense will further increase during the periods in
which such indebtedness is incurred and outstanding. However, see "Liquidity
and Capital Resources" regarding the Company's plan to redeem $7,000,000 of
outstanding debentures and such redemptions' effect on the Company's future
interest expense.
17
<PAGE> 20
Expenses related to depreciation, depletion, and amortization costs
decreased from the prior year primarily as a result of, among other things,
lower production and a lower depletable base. Geological and geophysical costs
decreased due to the Company's decreased exploration activities and 3-D seismic
activities.
In December 1995 the Company declared bonuses to four of its officers and
directors of approximately $520,000. The same period a year ago reflected
bonuses of $400,000.
The Company completed nineteen (19) new producing wells as operator in
fiscal 1996 and re-entered, recompleted, reworked or participated in a number
of others. Substantially all of the Company's revenues and cash derived from
operations came from oil and gas sales. The Company's profitability depends in
large part on its ability to find or purchase and efficiently produce oil and
gas reserves. In addition, profitability is heavily affected by oil and gas
prices.
Results of Operations
June 30, 1995 and June 30, 1994
The Company's oil and gas revenues were lower in fiscal 1995 than the
prior comparable fiscal year primarily as a result of lower oil production.
Production was lower primarily as a result of decreased drilling activities and
the natural decline in the Austin Chalk Trend area where a majority of the
Company's horizontal drilling takes place. As compared to the prior comparable
year, lower oil production had a negative effect on revenue of approximately
$4,114,000, lower gas prices of approximately $2,290,000, and lower gas
production of $187,000. Average oil prices were higher in fiscal 1995 than the
prior comparable year, $17.22 vs. $15.49, which amounts to an approximate
$2,140,000 offset to the above decreases. The Company sold nine (9) of its
drilling rigs for a total consideration of approximately $1,760,000 in fiscal
1995 reflecting a gain of $1,059,000 (before income tax effect) which has been
included in interest and other income.
Production costs were less in fiscal 1995 than the prior fiscal year
primarily due to lower production. Nonproductive exploration and property
abandonment costs increased as compared to a year ago due primarily to the
increased write-offs of nonproductive exploration, property abandonment and
expired leases.
Interest expense in fiscal 1995 decreased by approximately $191,000 as
compared to the prior comparable year due primarily to decreased debt. The
Company made a final payment on March 31, 1994 of $1,382,703 on its bank debt
thereby eliminating its bank debt at such time. The Company also reacquired
and cancelled $1,234,000 in principal amount of its outstanding 8 1/2%
Subordinated Debentures due 2005 (the" Debentures") in fiscal 1994 and $50,000
in fiscal 1995 thus decreasing the annual interest expense attributable to the
Debentures by $109,140.
The Company will incur ongoing interest expense related to its
outstanding indebtedness presently comprised of its outstanding Debentures.
Should the Company incur additional bank indebtedness to finance its
exploration, development, and possible property acquisition activities,
interest expense will further increase during the periods in which such
indebtedness is incurred and outstanding.
Expenses in fiscal 1995 related to depreciation, depletion, and
amortization costs decreased from the prior year as a result of, among other
things, lower production and a lower depletable base along with increased
18
<PAGE> 21
reserves. Geological and geophysical costs increased due to the Company's
increased exploration activities and 3-D seismic activities.
In fiscal 1994, the cumulative effect of change in accounting principle
of $4,250,000 relating to the adoption of FAS 109 was reported. No such item
occurred in fiscal 1995.
On December 6, 1994 the Company declared a cash dividend of $320,000 or
$228.73 per share to its sole shareholder. The Company's sole shareholder is
owned and controlled by Michael Amini, Rex Amini, Ronald Amini, and Jesse
Minor. Fiscal year 1994 also reflected a dividend of $320,000.
The Company completed sixteen (16) new producing wells as operator in
fiscal 1995 and re-entered, recompleted, reworked or participated in a number
of others. Substantially all of the Company's revenues and cash derived from
operations came from oil and gas sales. The Company's profitability depends in
large part on its ability to find or purchase and efficiently produce oil and
gas reserves. In addition, profitability is heavily affected by oil and gas
prices.
Liquidity and Capital Resources
The Company's long-term debt at June 30, 1996 consisted of its
convertible Debentures which had an aggregate outstanding balance of
$18,030,000. During fiscal 1996 the Company acquired and cancelled debentures
with aggregate principal of $500,000 thus reducing its indebtedness by such
amount. Debentures totaling an additional $332,000 in principal were
reacquired and cancelled in July 1996. No sinking fund payments are currently
required under the Debentures and, absent further acquisitions by the Company
of Debentures, no sinking fund payments will be due until 1998. The Debentures
are convertible into cash at the rate of $260 per every $1,000 in principal
amount of Debentures.
Under the Company's Restated Credit Agreement with Texas Commerce Bank,
as amended, Company may borrow up to $3,000,000 under the revolving credit
facility until June 30, 1997 (the "Termination Date"). On the Termination Date
(subject to acceleration for certain events), any outstanding balance under the
Restated Credit Agreement is scheduled to be fully paid. However, such
repayment may be accelerated by the Company based upon availability of cash or
other appropriate uses of cash, and other factors in its discretion. As of
June 30, 1996, the Company had not drawn funds under the revolving credit
facility. The Company presently has no indebtedness under the Revolving Credit
Agreement.
Management of the Company deems it important to acquire additional
properties with longer life reserves at suitable prices, however, the Company
also on a routine basis considers sales of properties and other assets at
appropriate prices. The proceeds from any such sales could be used for a
variety of purposes, including property acquisitions, acquisitions of
outstanding Debentures, and repayment of bank debt, if any. In this regard, in
the first quarter of fiscal 1997 the Company sold acreage in North Dakota for
approximately $2,024,000.
The Company also recently announced the cancellation of a program to use
up to $2 million to repurchase certain of its outstanding Debentures in the
open market or in privately negotiated transactions at prices and at times
deemed suitable by management (the "Program"). Debentures with an aggregate
principal amount of $500,000 were repurchased under the Program.
In the first quarter of fiscal 1996, the Company sold all of its
producing properties in the state of Oklahoma for approximately $925,000. In
March 1996
19
<PAGE> 22
the Company sold at auction three of its drilling rigs for approximately
$610,000. In May the Company sold its six well servicing units and related
vehicles for $779,250. The Company will now contract with third parties for
all of its well servicing needs.
In this regard, the Company substantially decreased its contract drilling
operations in 1988 and subsequently moved substantially all of its drilling
equipment to Company-owned yards in West Texas. In the last six (6) months of
fiscal 1993 the Company began contract drilling operations and continued these
operations in fiscal 1994, 1995 and 1996 with one drilling rig. At the present
time the Company does not expect its contract drilling business to be
significant. If the Company were to significantly reenter the contract drilling
business, its principal market would likely be the Permian Basin of West Texas
and Southeastern New Mexico. This market is highly fragmented and extremely
competitive.
For some time the Company has aggressively pursued exploration and
development activities (particularly horizontal drilling activities) and
incurred expenditures attendant thereto. At the time such expanded activities
are undertaken, they may result in a short-term negative impact on capital
resources and liquidity even if they are ultimately successful. In part, as a
result of such activities the Company entered into the Restated Credit
Agreement and in the past borrowed funds under the revolving credit facility.
Although the funds have since been repaid, the Company anticipates that
additional funds may be borrowed under the revolving credit facility for
drilling or producing property acquisitions at a later date.
Absent additional acquisitions of producing properties, revenues can be
expected to decline due to a decrease in production resulting from decreased
drilling activities and the natural decline in the Austin Chalk Trend area
where a majority of the Company's horizontal drilling takes place. Wells in
the Austin Chalk Trend area have traditionally exhibited significant initial
production followed by a more rapid decline than other areas. In addition,
reservoir characteristics make extrapolating future production and revenues
from wells in this area difficult. Production costs may also decline as a
result of decreased production. Revenue will also decline in response to
negative changes in oil and gas prices.
The Company intends to continue on a modified basis its exploration and
development activities in the Austin Chalk and in other areas. Such activity
will in large part be based upon availability of capital and economic prospects
and with consideration for continued volatility in oil and gas prices. The
Company will also continue to seek undeveloped leasehold acreage and to
consider various proposals for the acquisition of producing properties within
such parameters. Further, the Company will expend funds to implement various
enhanced recovery techniques within such parameters and continue its horizontal
drilling activities with industry partners and on its own. The Company has
also begun to pursue exploration opportunities which it has identified through
the use of computer technology and 3-D seismic. The Company anticipates that
its increased exploration activities will continue to have a negative impact on
its liquidity. The Company anticipates utilizing internally generated funds
and, if necessary and available, funds under the Restated Credit Agreement to
continue such activities.
The Company will consider the payment of cash dividends (in accordance
with applicable law and the provisions of the Restated Credit Agreement as the
same may be modified or amended from time to time) in the future. The payment
of such dividends will be determined by the Company as general business
conditions, the development of the Company's business, the financial condition
of the Company, and other factors may warrant. Any such payment of dividends
would adversely affect capital resources and liquidity. In December 1995, the
Company determined to pay bonuses to four of its officers and directors
aggregating $520,000. Based on the formula compensation plan for senior
executive officers adopted by the Board of Directors, commencing July 1, 1996,
20
<PAGE> 23
total compensation (including bonuses) for such senior executive officers is
estimated to be approximately $2,126,000 for fiscal 1997.
On a routine basis, certain of the Company's officers obtain working
interests in certain of the Company's wells. Generally, the Company will
advance monies as operator on behalf of such persons with respect to their pro
rata share of drilling, equipping, leasehold and operating costs. As of June
30, 1996, the Company had receivables from such persons in the aggregate amount
of $2,082,000. Although the Company may effectively offset such amounts
against sums due such persons with respect to their working interests
($1,706,000 at June 30, 1996), such costs, until recouped, can adversely affect
the Company's liquidity.
The Company elected not to make a sinking fund payment in fiscal 1996
(which would ordinarily have been due at least one business day before October
15, 1995) for the purpose of setting aside funds to retire its outstanding
Debentures. The Company is not required to make such payment, which would
ordinarily be a sum in cash sufficient to retire by redemption $1,500,000
principal amount of the Debentures, because it reacquired and cancelled a
sufficient number of Debentures to eliminate the sinking fund payment required
on such date. As of June 30, 1996, the Company has reacquired and cancelled
Debentures in the face amount of $11,970,000, which could, if the Company so
elects, result in the deferral of sinking fund payments until 1998. $500,000
in principal amount of Debentures was reacquired in November 1995 for an
aggregate consideration of $430,000. An additional $332,000 in principal
amount of debentures was reacquired in July 1996 for $298,800.
The Company recently announced that it intends to redeem up to $7,000,000
in principal amount of its outstanding debentures. Such redemption is to be
carried out in accordance with the terms of such securities and is to be
effected at a price equal to 100% of the principal amount of each debenture so
redeemed. It is expected that following the redemption, the aggregate
principal amount of the outstanding debentures would be reduced to
approximately $11,000,000. It is expected that although the redemption will
significantly and adversely affect the Company's liquidity in the short term,
the Company's liquidity, over time, will be enhanced as a result of the
elimination of approximately $595,000 in annual interest payments. In
addition, as described above, absent such a redemption (or other acquisition
and retirement of debentures), the Company would be required to make sinking
fund payments commencing in fiscal 1998.
Liquidity is heavily affected by oil and gas prices. The Company cannot
predict with accuracy the volatility or parameters of future oil or gas prices.
Further, should the value of the Company's assets decrease (as a result of
declines in oil and gas prices or other factors), any future bank borrowings
may be subject to mandatory prepayment.
Although certain of the transactions described herein may have adversely
affected liquidity and capital resources, management of the Company currently
believes that (based on present pricing scenarios) its liquidity and capital
resources are generally adequate. However, as a result of the exploration and
development activities and the possible acquisition of properties with
long-life reserves, it is possible that the Company will utilize other
borrowings under the revolving credit facility to finance its activities.
The Company maintains an internal compliance program to monitor its
compliance with environmental laws and employs an independent consulting firm
to inspect its wellsites to determine whether the Company has any clean-up
obligations. Aside from a site in California for which the Company has
21
<PAGE> 24
reserved $200,000, the Company is not aware of any other potential clean-up
obligations which would have a material effect on its financial condition or
results of operations.
Inflation
The rate of inflation has had no significant effect on the Company's
operations for some time.
- -------------------------
22
<PAGE> 25
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements and Schedules
<TABLE>
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Report.................................. 24
Financial Statements:
Balance Sheets, June 30, 1996 and 1995................... 25
Statements of Operations, Years Ended June 30, 1996,
1995 and 1994............................................ 27
Statements of Stockholder's Equity,
Years Ended June 30, 1996, 1995 and 1994................. 28
Statements of Cash Flows, Years Ended June 30, 1996
1995 and 1994............................................ 29
Notes to Financial Statements............................ 30
</TABLE>
Schedules: There are no financial schedules as the required information
is inapplicable or the information is presented in the Financial Statements or
related Notes.
23
<PAGE> 26
Independent Auditors' Report
The Board of Directors
Sage Energy Company:
We have audited the financial statements of Sage Energy Company as listed in
the accompanying index. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Sage Energy Company as of June
30, 1996 and 1995, and the results of its operations and its cash flows for
each of the years in the three-year period ended June 30, 1996, in conformity
with generally accepted accounting principles.
As discussed in Note 1 to the financial statements, the Company changed its
method of accounting for income taxes in 1994 to adopt the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes."
KPMG Peat Marwick LLP
San Antonio, Texas
September 27, 1996
24
<PAGE> 27
SAGE ENERGY COMPANY
Balance Sheets
(In Thousands)
Assets
<TABLE>
<CAPTION>
June 30, June 30,
1996 1995
----------- -----------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 7,966 $ 3,104
Accounts receivable:
Trade ($ 2,082 in 1996 and $648 in 1995 3,561 1,827
from related parties - Note 2)
Oil and gas sales 6,839 4,156
Federal income tax refund - 712
Inventories - well and production
equipment, at cost 1,333 1,483
Prepaid expenses 88 258
----------- -----------
Total current assets 19,787 11,540
----------- -----------
Property, plant and equipment, at cost
(Notes 6 and 9):
Producing oil and gas properties
(successful efforts method) 119,550 118,504
Undeveloped properties 4,812 4,044
Drilling equipment 5,096 9,673
Other 3,038 4,350
----------- -----------
132,496 136,571
Less accumulated depreciation and
depletion (102,355) (106,605)
----------- -----------
30,141 29,966
----------- -----------
Other assets, at cost, net of accumulated
amortization 247 285
----------- -----------
$ 50,175 $ 41,791
=========== ===========
</TABLE>
See accompanying notes to the financial statements.
25
<PAGE> 28
SAGE ENERGY COMPANY
Balance Sheets (Continued)
(In Thousands Except Share Data)
Liabilities and Stockholder's Equity
<TABLE>
<CAPTION>
June 30, June 30,
1996 1995
-------- --------
<S> <C> <C>
Current liabilities:
Accounts payable, trade $ 2,765 $ 1,423
Accrued liabilities (Note 4) 6,331 3,665
Federal income taxes payable 555 -
State income taxes payable (Note 10) 435 197
-------- --------
Total current liabilities 10,086 5,285
Bonds payable (Note 5) 18,030 18,530
Deferred income taxes 3,823 4,166
-------- --------
Total liabilities 31,939 27,981
-------- --------
Stockholder's equity (Note 7):
Common stock, $.01 par value; authorized
12,000 shares; issued 1,399 shares - -
Additional paid-in capital 14 14
Retained earnings 18,222 13,796
-------- --------
Total stockholder's equity 18,236 13,810
Contingent liabilities (Note 17)
-------- --------
$ 50,175 $ 41,791
======== ========
</TABLE>
See accompanying notes to the financial statements.
26
<PAGE> 29
SAGE ENERGY COMPANY
Statements of Operations
(In Thousands Except Per Share and Share Data)
<TABLE>
<CAPTION>
Years Ended June 30,
---------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 27,815 $ 25,675 $ 30,089
Contract drilling 1,836 1,632 1,842
Interest and other income, net (Note 9) 1,885 1,496 411
-------- -------- --------
Total revenues 31,536 28,803 32,342
-------- -------- --------
Costs and expenses:
Oil and gas operations:
Production taxes 1,321 1,286 1,361
Production costs 7,075 6,826 8,378
Nonproductive exploration and
property abandonment costs 2,501 3,005 1,980
-------- -------- --------
10,897 11,117 11,719
Contract drilling direct costs 1,398 1,358 1,242
Depreciation, depletion and amortization 7,567 8,670 11,643
Geological and geophysical 430 1,314 1,088
General and administrative 3,093 3,186 3,739
Interest 1,545 1,579 1,770
-------- -------- --------
Total costs and expenses 24,930 27,224 31,201
-------- -------- --------
Income from operations before income taxes 6,606 1,579 1,141
Income tax expense (benefit) (Note 10):
Federal - current 2,371 1,259 415
State - current 193 169 104
Federal - deferred (343) (1,097) (248)
-------- -------- --------
2,221 331 271
-------- -------- --------
Income before extraordinary item and cumulative
effect of change in accounting for income taxes 4,385 1,248 870
Extraordinary item-debenture retirement
(net of Federal income taxes of $19 in 1996 and $73
in 1994 - Note 5) 41 - 141
-------- -------- --------
Income before cumulative effect of
change in accounting 4,426 1,248 1,011
Cumulative effect of change in accounting (Note 10) - - 4,250
-------- -------- --------
Net income $ 4,426 $ 1,248 $ 5,261
======== ======== ========
Net income per common share:
Income before extraordinary item and cumulative
effect of change in accounting $ 3,134 $ 892 $ 622
Extraordinary item 29 - 101
Cumulative effect of change in accounting - - 3,038
-------- -------- --------
$ 3,163 $ 892 $ 3,761
======== ======== ========
Weighted average common shares outstanding 1,399 1,399 1,399
======== ======== ========
</TABLE>
See accompanying notes to the financial statements.
27
<PAGE> 30
SAGE ENERGY COMPANY
Statements of Stockholder's Equity
(In Thousands Except Share Data)
<TABLE>
<CAPTION>
Common Stock Additional
-------------- Paid-In Retained
Shares Amount Capital Earnings Total
----- ------ -------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Balances June 30, 1993 1,399 $ - $ 14 $ 7,927 $ 7,941
Cash dividend - (Note 7) - - - (320) (320)
Net income - - - 5,261 5,261
----- ------ -------- ---------- ----------
Balances June 30, 1994 1,399 - 14 12,868 12,882
Cash dividend - (Note 7) - - - (320) (320)
Net income - - - 1,248 1,248
----- ------ -------- ---------- ----------
Balances June 30, 1995 1,399 - 14 13,796 13,810
Net income - - - 4,426 4,426
----- ------ -------- ---------- ----------
Balances June 30, 1996 1,399 $ - $ 14 $ 18,222 $ 18,236
===== ====== ======== ========== ==========
</TABLE>
See accompanying notes to the financial statements.
28
<PAGE> 31
SAGE ENERGY COMPANY
Statements of Cash Flows
(In Thousands)
<TABLE>
<CAPTION>
Years Ended June 30,
---------------------------------
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 4,426 $ 1,248 $ 5,261
--------- --------- ---------
Adjustments to reconcile net income to
net cash provided by operating activities:
Extraordinary item before Federal
income taxes 60 - 214
Depreciation, depletion and
amortization 7,567 8,670 11,643
Net loss on asset dispositions 420 1,669 1,273
Deferred income taxes (343) (1,097) (4,124)
Changes in current assets and
liabilities:
Accounts receivable (4,417) 1,407 2,154
Federal income taxes receivable 712 (699) (12)
Inventories 150 (286) (198)
Prepaid expenses 170 (195) (54)
Accounts payable 1,342 (360) (992)
Accrued liabilities 2,666 (1,210) (608)
Federal income taxes payable 555 - -
State income taxes payable 238 94 (547)
--------- --------- ---------
Total adjustments 9,120 7,993 8,749
--------- --------- ---------
Net cash provided by
operating activities 13,546 9,241 14,010
--------- --------- ---------
Cash flows from investing activities:
Proceeds from sales of assets 3,974 2,993 930
Capital expenditures (12,158) (13,952) (10,734)
--------- --------- ---------
Net cash used in investing
activities (8,184) (10,959) (9,804)
--------- --------- ---------
Cash flows from financing activities:
Long-term debt retired (500) (50) (1,234)
Bank debt repayments - - (3,583)
Dividend paid - (320) (320)
--------- --------- ---------
Net cash used in
financing activities (500) (370) (5,137)
--------- --------- ---------
Net increase (decrease)in cash and cash equivalents 4,862 (2,088) (931)
Cash and cash equivalents:
Beginning of year 3,104 5,192 0
--------- --------- ---------
End of year $ 7,966 $ 3,104 $ (931)
========= ========= =========
</TABLE>
See accompanying notes to the financial statements.
29
<PAGE> 32
SAGE ENERGY COMPANY
Notes to Financial Statements
1. Summary of Significant Accounting Policies
General
Sage Energy Company (Company) is engaged in the exploration,
development, production and sale of oil and gas. Effective January 9, 1990,
the Company became a wholly owned subsidiary of Sage Acquisition Company. On
December 31, 1991, the Company reincorporated in the state of Delaware.
The Company's operations are concentrated principally in Texas and
Southeastern New Mexico and it holds some undeveloped acreage in North Dakota,
South Dakota and Louisiana. The principal markets for the Company's products
are by sale of such products at the wellhead to appropriate gathering companies
operating in the geographic area of the Company's production. The ability of
the Company to market oil and gas depends on numerous factors including the
availability of other domestic and foreign production, the marketing of
competitive fuels, the proximity and capacity of pipelines, fluctuations in
supply and demand, the effect of Federal and state regulations and national and
worldwide economic and political conditions.
Use of Estimates
Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities and the disclosure of
contingent assets and liabilities to prepare these financial statements in
conformity with generally accepted accounting principles. Actual results could
differ from those estimates.
Contract Drilling in Progress
Income on wells in progress, drilled on a turnkey or fixed-contract
basis, is recognized under the percentage-of- completion method for financial
reporting purposes. Revenue and cost applicable to wells drilled on a day-work
basis are recognized on a daily basis. Losses, if any, on contract drilling
are recognized in the period in which the loss is determined.
Cash and Cash Equivalents
Cash and cash equivalents include short-term interest-bearing
investments in commercial paper, money markets and similar types of
investments, all with maturities of three months or less.
Inventories
Inventories of well and production equipment are stated at cost
determined by the weighted average method. Inventories are not in excess of
net realizable value.
Property, Plant and Equipment
Property, plant and equipment are carried at cost. Depreciation of
assets other than oil and gas properties is computed using the straight-line
method (3 to 20 year lives). When assets, other than oil and gas properties,
are retired or otherwise disposed of, the cost and related accumulated
depreciation are removed from the accounts, and any resulting gain or loss is
30
<PAGE> 33
reflected in income for the period. The cost of maintenance and repairs is
charged to income as incurred; significant renewals and betterments are
capitalized.
The Company utilizes the "successful efforts" method of accounting for
its oil and gas properties and equipment. Under this method, property
acquisition and development costs and productive exploration costs are
capitalized while nonproductive exploration costs, which include dry holes,
expired leases and delay rentals, are expensed as incurred. A valuation
adjustment would be provided to the extent the carrying amount of the producing
oil and gas properties for financial reporting purposes exceeded the estimated
undiscounted future net cash flow from proved oil and gas reserves as
determined on an annual basis. Such a valuation adjustment has never been
required for the Company. Undeveloped properties are assessed periodically
and, if an impairment of value is apparent, a valuation adjustment is provided.
Capitalized costs related to proven properties are depleted using the
unit-of-production method on a property-by-property basis. Oil and gas
reserves used in the calculation of the unit-of-production method are revised
annually at the beginning of the Company's fourth quarter and as needed during
the fiscal year.
Income Taxes
In February, 1992, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes." Statement 109 requires a change from the deferred method of accounting
for income taxes of APB Opinion 11 to the asset and liability method of
accounting for income taxes. Under the asset and liability method of Statement
109, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under Statement 109, the
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date.
Effective July 1, 1993, the Company adopted Statement 109.
2. Related Party Transactions
Related party accounts receivable at June 30, 1996 and 1995 are
unsecured and arise from normal operations of oil and gas properties. All such
amounts are current and are paid promptly when due.
During fiscal years 1996 and 1995, the Company charged other related
parties for certain operating and drilling expenditures totaling $6,203,000 and
$1,710,000, respectively.
During fiscal 1995 the Company purchased a 50% interest in certain west
Texas oil and gas properties for $1,750,000 and two drilling rigs for
approximately $1,149,000 from Blanco Oil Company, a related party. The Company
also obtained two vehicles and pipe inventory in the transaction for an
approximate aggregate of $150,000. In the same transaction, Messrs. Rex Amini,
Ronald Amini, Michael Amini and Jesse Minor purchased the remaining 50% of the
oil and gas properties from Blanco for the same purchase price and two other
drilling rigs for $700,000. Blanco is owned by K. K. Amini, the father of
Rex, Michael and Ron Amini and Sue Amini Minor (the wife of Jesse Minor).
31
<PAGE> 34
During fiscal 1994, the Company adopted the Sage Energy Company
Overriding Royalty Plan (the "Plan") as a performance incentive program for
certain key management employees of the Company. Under the Plan, such key
employees (presently consisting of Michael Amini, Rex Amini, Ronald Amini and
Jesse Minor) may be assigned overriding royalty interests in new exploratory or
developmental prospects acquired by the Company. In no event shall any such
overriding royalty interest, in the aggregate, exceed six percent (6%). The
value of the overriding royalty interests for fiscal years ended June 30, 1996,
1995 and 1994 amounted to approximately $60,000, $36,000 and $41,000,
respectively. These amounts were included in compensation.
3. Long-Lived Assets
During March, 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
The Company is required to adopt Statement 121 in the fiscal year beginning
July 1, 1996. Statement 121 requires that long-lived assets and certain
identifiable intangibles to be held and used by an entity be reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Furthermore, Statement 121
also requires that long-lived assets and certain identifiable intangibles to be
disposed of be reported at the lower of carrying amount or fair value less cost
to sell, except for assets that are covered by APB Opinion 30. The Company has
not completed all of the complex analyses required to estimate the impact of
the new statement, however, the adoption of Statement 121 is not expected to
have any adverse impact on the Company's financial position or the results of
its operations at the time in which it is adopted.
4. Accrued Liabilities
A summary of accrued liabilities is shown below:
<TABLE>
<CAPTION>
Years Ended June 30,
----------------------
(In Thousands)
1996 1995
----------------------
<S> <C> <C>
Interest payable $ 319 $ 328
Royalties payable 5,510 2,785
Stock repurchases 158 162
Reserve for environmental
clean-up costs 200 200
Other 144 190
------ ------
$6,331 $3,665
====== ======
</TABLE>
5. Bonds Payable
Bonds payable consist of 8 1/2% convertible debentures that mature in
2005 and are convertible into cash at the rate of $260 per $1,000 face value of
the debentures. The debentures are unsecured and are redeemable by the Company
at any time at defined redemption rates. Interest is payable semi-annually on
April 15 and October 15. Commencing in 1990, the Company was required to pay
$1,500,000 each year to a sinking fund for debenture retirement, but may, at
its option, reduce the yearly payments up to the aggregate face amount of
debentures reacquired. During fiscal years ended June 30, 1996 and 1995,
the Company retired certain debentures with a face value of $500,000 and
32
<PAGE> 35
$50,000, respectively. This transaction resulted in an extraordinary gain of
$41,000 in 1996, net of taxes. The aggregate face amount of debentures which
have been reacquired is $11,970,000. The Company has exercised its option not
to make the sinking fund payment in 1996 and 1995. Sinking fund payments will
be required commencing in October, 1997 if no further debentures are acquired
and retired. The following is a summary of sinking fund requirements over the
succeeding five years:
June 30, 1997 $ 30,000
June 30, 1998 $1,500,000
June 30, 1999 $1,500,000
June 30, 2000 $1,500,000
June 30, 2001 $1,500,000
Deferred debenture issue costs are being amortized over a 25-year period.
6. Notes Payable - Bank and Long-term Debt
The Company's credit agreement was amended and restated as of March 9,
1992 (the "Restated Credit Agreement") and as amended in May 1995 (the
"Amendment"). The Restated Credit Agreement provided for a term loan and
revolving credit facility. The term loan was fully repaid during the 1994
fiscal year. Under the revolving credit facility, as amended in May 1995, the
Company may borrow from time to time an amount determined by reference to the
Company's "borrowing base" but in any event, not more than $3,000,000. The
borrowing base is generally determined by reference to the value of the
Company's oil and gas properties; however, by agreement the Company's borrowing
base has been fixed at $3,000,000 as of June 30, 1996. On June 30, 1997
(subject to acceleration for certain events), the Company's loans, if any,
under the Restated Credit Agreement are scheduled to be fully paid. Further,
should the value of the Company's assets decrease (as a result of oil and gas
prices or other factors) any future bank borrowings may be subject to mandatory
prepayment. As of June 30, 1996, there were no borrowings outstanding with
respect to the revolving credit facility.
7. Ownership
On December 31, 1991, Sage Energy Company, a Texas corporation, merged
with and into Sage Energy Company, a Delaware corporation (Sage Delaware). As
the surviving corporation in such a merger, Sage Delaware succeeded to all of
the rights and obligations of the Company, including the Company's obligations
with respect to its outstanding Convertible Subordinated Debentures.
The Company paid a cash dividend of approximately $229 per share which
aggregated $320,000 in fiscal 1995. The Company declared bonuses to four of
its officers and directors of approximately $520,000 and $400,000 in fiscal
1996 and 1995. These bonuses were paid in December 1995 and March 1995,
respectively.
8. Floor Agreement
On March 28, 1994, the Company entered into the Commodity Floor
Transaction (the "Floor Agreement") with Chemical Bank. The Agreement
commenced on April 1, 1994 and ended on December 31, 1994. The Company
effectively received a price associated with the New York Mercantile price of
no lower than $13.00 per barrel with respect to 40,000 barrels of production
per month. The Company paid $72,000 for the Agreement which was amortized over
the life of the Agreement.
33
<PAGE> 36
9. Sales of Assets
The Company sold several marginal properties during fiscal year ended
June 30, 1994 which resulted in a gain on sale of approximately $49,000. The
Company sold several of its drilling rigs during fiscal year ended June 30,
1995 which resulted in a gain on the sale of approximately $1,059,000.
During fiscal year ended June 30, 1996, the Company sold all of its
producing properties in Oklahoma, undeveloped leases in North Dakota and three
drilling rigs and all of its servicing units as well as related automobiles and
miscellaneous equipment. The sales resulted in a gain of approximately
$490,000 from the producing properties in Oklahoma, a gain of approximately
$447,000 from the drilling rigs and a gain of approximately $700,000 from the
servicing units and related automobiles and miscellaneous equipment.
10. Income Taxes
As discussed in Note 1, the Company adopted Statement 109 as of July 1,
1993. The adoption of Statement 109 reduced the net deferred tax liability by
approximately $4,250,000 and this amount was reported separately as the
cumulative effect of the change in the method of accounting for income taxes in
the statement of operations for the year ended June 30, 1994.
Total income tax expense attributable to income before extraordinary
item for the year ended June 30, 1996 was $2,221,000, of which $2,564,000 is
attributable to current income tax expenses and $343,000 is attributable to
deferred income tax benefit. Total income tax expense attributable to income
before cumulative effect of change in accounting for the year ended June 30,
1995 was $331,000, of which $1,428,000 was attributable to current income tax
expenses and $1,097,000 was attributable to deferred income tax benefit.
Income tax expense attributable to income from operations before income
taxes for the year ended June 30 differed from the amounts computed by applying
the Federal income tax rate of 34% to pretax income before cumulative effect of
change in accounting as a result of the following:
<TABLE>
<CAPTION>
Years Ended June 30,
-------------------------------------
(In Thousands)
1996 1995 1994
-------------------------------------
<S> <C> <C> <C>
Tax expense computed at
statutory rate on income
before income taxes $2,246 $ 537 $ 388
Increase (decrease) in tax from:
Statutory depletion (199) (258) (134)
Deduction for state income taxes (90) (67) (35)
Other 7 (50) (52)
State income taxes 257 169 104
------ ------ ------
$2,221 $ 331 $ 271
====== ====== ======
</TABLE>
34
<PAGE> 37
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at June 30,
1996 and 1995 are presented below:
<TABLE>
<CAPTION>
Years Ended June 30,
----------------------
(In Thousands)
1996 1995
----------------------
<S> <C> <C>
Deferred tax assets:
State income taxes $ 111 $ 239
Deferred expenses for tax purposes 76 79
------ ------
Total gross deferred tax assets 187 318
Less valuation allowance - -
------ ------
Total deferred tax assets 187 318
Deferred tax liabilities:
Property and equipment, principally
due to differences in depreciation
and depletion 4,010 4,484
------ ------
Total gross deferred tax liability 4,010 4,484
------ ------
Net deferred tax liability $3,823 $4,166
====== ======
</TABLE>
The Company anticipates that the reversal of existing taxable temporary
differences will provide sufficient income to realize the tax benefits of the
deferred tax assets.
11. Benefit Plans
During December, 1990, the Company adopted a 401(k) retirement plan in
which eligible employees of the Company may elect to participate. The Company
may contribute, on a discretionary basis, a percentage of the employees' annual
contribution, determined annually by the Company. The Company's contributions
for the fiscal years ended June 30, 1996, 1995 and 1994 were approximately
$22,000, $28,000 and $32,000, respectively.
12. Supplemental Cash Flow Information
<TABLE>
<CAPTION>
Years Ended June 30,
-------------------------
(In Thousands)
1996 1995 1994
-------------------------
<S> <C> <C> <C>
Interest paid $1,554 $1,580 $1,798
====== ====== ======
Taxes paid $1,586 $2,305 $1,164
====== ====== ======
</TABLE>
35
<PAGE> 38
13. Segment Disclosure
A summary of revenues, operating profit, identifiable assets,
depreciation and depletion and property additions of each business segment is
shown below:
<TABLE>
<CAPTION>
Years Ended June 30,
--------------------------------------------------
(In Thousands)
Revenue-
Revenue Intersegment Nonsegment
By Segment Revenue Customers
--------------------------------------------------
<S> <C> <C> <C>
1996
- -------------------------------------------------------------------------------------
Revenues:
Oil and gas production $27,815 $ - $27,815
Contract drilling 2,723 887 1,836
Other 1,885 - 1,885
------- ------ -------
$32,423 $ 887 $31,536
======= ====== =======
1995
- -------------------------------------------------------------------------------------
Revenues:
Oil and gas production $25,675 $ - $25,675
Contract drilling 2,450 818 1,632
Other 1,496 - 1,496
------- ------ -------
$29,621 $ 818 $28,803
======= ====== =======
1994
- -------------------------------------------------------------------------------------
Revenues:
Oil and gas production $30,089 $ - $30,089
Contract drilling 3,169 1,327 1,842
Other 411 - 411
------- ------ -------
$33,669 $1,327 $32,342
======= ====== =======
</TABLE>
The following is a summary of major customer purchases exceeding 10% of the
Company's revenues:
<TABLE>
<CAPTION>
Years Ended June 30,
-------------------------------------------------
(In Thousands)
1996 1995 1994
-------------------------------------------------
<S> <C> <C> <C>
Scurlock Permian Corporation $14,910 $ 15,395 $17,418
Aquila Southwest Pipeline $ 3,798 $ - $ 3,634
- -------------------------------------------------------------------------------------
</TABLE>
36
<PAGE> 39
Operating profit is total revenues less operating expenses. In
determining operating profit, none of the following items have been included:
general corporate expenses, investment and miscellaneous income, interest
expense and income taxes. Eliminations represent the intersegment operating
profit of the contract drilling segment for wells drilled for the oil and gas
production segment. Such eliminations result in the wells being recorded at
the Company's cost.
<TABLE>
<CAPTION>
Years Ended June 30,
-----------------------------------
(In Thousands)
1996 1995 1994
-----------------------------------
<S> <C> <C> <C>
Operating profit:
Oil and gas production $ 9,506 $ 5,169 $ 6,249
Contract drilling 432 179 712
-------- -------- --------
9,938 5,348 6,961
Eliminations (246) (145) (378)
-------- -------- --------
Total operating profit 9,692 5,203 6,583
General corporate expenses and
other unallocated components of
other income and expenses - net (1,541) (2,045) (3,672)
Interest expense (1,545) (1,579) (1,770)
-------- -------- --------
Profit from operations
before income taxes $ 6,606 $ 1,579 $ 1,141
======= ======= =======
</TABLE>
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended June 30,
-------------------------------------
(In Thousands)
1996 1995 1994
-------------------------------------
<S> <C> <C> <C>
Identifiable assets:
Oil and gas production, net $39,383 $34,124 $34,694
Contract drilling 1,331 2,148 1,846
Corporate assets 9,461 5,519 6,946
------- ------- -------
$50,175 $41,791 $43,486
======= ======= =======
</TABLE>
- --------------------------------------------------------------------------------
37
<PAGE> 40
<TABLE>
<CAPTION>
Years Ended June 30,
-----------------------------------------------------------------------------
(In Thousands)
1996 1995 1994
------------------------------------------------------------------------------
Deprecia- Deprecia- Deprecia-
tion and Property tion and Property tion and Property
Depletion Additions Depletion Additions Depletion Additions
------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Oil and gas
production $6,982 $11,894 $ 8,075 $12,538 $11,033 $10,348
Contract
drilling 252 34 240 1,196 266 91
Corporate 333 230 325 218 311 295
------ ------- -------- ------- ------- -------
$7,567 $12,158 $ 8,640 $13,952 $11,610 $10,734
====== ======= ======== ======= ======= =======
</TABLE>
14. Interim Results of Operations (Unaudited)
<TABLE>
<CAPTION>
Per Common Share Per
Income (Loss) Before Income (Loss) Before Common
Extraordinary Item Extraordinary Item Share
and Cumulative Net and Cumulative Net
Effect of Change Income Effect of Change Income
Revenues in Accounting (Loss) in Accounting (Loss)
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Year Ended
- ----------
June 30, 1996
- -------------
First quarter $ 6,550 $ 814 $ 814 $ 582 $ 582
Second quarter 6,871 641 682 458 487
Third quarter 8,413 2,081 2,081 1,487 1,487
Fourth quarter 9,702 849 849 607 607
------- ------ ------ ------ ------
$31,536 $4,385 $4,426 $3,134 $3,163
======= ====== ====== ====== ======
Year Ended
- ----------
June 30, 1995
- -------------
First quarter $ 8,373 $1,355 $1,355 $ 969 $ 969
Second quarter 6,395 13 13 9 9
Third quarter 7,384 164 164 117 117
Fourth quarter 6,651 (284) (284) (203) (203)
------- ------ ------ ------ ------
$28,803 $1,248 $1,248 $ 892 $ 892
======= ====== ====== ====== ======
Year Ended
- ----------
June 30, 1994
- -------------
First quarter $ 9,239 $1,005 $5,255 $ 718 $3,756
Second quarter 8,141 (544) (544) (389) (389)
Third quarter 7,263 163 163 117 117
Fourth quarter 7,699 246 387 176 277
------- ------ ------ ------ ------
$32,342 $ 870 $5,261 $ 622 $3,761
======= ====== ====== ====== ======
</TABLE>
38
<PAGE> 41
15. Supplemental Information Related to Oil and Gas Producing Activities
(Unaudited)
The following tables contain certain historical cost and operating
information related to the Company's oil and gas producing activities.
<TABLE>
<CAPTION>
June 30,
----------------------------------------
(In Thousands)
1996 1995 1994
----------------------------------------
<S> <C> <C> <C>
Capitalized cost:
Producing properties $119,550 $118,504 $ 116,740
Undeveloped properties 4,812 4,044 2,515
-------- ------- -------
Total capitalized cost 124,362 122,548 119,255
Accumulated depreciation and
depletion (96,527) (95,571) (92,786)
-------- ------- -------
Net capitalized cost $ 27,835 $26,977 $26,469
======== ======= =======
</TABLE>
<TABLE>
<CAPTION>
Years Ended June 30,
----------------------------------
(In Thousands)
1996 1995 1994
----------------------------------
<S> <C> <C> <C>
Cost incurred:
Property acquisition cost:
Non-producing properties $2,811 $ 3,451 $ 1,895
Producing properties - 3,201 202
Exploration costs 2,751 3,067 1,535
Development costs 7,948 4,911 8,169
</TABLE>
The results of operations of the Company's oil and gas producing
activities are shown below:
<TABLE>
<CAPTION>
Years Ended June 30,
----------------------------------
(In Thousands)
1996 1995 1994
----------------------------------
<S> <C> <C> <C>
Oil and gas revenues $27,815 $25,675 $30,089
------- ------- -------
Less:
Production taxes 1,321 1,286 1,361
Production costs 7,075 6,826 8,378
Nonproductive exploration costs 2,501 3,005 1,980
Geological and geophysical 430 1,314 1,088
Depletion 6,982 8,075 11,033
------- ------- -------
18,309 20,506 23,840
------- ------- -------
Profit before income taxes 9,506 5,169 6,249
Income taxes 3,232 1,757 2,125
------- ------- -------
Net profit from oil and gas
producing activities (exclusive
of general corporate overhead
and financial cost) $ 6,274 $ 3,412 $ 4,124
======= ======= =======
</TABLE>
39
<PAGE> 42
The Company's interest in proved oil (including natural gas liquids) and
gas reserves are as follows:
<TABLE>
<CAPTION>
Years Ended June 30,
-----------------------------------------------------------------
(In Thousands)
1996 1995 1994
-----------------------------------------------------------------
Bbls Mcf Bbls Mcf Bbls Mcf
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning of year 6,178 32,132 5,325 30,280 5,966 29,055
Revisions of previous
estimates 377 2,353 (258) 2,807 (86) 4,388
Purchases of minerals
in place - - 1,391 2,400 - -
New discoveries and
extensions 847 2,681 723 1,970 687 2,273
Production (994) (5,037) (1,003) (5,325) (1,242) (5,436)
Sales of minerals in place (7) (4,689) - - - -
---- ------ ----- ------ ----- ------
End of year 6,401 27,440 6,178 32,132 5,325 30,280
===== ====== ===== ====== ===== ======
Proved developed reserves:
Balance at beginning of
year 3,640 25,273 3,465 23,572 3,428 19,739
Balance at end of year 4,000 23,250 3,640 25,273 3,465 23,572
</TABLE>
The following is a standardized measure of the discounted net future
cash flows and changes applicable to proved oil and gas reserves required by
FAS 69. The future cash flows are based on estimated oil and gas reserves
utilizing prices and costs in effect as of year end discounted at 10% per year
and assuming continuation of existing economic conditions.
The standardized measure of discounted future net cash flows, in
management's opinion, should be examined with caution. The basis for this
table is management's reserve study which contains imprecise estimates of
quantities and rates of production of reserves. Revisions of previous year
estimates can have a significant impact on these results. Also, exploration
cost in one year may lead to significant discoveries in later years and may
significantly change previous estimates of proved reserves and their valuation.
Therefore, the standardized measure of discounted future net cash flow
is not necessarily a "best estimate" of the fair value of the Company's proved
oil and gas properties.
40
<PAGE> 43
<TABLE>
<CAPTION>
Years Ended June 30,
----------------------------------------------
(In Thousands)
1996 1995 1994
----------------------------------------------
<S> <C> <C> <C>
Estimated cash inflows $187,135 $159,905 $147,843
Less:
Related estimated future
development and production
costs (71,509) (68,073) (60,051)
Estimated income taxes (35,091) (26,986) (25,178)
-------- -------- --------
Estimated net cash
flows 80,535 64,846 62,614
Discount to reduce estimated
net cash flows to present
value (26,609) (23,115) (19,766)
-------- -------- --------
Discounted present value of
estimated net cash flows $ 53,926 $ 41,731 $ 42,848
======== ======== ========
Changes in discounted net cash
flows:
Increase (decrease):
Additions to proved reserves
resulting from extensions
and discoveries less
related cost $ 10,016 $ 5,637 $ 8,756
Purchase of minerals in place - 6,696 -
Accretion of discount 5,684 5,793 6,000
Sales of oil and gas net of
production costs of $8,396,
$8,112 and $9,739 (19,419) (17,563) (20,350)
Revisions of previous estimates
Changes in prices 13,588 5,184 (2,752)
Changes in quantities 5,286 1,481 4,340
Changes in future development
costs (4,713) (8,115) 6,116
Changes of production
rates (timing) and other (4,220) (257) (4,243)
Changes in estimated income taxes 5,973 27 30
-------- -------- --------
Net increase (decrease) 12,195 (1,117) (2,103)
Balance:
Beginning of year
End of year 41,731 42,848 44,951
-------- -------- --------
$ 53,926 $ 41,731 $ 42,848
======== ======== ========
</TABLE>
16. Fair Value of Financial Instruments
The Company holds cash, trade receivables, oil and gas receivables and
payables. The carrying amount of these instruments approximates fair value due
to the short maturity of these instruments. The fair value of the Company's
bonds payable is approximately $15,799,000 based on the quoted market prices at
June 30, 1996 or $876.25 per $1,000 face amount of the bonds.
17. Contingent Liabilities
The Company is involved in various claims and legal actions arising in
the ordinary course of business. Management believes the ultimate disposition
of these matters will have no material adverse effect on the financial
statements of the Company.
41
<PAGE> 44
18. Subsequent Events
Subsequent to June 30, 1996, the Company announced a plan to effect a
redemption of up to $7,000,000 of its outstanding convertible subordinated
debentures. Such redemption is to be carried out in accordance with the terms
of such securities and is to be effected at a price equal to 100% of the
principal amount of each debenture so redeemed.
During August 1996, the Company sold several of its undeveloped leases
in North Dakota for approximately $2,024,000. This sale will result in an
estimated gain of approximately $1,640,000.
42
<PAGE> 45
Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure.
Not Applicable.
PART III
Item 10. Directors and Executive Officers of the Registrant.
Jesse Minor, Michael Amini, Ronald Amini, Rex Amini, Harold Conrad and
Mark S. Solomon are the directors of the Company. The business address of
Jesse Minor, Michael Amini, Ronald Amini, and Rex Amini is 10101 Reunion Place,
Suite 800, San Antonio, Texas 78216. The business address of Mr. Conrad is
5315 Mittlestadt, Houston, Texas 77069. Mr. Solomon's business address is
1717 Main Street, Suite 4100, Dallas, Texas 75201.
The executive officers of the Company, their ages and office or offices
held are as follows:
<TABLE>
<CAPTION>
Name Age Position with Company
---- --- ---------------------
<S> <C> <C>
Jesse Minor 44 President and Director
Rex Amini 46 Executive Vice President,
Treasurer and Director
Stanley A. Paris, Jr. 47 Vice President - Finance
Jay Hardy 63 Vice President - Engineering
Michael Amini 39 Executive Vice President,
Secretary and Director
Ronald Amini 42 Executive Vice President and
Director
</TABLE>
Jesse Minor received his B.A. in 1974 and an M.S. in petroleum
engineering from the University of Texas in 1978. Since January, 1990, Mr.
Minor has been President and a Director of the Company.
Rex Amini received his B.A. from Cornell University in May 1972. He
received a J.D. in 1975 and a B.S in geology in 1978 from the University of
Texas. Rex Amini has been a director of the Company since 1977 and has been
Executive Vice President and Treasurer since January, 1990.
Michael Amini received his B.S. degree in geology from Stanford
University in June 1979. He has served as a director of Fargo Energy Company
since 1980 and was elected an officer and director of the Company on January
10, 1990.
Ronald Amini received his B.S. in petroleum engineering from the
University of Texas in May 1977. He has served as an officer and director of
Fargo Energy Company since 1980. Ronald Amini was elected as a director of
the Company on January 10, 1990 and as an officer of the Company on March 1,
1990.
Stanley A. Paris, Jr. received his BBA in accounting from the University
of Texas in May 1971. He was elected an officer of the Company on January 9,
1990.
Jay Hardy received his B.S. from the University of Kansas in 1956. He
has been an officer of the Company since May 27, 1980.
Mark S. Solomon, age 36, received his B.A. from Franklin and Marshall
College in 1982 and a J.D. (with honors) in 1985 from the George Washington
University National Law Center. Since June of 1992, he has been a partner
43
<PAGE> 46
with the law firm of Arter & Hadden. From March 1990 until June 1992, he was
associated with the law firm of Johnson Bromberg and Leeds, a predecessor to
Arter & Hadden.
Harold J. Conrad, age 59, received his B.S. in petroleum engineering from
Texas A&M University in 1958. Upon graduation, he immediately joined Shell Oil
Company where he spent 33 years before retiring in 1991. When he left Shell,
he was Manager of Business Development. Since that time he has been an
independent investor advisor.
Rex Amini, Ronald Amini and Michael Amini are brothers, and Jesse Minor
is a brother-in-law of each of them. There is no other family relationship
between any of the executive officers and directors of the Company. Fargo was
previously involved in the exploration and production of oil and gas and is
owned 25% by each of Rex Amini, Michael Amini, Ronald Amini and Susan Amini
Minor, wife of Jesse Minor. Each officer is appointed annually by the
Company's Board of Directors to serve at the Board's discretion or until their
successors in office are duly elected and qualified.
Item 11. Executive Compensation.
Executive Compensation
The following Summary Compensation Table shows compensation paid by the
Company for services rendered during fiscal years ending June 30, 1996, 1995
and 1994 for the person who was President at the end of the last fiscal year
and the four most highly compensated executive officers of the Company whose
salary and bonus exceeded $100,000 in fiscal 1996.
Annual
Compensation
<TABLE>
<CAPTION>
Year All other
Name and Principal Ended Salary Bonus Compensation
Position June 30, ($) ($) (1) (3) ($) (2)
- ------------------ -------- ------- ----------- -------
<S> <C> <C> <C> <C>
Jesse Minor 1996 210,000 130,000 24,249
President and Director 1995 200,000 100,000 30,500
1994 200,000 120,000 14,185
Rex Amini 1996 210,000 130,000 23,737
Executive Vice President 1995 200,000 100,000 25,847
Treasurer and Director 1994 200,000 120,000 14,107
Michael Amini 1996 210,000 130,000 23,895
Executive Vice President 1995 200,000 100,000 29,342
Secretary and Director 1994 200,000 120,000 13,223
Ronald Amini 1996 210,000 130,000 12,264
Executive Vice President 1995 200,000 100,000 22,812
and Director 1994 200,000 120,000 11,653
Jay Hardy 1996 122,841 6,130 2,431
Vice President 1995 119,265 7,726 6,818
of Engineering 1994 119,265 9,102 2,141
</TABLE>
(1) Cash bonuses for services rendered in fiscal years 1994, 1995 and 1996
have been listed in the fiscal year paid.
(2) The stated amounts are Company matching contributions to the Sage Energy
44
<PAGE> 47
Company 401(K) Plan, club memberships, dues and payments under the Sage
Energy Company Overriding Royalty Plan (described below) for Michael
Amini, Rex Amini, Ron Amini, and Jesse Minor and tickets to sporting
activities.
(3) The Company made no long term compensation, awards or payouts during the
three fiscal years set forth in the summary compensation table.
Overriding Royalty Plan
During fiscal 1994, the Company adopted the Sage Energy Company
Overriding Royalty Plan (the "Plan") as a performance incentive program for
certain key management employees of the Company. Under the Plan, such key
employees (presently consisting of Michael Amini, Rex Amini, Ronald Amini and
Jesse Minor) may be assigned overriding royalty interests in new exploratory or
developmental prospects acquired by the Company. In no event shall any such
overriding royalty interest, in the aggregate, exceed six percent (6%).
Director Compensation
Directors of the Company receive an annual retainer of $10,000.
Additionally, the directors are reimbursed for their expenses incurred in
attending meetings of the Company's Board of Directors.
Stock Option Grants in Fiscal Year 1996
The Company does not have a stock option plan.
Compensation Committee Interlocks on Insider Participation
Mr. Solomon, who serves as a member of the Company's Compensation
Committee, is a member of a law firm which renders legal services to the
Company. (See Certain Relationships and Related Transactions.)
Compensation Report of the Board of Directors
The Compensation Committee of the Board of Directors traditionally meets
at the end of each calendar year to determine compensation for the following
year. The following report was issued in December of 1995.
Sage Energy Company's Compensation Committee consists of Messrs. Harold
Conrad and Mark S. Solomon. The Compensation Committee's primary function is
to establish and review the compensation awarded to the four most senior
executive officers of the Company.
In determining executive compensation, the Compensation Committee has
traditionally reviewed a multitude of factors. However, in light of the unique
nature of the Company (its four most senior executive officers are the sole
shareholders of the Company which owns all of the Company's outstanding common
stock) and in an attempt to align the Company's compensation policies more
closely with the Company's other policies, the Compensation Committee approved
and adopted a formula compensation plan as the method of compensating such
executive officers for each fiscal year commencing with the fiscal year
beginning July 1, 1996. The formula plan is attached hereto as Exhibit A. The
formula plan is intended to provide each of the executive officers with
incentive to increase the net value of the Company (e.g., by acquiring
additional reserves at suitable prices, the repayment of indebtedness, or other
means) while maintaining positive cash flow. The Compensation Committee has
determined that such formula will serve to reward the performance of the
executives in the Company. Each of the four most senior executive officers of
the Company are to be provided equal compensation reflecting the team
management philosophy of the Company under which each of the executive officers
are accorded roughly equivalent responsibilities. Thus, the determination of
the chief executive officer's compensation is no different
45
<PAGE> 48
than that of any of the other three most senior executive officers. In
adopting the proposed formula, the Compensation Committee took special note of
the fact that, given the nature of the Company, the traditional forms of
incentive compensation are not applicable to the executive officers of the
Company.
Since the formula compensation plan will not take effect until the
results of the 1996 fiscal year have been determined, the Compensation
Committee reviewed the appropriate bonus (if any) to be paid to each of the
executive officers with respect to the 1995 fiscal year. In determining such
bonus, the Compensation Committee reviewed and considered (i) the performance
of the executives, (ii) the operating performance of the Company, (iii) the
compensation of executives of entities which are engaged in similar activities
and are of similar size to the Company, (iv) the historical compensation of the
executive (v) the proposed compensation formula, and (vi) the performance of
the Company's debentures. After a review of such factors (with the Company's
performance and the historical compensation of the executives being accorded
the most weight and the price of the Company's debentures being accorded the
least weight) the Compensation Committee determined to award each executive
officer a bonus of $130,000. In connection therewith, the Compensation
Committee took particular note of the Company's sustained profitablity since
1990, increase in income before cumulative effect of change in accounting of
$237,000 from fiscal 1994 to fiscal 1995, the Company's recent repurchases of
outstanding debentures and continued replacement of reserves and the Company's
general and administrative cost saving measures. The Compensation Committee
also considered that the approximate compensation which would have been awarded
to each of the executive officers in fiscal 1995 under the proposed formula
plan would have been $372,000 (which is higher than that actually paid).
EXHIBIT A
The total compensation for each of the four most senior executive
officers for any fiscal year (commencing with the fiscal year beginning July 1,
1996) shall be made with reference to Sage Energy Company's Annual Report on
Form 10-K for the immediately preceeding fiscal year. It is expected that the
Form 10-K will be completed and filed in late September of such year in the
interim (e.g. the date before the determination of such awards), the Company
may provide to each of such executive officers a "draw" against any
compensation earned with any excess compensation to be payable by the Company
after the determination of such amount and any shortfalls or amounts owed by
the executive (by reason of draws in excess of the amounts determined to be
paid as compensation), shall be an obligation of such executive to the Company.
Compensation shall be determined as a sum of the following amounts
derived from the following two formulas and with each such amount to be
determined by reference to the Company's Annual Report for the most recently
completed fiscal year.
1. Current assets + the net present value of the Company's oil and
gas reserves (discounted in accordance with Securities and
Exchange Commission procedures and at an annual rate of 10%) -
long-term debt (excluding the effect of any deferred income taxes)
- current liabilities = "break-up value." The "break-up value"
multiplied by .005 equals the break-up value compensation.
2. Total revenues - all costs and expenses - federal income taxes +
depreciation, depletion and amortization = "cash flow." "Cash
flow" multiplied by 0.15 equals the cash flow compensation.
Break-up value compensation plus cash flow compensation equals
compensation for each executive officer for each fiscal year.
The total compensation for each executive officer shall not exceed
46
<PAGE> 49
$550,000 for any fiscal year. The Compensation Committee (and in its absence,
the Board of Directors) reserves the right to modify, amend and terminate this
formula plan at any time.
HAROLD CONRAD MARK S. SOLOMON
Employment Contracts and Termination of Employment and Change in Control
Arrangements
No director or executive officer of the Company is entitled to any
payment in connection with the termination of his employment.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Sage Acquisition Company owns 100% of all of the 1,399 issued and
outstanding shares of the Company's Common Stock. Sage Acquisition Company is
wholly-owned by Michael Amini, Rex Amini, Ronald Amini and Jesse Minor.
Item 13. Certain Relationships and Related Transactions.
No officer, director or principal security holder of the Company, or any
relative or spouse of any of the foregoing persons, or any relative of such
spouse who has the same home as such person or who is a director or officer of
any parent or subsidiary of the Company was, or is a party to, or had any
direct or indirect material interest in, any material transaction during the
Company's fiscal year ended June 30, 1996, or any presently proposed
transactions, except as set forth below:
The Company acts as operator on numerous wells in which of Kit Carson,
Ltd. (a limited partnership of which Rex Amini is the general partner), Ronald
Amini, Jemsam, Ltd. (a limited partnership of which Jesse Minor and Susan
Amini- Minor are partners), and Cuthbert Partners, Ltd. (of which Michael Amini
and Molly Amini, spouse of Michael Amini are partners) own interests. The
Company charges to each interest owner their pro-rata share of drilling
overhead charges and pumping charges per well. Overhead charges are
approximately $326 to $831 per well per month, and pumping charges are
approximately $295 per well per month. In addition, the Company charges each
of the interest owners, leasehold costs, other lease operating expenses,
including equipment costs, attributable to the well which the Company pays. The
Company believes that its charges to each of the referenced persons and
entities are comparable to those charged within the industry in connection with
similar transactions. At June 30, 1996 the following entities as related
parties had the following indebtedness to the Company: Cuthbert Partners, Ltd.,
$515,000; Kit Carson, Ltd., $536,000; Ron Amini, $495,000; and JEMSAM, Ltd.,
$536,000. Such indebtedness is primarily attributable to receivables to the
Company with respect to working interests in certain wells in which the Company
is the operator. At June 30, 1996 the Company owed Cuthbert Partners, Ltd.,
$426,000; Kit Carson, Ltd.,$428,000; Ron Amini, $424,000; and JEMSAM, Ltd.,
$428,000 with respect to their revenue interests in such wells.
Each of Jesse Minor, Rex Amini, Michael Amini and Ronald Amini
(collectively the "Family Members") was a co- participant either through their
limited partnerships or individually in varying percentages in several of the
Company's drilling prospects conducted during the twelve-month period ended
June 30, 1996.
The Family Members' percentage working interest in such prospects
generally was between 5% and 15% each during such period. The percentage of
the Family Members participation for each calendar year is to be reviewed
annually by the Board and may be adjusted in the Board's discretion. The
47
<PAGE> 50
terms of the Family Members' participation in the Company's drilling prospects
are on the basis of actual costs incurred and billed to Sage in the drilling
and acquisition activities. The Company collects and disburses the revenues on
a majority of these wells as operator and also charges each of the participants
their pro-rata share of pumping and overhead charges and other lease operating
and equipment costs. The Company believes that its charges in these
transactions are either consistent with those charged in the industry in
similar transactions or pursuant to terms under which the Family Members bear
their respective pro-rata share of expenses incurred by the Company.
On the basis of the three preceding paragraphs set forth above, the
Company charged, including reimbursable items, an aggregate of $6,203,000 to
the above named persons.
Mr. Solomon is a member of the law firm of Arter & Hadden. The Company
has retained such law firm in the past with respect to certain legal matters
and intends to retain such law firm in the future. The fees paid to such law
firm were not material in any respect.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) 1. Financial Statements, included in Part II (Item 8) of this report:
Page
----
Independent Auditors' Report............................. 24
Balance Sheets, June 30, 1996 and 1995................... 25
Statements of Operations, Years ended
June 30, 1996, 1995 and 1994.......................... 27
Statements of Stockholder's Equity,
Years ended June 30, 1996, 1995 and 1994.............. 28
Statements of Cash Flows,
Years ended June 30, 1996, 1995 and 1994.............. 29
Notes to Financial Statements............................ 30
(a) 2. Financial Schedules:
There are no financial schedules as the required information is
inapplicable or the information is presented in the Financial Statements or
related Notes.
(a) 3. Exhibits
3.1 Certificate of Incorporation is hereby incorporated by
reference to Exhibit 3.1 of the Form 8-B to the Company's
Registration Statement on Form 8-B filed by the Company with
the Securities and Exchange Commission on January 10, 1992
(the "Form 8-B").
3.2 Bylaws of the Company are hereby incorporated by reference
to Exhibit 3.2 of the Form 8-B.
4.1 Indenture between the Company and the First NationalBank of
Midland, Texas (now NationsBank, N.A.), Trustee, dated
October 15, 1980, is hereby incorporated by reference to
Exhibit 4.1 of the Form 8-B.
4.2 First Supplemental Indenture between Sage Energy Company and
NCNB Texas National Bank dated as of May 15, 1989 is hereby
incorporated by reference to Exhibit 4.2 of the Form 8-B.
48
<PAGE> 51
4.3 Second Supplemental Indenture between Sage Energy Company
and NCNB Texas National Bank dated as of December 31, 1991
is hereby incorporated by reference to Exhibit 4.3 of the
Form 8-B.
10.1 Second Amended and Restated Credit Agreement dated as of
March 9, 1992 by and among Sage Energy Company, Texas
Commerce Bank, National Association ("TCB"), Texas Commerce
Bank-San Antonio ("TCB-SA") (collectively, the "Banks"), TCB
as administrative agent for the ratable benefit of the
Banks, TCB and TCB-SA, as co-agents for the ratable benefit
of the Banks, (the "Restated Credit Agreement") is hereby
incorporated by reference to Exhibit 28.1 of the Company's
Quarterly Report on Form 10-Q for the quarter ended March
31, 1992.
10.2 First Amendment to Second Amended and Restated Credit
Agreement dated as of June 30, 1993 by and among Sage Energy
Company, TCB, TCB-SA, TCB as Administrative Agent for the
ratable benefit of the Banks and TCB and TCB-SA as co-agents
for the ratable benefit of the Banks, is hereby incorporated
by reference to Exhibit 10.2 of the Company's Annual Report
on form 10K for the fiscal year ended June 30, 1993.
10.3 Second Amendment to Second Amended and Restated Credit
Agreement dated as of May 9, 1995 by and between Sage Energy
Company and TCB is hereby incorporated by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10Q
for the Quarter ended March 30, 1995.
10.4 Shareholders Agreement, dated as of February 7, 1990, by and
among Sage Acquisition Company, Sage Energy Company, Rex
Amini, Ronald Amini, Michael Amini and Jesse Minor is hereby
incorporated by reference to Exhibit 10.4 to the Company's
Annual Report on Form 10-K for the fiscal year ended June
30, 1995.
10.5 Sage Energy Company Overriding Royalty Plan is hereby
incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on form 10-Q for the quarter ended December
31, 1993.
23.1 Independent Auditors' Report. * See Page 24 hereof.
27.1 Financial Data Schedule *
(b) Reports on Form 8-K. No reports on Form 8-K have been filed during
the last quarter of the year covered by this report.
* Filed herewith.
49
<PAGE> 52
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities
Exchange Act of 1934, the Company has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
SAGE ENERGY COMPANY
By: /s/ Jesse Minor
-----------------------------------
Jesse Minor, President
September 30, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
<TABLE>
<CAPTION>
Signatures Title Date
---------- ----- ----
<S> <C> <C>
/s/ Jesse Minor President and Director September 30, 1996
- --------------------------
(Jesse Minor)
/s/ Rex Amini Executive Vice President, September 30, 1996
- -------------------------- Treasurer and Director
(Rex Amini)
/s/ Ronald Amini Executive Vice President September 30, 1996
- -------------------------- and Director
(Ronald Amini)
/s/ Michael Amini Executive Vice President, September 30, 1996
- -------------------------- Secretary and Director
(Michael Amini)
/s/ Stanley A. Paris, Jr. Vice President-Finance September 30, 1996
- --------------------------
(Stanley A. Paris, Jr.)
/s/ Mark S. Solomon Director September 30, 1996
- --------------------------
(Mark S. Solomon)
/s/ Harold J. Conrad Director September 30, 1996
- --------------------------
(Harold J. Conrad)
</TABLE>
50
<PAGE> 53
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Exhibit Page No.
- ------ ------- --------
<S> <C>
3.1 Certificate of Incorporation is hereby incorporated
by reference to Exhibit 3.1 of the Form 8-B. to the
Company's Registration Statement on Form 8-B filed by the
Company with the Securities and Exchange Commission on
January 10, 1992 (the "Form 8-B").
3.2 Bylaws of the Company are hereby incorporated by
reference to Exhibit 3.2 of the 8-B.
4.1 Indenture between the Company and the First National
Bank of Midland, Texas (now NationsBank, N.A.),
Trustee, dated October 15, 1980, is hereby incorporated
by reference to Exhibit 4.1 of the Form 8-B.
4.2 First Supplemental Indenture between Sage Energy
Company and NCNB Texas National Bank dated as of
May 15, 1989 is hereby incorporated by reference to
Exhibit 4.2 of the Form 8-B.
4.3 Second Supplemental Indenture between Sage Energy
Company and NCNB Texas National Bank dated as of
December 31, 1991 is hereby incorporated by
reference to Exhibit 4.3 of the Form 8-B.
10.1 Second Amended and Restated Credit Agreement dated
as of March 9, 1992 by and among Sage Energy Company,
Texas Commerce Bank, National Association ("TCB"),
Texas Commerce Bank-San Antonio ("TCB-SA")
(collectively, the "Banks"), TCB as administrative
agent for the ratable benefit of the Banks (the
"Restated Credit Agreement"), is hereby incorporated
by reference to Exhibit 28.1 of the Company's
Quarterly Report on Form 10-Q for the quarter
ended March 31, 1992.
10.2 First Amendment to Second Amended and Restated Credit
Agreement dated as of June 30, 1993 by and among
Sage Energy Company, TCB, TCB-SA, TCB as Administrative
Agent for the ratable benefit of the Banks and TCB and
TCB-SA as co-agents for the ratable benefit of the Banks,
is hereby incorporated by reference to Exhibit 10.2 of the
Company's Annual Report on form 10K for fiscal year ended
June 30, 1993.
</TABLE>
51
<PAGE> 54
<TABLE>
<CAPTION>
Exhibit
Number Exhibit Page No.
- ------ ------- --------
<S> <C>
10.4 Shareholders Agreement, dated as of February 7, 1990,
by and among Sage Acquisition Company, Sage Energy
Company, Rex Amini, Ronald Amini, Michael Amini
and Jesse Minor is hereby incorporated by reference
to Exhibit 10.4 to the Company's Annual Report on
Form 10-K for the fiscal year ended June 30, 1995.
10.5 Sage Energy Company Overriding Royalty Plan is hereby
incorporate by reference to Exhibit 10.1 to Company's
Quarterly Report on form 10Q for the quarter ended
December 31, 1993.
23.1 Independent Auditors' Report * See Page 24
hereof.
27.1 Financial Data Schedule *
</TABLE>
- --------------------------
*Filed herewith.
52
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K
FINANCIAL STATEMENTS FILED FOR THE PERIOD ENDING JUNE 30, 1996 AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000216991
<NAME> SAGE ENERGY COMPANY
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> JUN-30-1996
<PERIOD-START> JUL-01-1995
<PERIOD-END> JUN-30-1996
<CASH> 7,966
<SECURITIES> 0
<RECEIVABLES> 10,400
<ALLOWANCES> 0
<INVENTORY> 1,333
<CURRENT-ASSETS> 19,787
<PP&E> 132,496
<DEPRECIATION> 102,355
<TOTAL-ASSETS> 50,175
<CURRENT-LIABILITIES> 10,086
<BONDS> 18,030
0
0
<COMMON> 0
<OTHER-SE> 18,236
<TOTAL-LIABILITY-AND-EQUITY> 50,175
<SALES> 27,815
<TOTAL-REVENUES> 31,536
<CGS> 15,963
<TOTAL-COSTS> 17,361
<OTHER-EXPENSES> 6,024
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,545
<INCOME-PRETAX> 6,606
<INCOME-TAX> 2,221
<INCOME-CONTINUING> 4,385
<DISCONTINUED> 0
<EXTRAORDINARY> 41
<CHANGES> 0
<NET-INCOME> 4,426
<EPS-PRIMARY> 3,163
<EPS-DILUTED> 0
</TABLE>
