1
________________________________________________________________________________
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934 FOR THE
FISCAL YEAR ENDED JUNE 30, 1995
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 jurisdicition 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)
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 27,
1995.
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, 1995
----- ----------------------------
Common Stock ($.01 par value) 1,399
-----
________________________________________________________________________________
2
SAGE ENERGY COMPANY
ANNUAL REPORT (S.E.C. Form 10-K)
INDEX
Item Number and Description Page
--------------------------- ----
PART I
Item 1. Business................................................ 1
Item 2. Properties.............................................. 6
Item 3. Legal Proceedings....................................... 11
Item 4. Submission of Matters to a Vote of Security Holders..... 11
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters..................................... 11
Item 6. Selected Financial Data................................. 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 13
Item 8. Financial Statements and Supplementary Data............. 20
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure..................... 39
PART III
Item 10. Directors and Executive Officers of the Registrant...... 39
Item 11. Executive Compensation.................................. 40
Item 12. Security Ownership of Certain Beneficial Owners
and Management.......................................... 42
Item 13. Certain Relationships and Related Transactions.......... 42
PART IV and SIGNATURES
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................. 44
SIGNATURES........................................................ 46
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, whose activities developed from a Texas base, 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
in a gas field in Oklahoma 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
seven oil and gas drilling rigs (after selling nine and purchasing two in
fiscal 1995) with depth capabilities ranging from 7,500 to 14,500 feet. The
majority of these rigs were previously employed in exploratory and development
drilling for both the Company's own operations and for unaffiliated customers.
Additionally, the Company owns six service rigs used for completion and
remedial work on its own wells and those of others. As of June 30, 1995, all
but one of the Company's drilling rigs have been deactivated.
The Company's credit agreement was amended and restated as of March 9,
1992 (the "Restated Credit Agreement") and was 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, 1995. 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.
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.
1
4
Sage's principal offices are located at 10101 Reunion Place, Suite 800,
San Antonio, Texas, 78216 and its telephone number is (210) 340-2288.
(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.
Years Ended June 30,
------------------------------
1995 1994 1993
---- ---- ----
Oil and Gas Production
Revenues...................... $25,675,000 $30,089,000 $41,694,000
Operating profit ............. 6,483,000 7,337,000 15,829,000
Identifiable assets........... 34,124,000 34,694,000 39,642,000
Contract Drilling
Revenues...................... 2,450,000 3,169,000 1,978,000
Intersegment sales............ 818,000 1,327,000 679,000
Operating profit ............. 179,000 712,000 94,000
Identifiable assets........... 2,148,000 1,846,000 1,903,000
(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 1995 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
obtain price premiums from purchasers and has flexibility to switch purchasers
if it so desires. Approximately 54% of the Company's proved reserves at June
30, 1995 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 1995. Consequently, the financial results of the Company are
2
5
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 Company has been adversely affected by low gas prices since 1993,
but believes that it is well positioned to take advantage of any future price
increases.
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, 1995, the Company employed 103 full-time employees,
including 4 petroleum engineers, 6 geologists, 4 landmen, 1 attorney, 4
accountants, 1 drilling, 2 service and 8 production superintendents, and 57
field and 16 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 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
3
6
the Company began contract drilling operations and continued these operations
in fiscal 1994 and 1995 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 1995
exceeded 10% of revenues.
Sales as a
Type of Percent of
Service or Relationship Total
Name of Customer Product Sold to Company Revenue
- ---------------- ------------ ------------ ----------
Scurlock Permian Oil Company...... Crude Oil None 54%
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.
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. This
event was insignificant since market forces at that time had caused prices on
virtually all of the Company's decontrolled gas to fall below the
4
7
ceiling prices prior to decontrol. Future gas prices cannot be predicted.
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.
Various aspects of the energy industry and the nation's production and
use of its energy sources are the subject of numerous state and federal
legislative proposals. On October 8, 1992, comprehensive national energy
legislation came into effect which is focused on electric power, renewable
energy sources and conservation. The legislation, among other things,
guarantees equal treatment of domestic and imported natural gas supplies,
mandates expanded use of natural gas and other alternative fuel vehicles, funds
natural gas research and development, permits continued offshore drilling and
use of natural gas for electric generation, and adopts various conservation
measures designed to reduce consumption of imported oil. To date, such
legislation has not had a material adverse effect on the Company.
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.
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.
5
8
(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.
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 1995, the Company had additional working
interests in seven (7) wells which are not noted below and four (4) 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*
Oil Gas Dry Total
--- --- --- -----
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
Year ended June 30,
1991............. -- -- -- -- 1 1.00 1 1.00
1992............. -- -- -- -- 1 .75 1 .75
1993............. -- -- -- -- 1 1.00 1 1.00
1994............. -- -- -- -- 4 2.05 4 2.05
1995............. 3 1.5 3 1.5 2 1.50 8 4.50
DEVELOPMENT WELLS*
Oil Gas Dry Total
--- --- --- -----
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
Year ended June 30,
1991............. 10 9.55 1 .46 -- -- 11 10.01
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
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, 1995, there were two (2) gross (1.29 net) developmental
wells 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.
6
9
Oil and Gas Reserves
The total proved oil and gas reserves of the Company increased during
the fiscal year ended June 30, 1995 due in large part to purchases of
minerals-in-place. This increase was reduced somewhat by production during the
year. New oil discoveries and extensions were not sufficient to offset oil
production, however, decreases in reserves from oil and gas production were
more than offset by a combination of new discoveries and extensions, from
revisions of previous estimates and from purchases of minerals-in-place.
Proved oil and gas reserves of the Company (all of which are located in New
Mexico, Oklahoma, and Texas) have been estimated as of June 30, 1993, 1994 and
1995 by the Company. The estimates of oil reserves for fiscal 1993, 1994 and
1995 were based on average oil prices received by lease for the month of June
1993, 1994 and 1995 respectively, as a majority of the Company's crude oil is
sold under contracts based on average monthly postings. Gas reserves for
fiscal 1993, 1994 and 1995 were based on the most current prices available for
each lease at the time of the report which was June in most instances.
ESTIMATED PROVED DEVELOPED AND UNDEVELOPED RESERVES
YEAR ENDED YEAR ENDED YEAR ENDED
JUNE 30, 1995 JUNE 30, 1994 JUNE 30, 1993
------------- ------------- -------------
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)
-------- ------- -------- ------- -------- ------
Total proved reserves
developed and
undeveloped:
Beginning of period.. 5,325 30,280 5,966 29,055 8,199 30,124
Revisions of previous
estimates............ (258) 2,807 (86) 4,388 (52) 2,606
Purchases of minerals-
in-place............. 1,391 2,400 __ __ 441 798
New discoveries and
extensions........... 723 1,970 687 2,273 1,291 3,332
Production............ (1,003) (5,325) (1,242) (5,436) (1,518) (6,305)
Sales of minerals-in-
place................ - - - - (2,395) (1,500)
--------- --------- --------- --------- ------- -------
End of period......... 6,178 32,132 5,325 30,280 5,966 29,055
========= ========= ========= ========= ======= =======
Proved developed
reserves:
Beginning of period... 3,465 23,572 3,428 19,739 5,251 21,845
========= ========= ========= ========= ======= =======
End of period......... 3,640 25,273 3,465 23,572 3,428 19,739
========= ========= ========= ========= ======= =======
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.
7
10
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.
A summary projection of the Company's estimated future net revenues by
reserve categories for the fiscal years ended June 30, 1996, June 30, 1997 and
June 30, 1998 and the remainder thereafter are as follows. Separate
tabulations also shown as follows, present the Company's estimate of the
present value as of July 1, 1995 of the estimated future net revenues from
proved reserves based on an annual discount rate of 10%.
ESTIMATED FUTURE NET REVENUES FROM PROVED RESERVES
AS OF JULY 1, 1995
Proved
Developed
and Proved
Undeveloped Developed
----------- ----------
Year ended June 30, 1996.............. $12,293,697 $14,845,014
Year ended June 30, 1997.............. $13,859,759 $10,692,618
Year ended June 30, 1998.............. $11,037,623 $ 7,980,183
Remainder............................. $54,641,461 $31,359,504
----------- -----------
Total................................. $91,832,540 $64,877,319
=========== ===========
Estimated net revenues for proved undeveloped reserves have been reduced
to reflect capital costs necessary to convert such reserves from proved
undeveloped to proved developed.
PRESENT VALUE (10% DISCOUNT RATE) OF ESTIMATED
FUTURE NET REVENUES FROM PROVED RESERVES
AS OF JULY 1, 1995
Proved developed and undeveloped reserves:
Added in previous years................. $44,503,900
New discoveries and extensions.......... 5,637,000
Purchases of minerals-in-place.......... 6,695,731
-----------
Total as of July 1, 1995.............. $56,836,631
===========
Proved developed reserves.................... $45,416,133
===========
In computing the above future net revenues from proved reserves
attributable to the Company's interest, prices were based on average oil prices
received by lease for the month of June 1995. (The majority of the Company's
crude oil is sold under contract based on an average monthly posting). Gas
prices used in this report are based on the most current prices available for
each lease at the time of the report which is June 1995 in most instances.
8
11
Operating expense information was based on the twelve-month period ended
May 31, 1995. 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
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, depreciation or income
taxes. 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.
Years Ended June 30,
1995 1994 1993 1992 1991
------ ------ ------ ------ ------
Oil, Bbls.... 1,003,074 1,242,037 1,517,890 1,533,780 1,186,250
Gas, Mcf..... 5,325,469 5,436,173 6,305,158 4,780,999 4,569,595
The Company's average sales prices during the fiscal years ended June 30, 1993,
1994, and 1995 were $19.23, $15.49 and $17.22 per barrel of oil and $2.09,
$2.11 and $1.69 per Mcf of gas, respectively. The average prices for the
Company's oil and gas sales for the month of June 1995 were $17.41 per barrel
of oil and $1.65 per Mcf of gas. At June 30, 1995, the posted price for West
Texas Intermediate crude oil was $15.75 per barrel. The range of natural gas
prices received by the Company for the month of June 1995 was $.63 to $3.45 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, 1993, 1994 and 1995 were $2.90, $2.86 and $2.78
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.
PRODUCING WELLS DEVELOPED UNDEVELOPED
--------------- --------- -----------
OIL GAS ACREAGE ACREAGE
--- --- ------- -------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---
As of June 30,
1991.......... 599 458.03 55 45.31 56,999 47,478 48,103 42,908
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
9
12
The following table sets forth the Company's gross and net developed and
undeveloped oil and gas acreage by state as of June 30, 1995. "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.
Developed Undeveloped
Acreage Acreage Total
------- ------- -----
Gross Net Gross Net Gross Net
Acres Acres Acres Acres Acres Acres
----- ----- ----- ----- ----- -----
New Mexico........... 3,683 2,727 800 365 4,483 3,092
Oklahoma............. 13,600 13,120 640 640 14,240 13,760
Louisiana............ - - 697 697 697 697
Texas
Permian Basin...... 6,206 4,298 42,790 26,276 48,996 30,574
South Texas........ 33,726 24,752 42,799 23,038 76,525 47,790
North Dakota......... - - 82,914 44,057 82,914 44,057
South Dakota......... - - 40,926 29,819 40,926 29,819
------- ------- -------- -------- -------- -------
Total................ 57,215 44,897 211,566 124,892 268,781 169,789
======= ======= ======== ======== ======== =======
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 seven drilling rigs. The Company sold nine of
its rigs during fiscal 1995 and purchased two additional rigs. Because of
decreased activity in the contract drilling business, as of June 30, 1995, 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
10
13
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.
Rig # Draw Works Depth Capacity
----- ---------- --------------
Rig 3 National 370 9,000'
Rig 11 Ideco H-30 7,500'
Rig 15 Brewster N-75 14,500'
Rig 16 Brewster N-75 14,500'
Rig 18 National 610 13,000'
Rig 21 Brewster N-46 12,000'
Rig 22 National 610 13,000'
The Company also owns six service rigs used for completion and remedial
work.
Item 3. Legal Proceedings.
On June 30, 1995 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, 1995.
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, 1995. 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.
Dividends
The Company may consider the payment of cash dividends (in accordance
with applicable law and upon obtaining any necessary consents under the Credit
Agreement) 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 $18,530,000 is currently
outstanding. 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
11
14
"SAGA 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:
SALES
-----------
HIGH LOW
-------- -------
Quarter Ended:
September 30, 1993 . . . 84 1/4 81
December 31, 1993 . . . . . . 85 1/8 80
March 31, 1994 . . . . . . . 84 80
June 30, 1994 . . . . . . . . 88 1/8 79
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
The transfer agent for the Debentures is Texas Commerce Bank - National
Association. On June 30, 1995, there were approximately 111 holders of record
of the outstanding Debentures.
Item 6. Selected Financial Data.
SAGE ENERGY COMPANY (In thousands Except Per Share Data)
Years Ended June 30,
---------------------------------------------------
1995 1994 1993 1992 1991
---------------------------------------------------
Revenues $28,803 $32,342 $43,399 $36,896 $37,204
Net income $ 1,248 $ 5,261 $ 6,735 $ 2,868 $ 4,580
Net cash provided by
operating activities $ 9,241 $14,010 $21,917 $15,364 $13,488
Net cash used in
investing activities ($10,959) ($ 9,804) ($ 4,539) ($16,839) ($ 4,217)
Net cash used in
financing activities ($ 370) ($ 5,137) ($12,994) ($ 2,575) ($ 6,275)
Net income per
common share $ 892 $ 3,761 $ 4,814 $ 2,050 $ 3,274
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." 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.
- ------------------------------------------------------------------------------
12
15
Selected Balance Sheet Data
June 30,
-----------------------------------------------
1995 1994 1993 1992 1991
-----------------------------------------------
Current assets $11,540 $13,855 $16,675 $13,344 $12,526
Current liabilities $ 5,285 $ 6,761 $12,491 $15,600 $ 8,556
Working capital $ 6,254 $ 7,094 $ 4,184 ($ 2,256) $ 3,970
(deficit)
Total assets $41,791 $43,486 $49,632 $56,373 $52,604
Bonds payable $18,530 $18,580 $19,814 $19,814 $19,814
Long-term debt, net of
current portion $ - $ - $ - $ 7,375 $11,950
Stockholder's equity $13,810 $12,882 $ 7,941 $ 3,158 $ 790
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.
Item 7. Managements's Discussion and Analysis of Financial Condition and
Results of Operations.
Financial Position
Fiscal Year Ended June 30, 1995 and Fiscal Year Ended June 30, 1994
The Company's current ratio was 2.18 to 1 at the end of the fiscal year
ended June 30, 1995 as compared to the June 30, 1994 current ratio of 2.05 to
1. Cash on hand at the end of the 1995 fiscal year was $3,104,000 and
$5,192,000 at June 30, 1994. The indebtedness under the Company's Restated
Credit Agreement with Texas Commerce Bank ("the Bank") (discussed under
"Liquidity and Capital Resources"), was paid in full in fiscal 1994 and there
is presently no outstanding balance under the revolving credit facility
provided by the Bank.
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). Specifically, the Company spent
approximately $13,952,000 for capital expenditures as described below.
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.
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
13
16
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 a material adverse impact on the Company's financial position
or the result of operations at the time in which it is adopted.
Comparison of Years Ended June 30, 1995, 1994 and 1993
As noted above, the current ratio at the end of fiscal years 1995 and
1994 was 2.18 to 1 and 2.05 to 1, respectively. The current ratio at the end
of fiscal year 1993 was 1.33 to 1. The increase in the current ratio in fiscal
1994 as compared to June 30, 1993 is primarily the result of decreased
indebtedness. The Company had $3,104,000 in cash at the end of fiscal 1995 and
no short-term borrowings. The Company had $5,192,000 in cash at the end of
fiscal 1994 and no short-term borrowings. Cash at the end of fiscal 1993 was
$6,123,000 and short-term borrowings were $3,583,000. Cash was consumed in
fiscal 1995 for the reasons stated above. 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. In fiscal 1993, the Company used cash from
operations to, among other things, drill and rework wells, acquire producing
properties and leases for drilling, to reduce long-term debt and short-term
debt and pay estimated federal income taxes related to fiscal 1992 and 1993.
At June 30, 1993, there was an aggregate of $3,583,000 of current maturities of
long-term debt. There were no current maturities of long-term debt at June 30,
1994 or June 30, 1995.
Net fixed assets increased in fiscal 1995 for the reasons stated above.
The Company's net fixed assets decreased during fiscal 1994, as compared to
1993, primarily as a result of depletion and depreciation charges of
$11,610,000, and by write-offs of plugged and abandoned properties,
non-productive properties and expired leases of approximately $1,957,000. This
decrease was partially offset by additions to the Company's producing oil and
gas properties which result from drilling and recompletion work, and from
acquisitions of leases. These additions amounted to approximately $10,348,000.
Fiscal 1993 fixed assets decreased primarily as a result of depreciation and
depletion charges ($13,243,000), and by the sales of the "Harper Field" and
"Big Lake" properties and related assets in West Texas which had an aggregate
basis of $12,207,000. This decrease was partially offset by additions to the
Company's producing oil and gas properties as a result of drilling and
recompletion work from the acquisition of leases for horizontal drilling and
producing property acquisitions which in the aggregate amounted to
approximately $15,309,000. Charges to depreciation, depletion and amortization
increased during fiscal 1993 as a result of, among other reasons, increased
horizontal activities.
Statement of Financial Accounting Standards No. 109 (FAS 109),
"Accounting 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
14
17
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.
The Company does not provide post retirement benefits to its employees
and as a result, Statement of Accounting Standards No. 106 "Employers
Accounting for Post Retirement Benefits Other Than Pensions" and Statement of
Financial Accounting Standards No. 112 "Employer's Accounting for Post
Retirement Benefits" are not applicable to the Company and will not affect the
Financial Statements of the Company.
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 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 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 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 may incur additional indebtedness under
its revolving line of credit described below.
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 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 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 the current fiscal year.
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
15
18
Minor. The same period a year ago 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.
Results of Operations
June 30, 1994 and June 30, 1993
The Company's oil and gas revenues were lower in fiscal 1994 than the
prior fiscal year primarily as a result of substantially lower oil prices and
lower production. Specifically, substantially lower oil prices contributed to
the decline in revenue by approximately $5,341,000 and lower oil production
(excluding production from the "Harper Field" and "Big Lake" properties which
were sold during fiscal 1993) contributed approximately $2,556,000 to the
decline. The decrease in revenue and production attributable to the sold
properties in the prior year was approximately $2,171,000 of revenue and
approximately 111,000 barrels of oil and 48,000 Mcf of gas. Production costs
were less than the prior fiscal year primarily due to the sale of the "Harper
Field" and "Big Lake Field" properties in fiscal 1993.
Primarily as a result of the above, the Company's income from operations
before income taxes decreased resulting in a corresponding decrease to Federal
and State income taxes. Interest expense decreased by $448,000 as compared to
the prior year due primarily to decreased debt. The rate paid on indebtedness
to the Banks in fiscal 1994 was between 4.625% and 4.875% as compared to rates
between 4.75% and 6.0% during the 1993 fiscal year. The Company repaid
$1,100,000 under the bank facility on September 30, 1993 and December 31, 1993
($2,200,000 in total) with a final payment on March 31, 1994 of $1,382,703,
thereby eliminating the Company's bank debt at the present time.
Nonproductive exploration, property abandonment costs, and loss on sale
of assets increased in fiscal 1994 primarily as a result of write-offs of
certain nonproductive and expired leases (approximately $922,000), dry hole
costs (approximately $428,000) and plugged and abandoned well costs
(approximately $607,000). This amount was partially offset by the gain on the
sale of several marginal properties in fiscal 1994 which amounted to
approximately $49,000 before income taxes. The prior comparable fiscal year
included the loss on the sale of the "Harper Field" properties which was
incurred in the quarter ended December 31, 1992. Such sale was for
approximately $8,600,000 and resulted in a one time loss of approximately
$965,000 before income tax effect. Additionally, in September, 1992 the
Company sold its interest in the "Big Lake" properties in West Texas (except
for the deep rights) for $2,840,228. Such sale resulted in a gain of
approximately $192,000 before income tax effect and a reduction of
nonproductive exploration and property abandonment costs and loss on the sale
of assets in the prior year.
Expenses related to depreciation, depletion, and amortization costs
decreased in fiscal 1994 from the prior year primarily as a result of lower
production. General and administrative costs increased over the prior year as a
result of, among other things, the decreased allocations of general and
administrative expenses to third parties and to production costs by
approximately $747,000. The decrease in allocated costs to third parties is
primarily the result of the Company's fiscal 1993 sales of producing
properties.
Geological and geophysical costs increased in fiscal 1994 over the prior
fiscal year (by approximately $860,000 (377%) primarily as a result of
additional exploration undertakings including the 3-D siesmic activities
described above.
16
19
In fiscal 1994, the cumulative effect of change in accounting principal
of $4,250,000 relating to the adoption of FAS 109 was reported. No such item
occurred in the prior comparable year. (See prior discussion under "Financial
Position").
In June of fiscal 1994, the Company purchased and retired $1,234,000 face
value of its bonds resulting in a $141,000 extraordinary gain after tax
effects. No such repurchase occurred in fiscal 1993.
In fiscal 1994, the Company declared a cash dividend of $320,000 or
$228.73 per share to its sole shareholder. The prior fiscal year reflected a
dividend of $1,952,000 resulting from the purchase of producing properties from
Fargo Energy Corporation which is controlled by the inside directors of (and
shareholders of the sole shareholder of) the Company.
The Company completed sixteen (16) new producing wells as operator in
fiscal 1994 and reentered, recompleted, reworked or participated in a number of
others.
Liquidity and Capital Resources
The Company's long-term debt at the end of the 1995 fiscal year, consists
of its convertible Debentures which have an aggregate outstanding balance of
$18,530,000. 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 fiscal 1997. The Debentures are
convertible into cash at the rate of $260 per every $1,000 in principal amount
of debentures.
The term facility provided under the Company's Restated Credit Agreement
with Texas Commerce Bank National Association was fully repaid in March 1994.
The Restated Credit Agreement also provided for a revolving credit facility
pursuant to which the Company could borrow from time to time an amount
determined by reference to the Company's "borrowing base", but in no event more
than $10,000,000. Effective May 9, 1995, the Company entered into an amendment
to the Restated Credit Agreement (the "Amendment"). The Amendment generally
provides an extension of the Company's ability to borrow funds under the
revolving credit facility (until June 30, 1997) (the "Termination Date"). The
Amendment also decreases the amount that the Company may borrow down to
$3,000,000 under the revolving credit facility. The Amendment does not
contemplate additional term loans to the Company. 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, 1995, the Company had not drawn funds under the revolving credit
facility.
The Company entered into the Amendment for the primary purpose of
providing the Company with available funds following the acquisition of certain
properties and assets from Blanco Oil Company ("Blanco") in May 1995. In the
Blanco transaction, 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. 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). The Company received appraisals from third parties indicating
that the purchase price for the Blanco assets was at least at the fair market
value thereof. Such appraisals excluded the pipe inventory and vehicles.
The Company consummated the acquisition of oil and gas properties from
Blanco to generally increase the portfolio for longer life reserves. Although
management of the Company continues to deem it important to acquire additional
17
20
properties with longer life reserves at suitable prices, the Company may also
consider further sales of properties 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.
In March 1995, the Company sold, by auction, seven of its drilling rigs
for approximately $1,224,000. The Company had previously sold two of its
drilling rigs in the second and third quarter of fiscal 1995. The two rigs
acquired from Blanco are generally of higher quality than those sold by the
Company.
The Company also recently announced the implementation 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"). The Program may be terminated
at any time by the Board of Directors. To date, there have been no purchases
by the Company of its Debentures under the Program and there can be no
assurances that any purchases will be made.
For approximately the last three fiscal years, 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 to 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 the decrease in prices as well as from 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.
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 made estimated payments of Federal income taxes of $2,200,000
during the fiscal year ending June 30, 1995 for such fiscal year.
On December 6, 1994 the Company declared a cash dividend to its sole
shareholder of $228.73 per share (or an aggregate of $320,000). The Company's
sole shareholder is owned by and controlled by Michael Amini, Rex Amini, Ronald
Amini, and Jesse Minor. The Company may 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
18
21
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 1994, the Company also determined to pay
bonuses to four of its officers and directors aggregating $400,000.
The Company has 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. The Company has reacquired and cancelled Debentures in the face
amount of $11,470,000, which could, if the Company so elects, result in the
deferral of sinking fund payments until 1997. The Company reacquired and
cancelled an aggregate of $1,234,000 in principal amount of Debentures in
fiscal 1994 for an aggregate purchase price of $999,540 which resulted in an
extraordinary gain of approximately $141,000, net of tax effect. An additional
$50,000 in principal amount of Debentures was acquired and cancelled in fiscal
1995. The Company has recently announced the implementation of the Program
under which further repurchases may be made.
Liquidity is heavily affected by oil and gas prices. Oil prices
generally evidenced substantial declines during the 1994 fiscal year.
Additionally, natural gas prices are at low levels. 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.
Effective March 28, 1994, the Company entered into the Commodity Floor
Transaction (the "Floor Agreement") with Chemical Bank which terminated on
December 31, 1994. The Company paid $72,000 to Chemical Bank for the Floor
Agreement in March of 1994 but did not receive any payments thereunder.
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
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.
____________________________
19
22
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements and Schedules
Page
----
Independent Auditors' Report.................................... 21
Financial Statements:
Balance Sheets, June 30, 1995 and 1994................... 22
Statements of Operations, Years Ended June 30, 1995,
1994 and 1993............................................ 24
Statements of Stockholder's Equity,
Years Ended June 30, 1995, 1994 and 1993................. 25
Statements of Cash Flows, Years Ended June 30, 1995
1994 and 1993............................................ 26
Notes to Financial Statements............................ 27
Schedules: There are no financial schedules as the required information
is inapplicable or the information is presented in the Financial Statements or
related Notes.
20
23
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, 1995 and 1994, and the results of its operations and its cash flows for
each of the years in the three-year period ended June 30, 1995, 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."
/s/ KPMG Peat Marwick LLP
San Antonio, Texas
September 18, 1995
21
24
SAGE ENERGY COMPANY
Balance Sheets
(In Thousands)
Assets
June 30, June 30,
1995 1994
-------- ---------
Current assets:
Cash and cash equivalents $ 3,104 $ 5,192
Accounts receivable:
Trade ($ 648 in 1995 and $529 in 1994 1,827 1,788
from related parties - Note 2)
Oil and gas sales 4,156 5,602
Federal income tax refund 712 13
Inventories - well and production
equipment, at cost 1,483 1,197
Prepaid expenses 258 63
-------- --------
Total current assets 11,540 13,855
-------- --------
Property, plant and equipment, at cost
(Notes 6 and 9):
Producing oil and gas properties
(successful efforts method) 118,504 116,740
Undeveloped properties 4,044 2,515
Drilling equipment 9,673 17,378
Other 4,350 4,395
-------- --------
136,571 141,028
Less accumulated depreciation and
depletion (106,605) (111,714)
-------- --------
29,966 29,314
-------- --------
Other assets, at cost, net of accumulated
amortization 285 317
-------- --------
$ 41,791 $ 43,486
======== ========
See accompanying notes to the financial statements.
22
25
SAGE ENERGY COMPANY
Balance Sheets (Continued)
(In Thousands Except Share Data)
Liabilities and Stockholder's Equity June 30, June 30,
1995 1994
-------- --------
Current liabilities:
Accounts payable, trade $ 1,423 $ 1,783
Accrued liabilities (Note 4) 3,665 4,875
State income taxes payable (Note 10) 197 103
-------- --------
Total current liabilities 5,285 6,761
Bonds payable (Note 5) 18,530 18,580
Deferred income taxes 4,166 5,263
-------- --------
Total liabilities 27,981 30,604
-------- --------
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 13,796 12,868
-------- --------
Total stockholder's equity 13,810 12,882
Contingent liabilities (Note 17)
-------- --------
$ 41,791 $ 43,486
======== ========
See accompanying notes to the financial statements.
23
26
SAGE ENERGY COMPANY
Statements of Operations
(In Thousands Except Per Share and Share Data)
Years Ended June 30,
---------------------------------
1995 1994 1993
-------- --------- --------
Revenues:
Oil and gas sales $ 25,675 $ 30,089 $ 41,694
Contract drilling 1,632 1,842 1,299
Interest and other income 1,496 411 406
-------- --------- --------
Total revenues 28,803 32,342 43,399
-------- --------- --------
Costs and expenses:
Oil and gas operations:
Production taxes 1,286 1,361 1,827
Production costs 6,826 8,378 9,703
Nonproductive exploration,
property abandonment costs and
loss on sale of assets (Note 9) 3,005 1,980 1,732
-------- --------- --------
11,117 11,719 13,262
Contract drilling direct costs 1,358 1,242 1,074
Depreciation, depletion and amortization 8,670 11,643 13,243
Geological and geophysical 1,314 1,088 228
General and administrative 3,186 3,739 3,128
Interest 1,579 1,770 2,218
-------- --------- --------
Total costs and expenses 27,224 31,201 33,153
-------- --------- --------
Income from operations before income taxes 1,579 1,141 10,246
Income tax expense (benefit) (Note 10): 4,477
Federal - current 1,259 415 4,477
State - current 169 104 259
Federal - deferred (1,097) (248) (1,225)
-------- --------- --------
331 271 3,511
Income before extraordinary item and cumulative
effect of change in accounting for income taxes 1,248 870 6,735
Extraordinary item-debenture retirement
(net of Federal income taxes of $73
in 1994 - Note 5) - 141 -
-------- --------- --------
Income before cumulative effect of 6,735
change in accounting 1,248 1,011 6,735
Cumulative effect of change in accounting (Note 10) - 4,250 -
-------- --------- --------
Net income $ 1,248 $ 5,261 $ 6,735
======== ========= ========
Net income per common share:
Income before extraordinary item and cumulative
effect of change in accounting $ 892 $ 622 $ 4,814
Extraordinary item - 101 -
Cumulative effect of change in accounting - 3,038 -
-------- --------- --------
$ 892 $ 3,761 $ 4,814
======== ========= ========
Weighted average common shares outstanding 1,399 1,399 1,399
======== ========= ========
See accompanying notes to the financial statements.
24
27
SAGE ENERGY COMPANY
Statements of Stockholder's Equity
(In Thousands Except Share Data)
Common Stock Additional
------------------ Paid-In Retained
Shares Amount Capital Earnings Total
------------------ ----- -------- --------
Balances June 30, 1992 1,399 $ - $ 14 $ 3,144 $ 3,158
Cash dividend - Fargo purchase - - - (1,952) (1,952)
(Note 7)
Net income - - - 6,735 6,735
------------------ ----- -------- --------
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
===== ====== ===== ======== ========
See accompanying notes to the financial statements.
25
28
SAGE ENERGY COMPANY
Statements of Cash Flows
(In Thousands)
Years Ended June 30,
---------------------------------------
1995 1994 1993
------ ------- -------
Cash flows from operating activities:
Net income $ 1,248 $ 5,261 $ 6,735
------- ------- -------
Adjustments to reconcile net income to
net cash provided by operating activities:
Extraordinary item before Federal
income taxes - 214 -
Depreciation, depletion and
amortization 8,670 11,643 13,243
Loss on asset dispositions 1,669 1,273 1,368
Deferred income taxes (1,097) (4,124) (1,040)
Changes in current assets and
liabilities:
Accounts receivable 1,407 2,154 510
Inventories (286) (198) 471
Prepaid expenses (195) (54) 72
Accounts payable (360) (992) 75
Accrued liabilities (1,210) (608) 780
Federal income taxes receivable (699) (12) (440)
State income taxes payable 94 (547) 143
------- ------- -------
Total adjustments 7,993 8,749 15,182
------- ------- -------
Net cash provided by
operating activities 9,241 14,010 21,917
------- ------- -------
Cash flows from investing activities:
Proceeds from sales of assets 2,993 930 11,669
Capital expenditures (13,952) (10,734) (16,208)
------- ------- -------
Net cash used in investing
activities (10,959) (9,804) (4,539)
------- ------- -------
Cash flows from financing activities:
Short-term debt repayments - - (2,500)
Long-term debt retired (50) (1,234) -
Bank debt repayments - (3,583) (8,542)
Dividend paid (320) (320) (1,952)
------- ------- -------
Net cash used in
financing activities (370) (5,137) (12,994)
------- ------- -------
Net increase (decrease)in cash and cash equivalents (2,088) (931) 4,384
Cash and cash equivalents:
Beginning of year 5,192 6,123 1,739
------- ------- -------
End of year $ 3,104 $ 5,192 $ 6,123
======= ======= =======
See accompanying notes to the financial statements.
26
29
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,
Southeastern New Mexico and Oklahoma 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.
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
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
27
30
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.
Pursuant to the deferred method under APB Opinion 11, which was applied
in fiscal 1993 and prior years, deferred income taxes are recognized for income
and expense items that are reported in different years for financial reporting
purposes and income tax purposes using the tax rate applicable for the year of
the calculation. Under the deferred method, deferred taxes are not adjusted
for subsequent changes in tax rates.
2. Related Party Transactions
Related party accounts receivable at June 30, 1995 and 1994 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 1995 and 1994, the Company charged other related
parties for certain operating and drilling expenditures totaling $1,710,000 and
$2,603,000, respectively. During fiscal 1994, certain related parties
purchased interests in several wells drilled by the Company for approximately
$79,000. The Company also purchased the interests of another related party for
$13,000.
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).
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
28
31
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 a material 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:
Years Ended June 30,
----------------------
(In Thousands)
1995 1994
----------------------
Interest payable $ 328 $ 329
Royalties payable 2,785 3,863
Stock repurchases 162 166
Reserve for environmental
clean-up costs 200 200
Other 190 317
------- ------
$3,665 $4,875
======= ======
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 June, 1995 and 1994, the Company retired certain
debentures with a face value of $50,000 and $1,234,000, respectively. This
transaction resulted in an extraordinary gain of $141,000 in 1994, net of
taxes. The aggregate face amount of debentures which have been reacquired is
$11,470,000. The Company has exercised its option not to make the sinking fund
payment in 1995 and 1994. Sinking fund payments will be required commencing in
October, 1997 if no further debentures are acquired and retired. 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 was 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, 1995. 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, 1995, there were no borrowings outstanding with
respect to the revolving credit facility.
29
32
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 and 1994. The Company declared bonuses to
four of its officers and directors of approximately $400,000 and $480,000 which
were paid in March, 1995 and December, 1993 respectively. During December,
1992, the Company purchased the "Fargo" producing properties from a company
substantially owned by the inside directors of Sage. The excess of the
purchase price over the net depleted cost of the properties was accounted for
as a dividend of $1,952,000 in the accompanying financial statements.
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.
9. Sales of Assets
During the fiscal year ended June 30, 1993, the Company sold several oil
and gas properties and related assets in a series of transactions with various
parties. The properties were disposed of for an aggregate consideration of
$11,440,000 and resulted in a $773,000 loss before income tax effect. 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.
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. Prior years
financial statements have not been restated to apply the provisions of
Statement 109.
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 is attributable to current income tax expenses and $1,097,000 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, 1994 was $271,000, of which $519,000 was attributable to
current income tax expenses and $248,000 was attributable to deferred income
tax benefit.
Income tax expense attributable to income from operations before income
taxes for the year ended June 30, 1995 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:
30
33
Years Ended June 30,
-----------------------------------
(In Thousands)
1995 1994 1993
-----------------------------------
Tax expense computed at
statutory rate on income
before income taxes $ 537 $ 388 $3,484
Increase (decrease) in tax from:
Statutory depletion (258) (134) (197)
Deduction for state income taxes (67) (35) (88)
Other (50) (52) 53
State income taxes 169 104 259
------- ------- ------
$ 331 $ 271 $3,511
======= ======= ======
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at June 30,
1995 and 1994 are presented below:
Years Ended June 30,
--------------------------
(In Thousands)
1995 1994
--------------------------
Deferred tax assets:
State income taxes $ 239 $ 246
Deferred expenses for tax purposes 79 79
------- -------
Total gross deferred tax assets 318 325
Less valuation allowance - -
------- -------
Total deferred tax assets 318 325
Deferred tax liabilities:
Property and equipment, principally
due to differences in depreciation
and depletion 4,484 5,588
------- -------
Total gross deferred tax liability 4,484 5,588
------- -------
Net deferred tax liability $ 4,166 $ 5,263
======= =======
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.
For the year ended June 30, 1993, the deferred income tax benefit of
$1,225,000, resulted from timing differences in the recognition of income and
expense for income tax and financial reporting purposes. The sources and tax
effects of those timing differences are presented below:
Year Ended June 30
-----------------------
(In Thousands)
1993
-----------------------
Intangible development costs $ 3,456
Depreciation, depletion, amortization,
and asset dispositions (5,202)
Rate differential from alternative
minimum tax 715
Accrued state taxes (194)
Other accruals -
--------
$(1,225)
========
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
31
34
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, 1995, 1994 and 1993
were approximately $28,000, $32,000 and $42,000, respectively. The Company
also adopted an overriding royalty program in which the directors of the
Company participate. The value of the overriding royalty interests amounted to
approximately $35,650 in 1995 and $41,000 in 1994. These amounts were included
in compensation.
12. Supplemental Cash Flow Information
Years Ended June 30,
-----------------------------
(In Thousands)
1995 1994 1993
-----------------------------
Interest paid $1,580 $1,798 $2,241
====== ====== ======
Taxes paid $2,305 $1,164 $4,848
====== ====== ======
13. Segment Disclosure
A summary of revenues, operating profit, identifiable assets,
depreciation and depletion and property additions of each business segment is
shown below:
Years Ended June 30,
-----------------------------------------
(In Thousands)
Revenue-
Revenue Intersegment Nonsegment
By Segment Revenue Customers
-----------------------------------------
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
======== ======= =======
1993
- ---------------------------------------------------------------------------
Revenues:
Oil and gas production $41,694 $ - $41,694
Contract drilling 1,978 679 1,299
Other 406 - 406
-------- ------- -------
$44,078 $ 679 $43,399
======== ======= =======
The following is a summary of major customer purchases exceeding 10% of
the Company's revenues:
Years Ended June 30,
----------------------------------------
(In Thousands)
1995 1994 1993
----------------------------------------
Scurlock Permian Corporation $ 15,395 $17,418 $25,398
Aquila Southwest Pipeline - 3,634 4,506
Phillips Petroleum Company - - -
- ---------------------------------------------------------------------------
32
35
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.
Years Ended June 30,
-------------------------------------
(In Thousands)
1995 1994 1993
-------------------------------------
Operating profit:
Oil and gas production $ 6,483 $ 7,337 $15,829
Contract drilling 179 712 94
--------- --------- --------
6,662 8,049 15,923
Eliminations (145) (378) (123)
--------- --------- --------
Total operating profit 6,517 7,671 15,800
Geological and geophysical (1,314) (1,088) (228)
General corporate expenses and
other unallocated components of
other income and expenses - net (2,045) (3,672) (3,108)
Interest expense (1,579) (1,770) (2,218)
--------- --------- --------
Profit from operations
before income taxes $ 1,579 $ 1,141 $10,246
========= ========= ========
- ---------------------------------------------------------------------------
Years Ended June 30,
-------------------------------------
(In Thousands)
1995 1994 1993
-------------------------------------
Identifiable assets:
Oil and gas production, net $34,124 $34,694 $39,642
Contract drilling 2,148 1,846 1,903
Corporate assets 5,519 6,946 8,087
-------- -------- -------
$41,791 $43,486 $49,632
======== ======== =======
- ---------------------------------------------------------------------------
33
36
Years Ended June 30,
------------------------------------------------------------------------------------
(In Thousands)
1995 1994 1993
------------------------------------------------------------------------------------
Deprecia- Deprecia- Deprecia-
tion and Property tion and Property tion and Property
Depletion Additions Depletion Additions Depletion Additions
------------------------------------------------------------------------------------
Oil and gas
production $ 8,075 $12,538 $11,033 $10,348 $12,604 $15,309
Contract
drilling 240 1,196 266 91 254 369
Corporate 325 218 311 295 353 530
------- ------- ------- ------- ------- -------
$ 8,640 $13,952 $11,610 $10,734 $13,211 $16,208
======= ======= ======= ======= ======= =======
14. Supplementary Information
The following is a schedule of supplementary information:
Years Ended June 30,
---------------------------------
(In Thousands)
1995 1994 1993
---------------------------------
Income Statement:
Maintenance and repairs $ 314 $ 306 $ 280
Taxes, other than income:
Franchise 2 4 4
Production 1,285 1,361 1,826
Payroll and other 918 994 1,007
Rents 209 219 228
- ---------------------------------------------------------------------------
There were no royalties, advertising costs, or research and development
costs incurred.
34
37
15. Interim Results of Operations (Unaudited)
Per
(In Thousands) Common Share
Net Net
Income Income
Revenues (Loss) (Loss)
- ---------------------------------------------------------------------------
Year Ended June 30, 1995
- ------------------------
First quarter $ 8,373 $ 1,355 $ 969
Second quarter 6,395 13 9
Third quarter 7,384 164 117
Fourth quarter 6,651 (284) (203)
-------- --------- --------
$28,803 $ 1,248 $ 892
======== ========= ========
Year Ended June 30, 1994
- ------------------------
First quarter $ 9,239 $ 5,255 $ 3,756
Second quarter 8,141 (544) (389)
Third quarter 7,263 163 117
Fourth quarter 7,699 387 277
------- -------- --------
$32,342 $ 5,261 $ 3,761
======= ======== ========
Year Ended June 30, 1993
- ------------------------
First quarter $11,032 $ 1,972 $ 1,410
Second quarter 12,592 1,967 1,406
Third quarter 9,883 1,770 1,265
Fourth quarter 9,892 1,026 733
------- -------- --------
$43,399 $ 6,735 $ 4,814
======= ======== ========
16. 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.
June 30,
----------------------------------------
(In Thousands)
1995 1994 1993
----------------------------------------
Capitalized cost:
Producing properties $118,504 $ 116,740 $ 122,899
Undeveloped properties 4,044 2,515 2,401
--------- ---------- ----------
Total capitalized cost 122,548 119,255 125,300
Accumulated depreciation and
depletion (95,571) (92,786) (95,893)
--------- ---------- ----------
Net capitalized cost $ 26,977 $ 26,469 $ 29,407
========= ========== ==========
35
38
Years Ended June 30,
----------------------------------
(In Thousands)
1995 1994 1993
----------------------------------
Cost incurred:
Property acquisition cost:
Non-producing properties $ 3,451 $ 1,895 $ 1,959
Producing properties 3,201 202 544
Exploration costs 3,067 1,535 397
Development costs 4,911 8,169 12,653
The results of operations of the Company's oil and gas producing
activities are shown below:
Years Ended June 30,
----------------------------------
(In Thousands)
1995 1994 1993
----------------------------------
Oil and gas revenues $25,675 $30,089 $41,694
------- ------- -------
Less:
Production taxes 1,286 1,361 1,827
Production costs 6,826 8,378 9,703
Nonproductive exploration costs 3,005 1,980 1,732
Geological and geophysical 1,314 1,088 228
Depletion 8,075 11,033 12,604
------- ------- -------
20,506 23,840 26,094
------- ------- -------
Profit before income taxes 5,169 6,249 15,600
Income taxes 1,757 2,125 5,304
------- ------- -------
Net profit from oil and gas
producing activities (exclusive
of general corporate overhead
and financial cost) $ 3,412 $ 4,124 $10,296
======= ======= =======
The Company's interest in proved oil (including natural gas liquids) and
gas reserves are as follows:
Years Ended June 30,
--------------------------------------------------------------------
(In Thousands)
1995 1994 1993
--------------------------------------------------------------------
Bbls Mcf Bbls Mcf Bbls Mcf
--------------------------------------------------------------------
Beginning of year 5,325 30,280 5,966 29,055 8,199 30,124
Revisions of previous
estimates (258) 2,807 (86) 4,388 (52) 2,606
Purchase of minerals
in place 1,391 2,400 - - 441 798
New discoveries and
extensions 723 1,970 687 2,273 1,291 3,332
Production (1,003) (5,325) (1,242) (5,436) (1,518) (6,305)
Sales of minerals in place - - - - (2,395) (1,500)
-------- -------- -------- -------- -------- --------
End of year 6,178 32,132 5,325 30,280 5,966 29,055
======== ======== ======== ======== ======== ========
Proved developed reserves:
Balance at beginning of
year 3,465 23,572 3,428 19,739 5,251 21,845
Balance at end of year 3,640 25,273 3,465 23,572 3,428 19,739
- -----------------------------------------------------------------------------
36
39
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.
37
40
Years Ended June 30,
-------------------------------------------------
(In Thousands)
1995 1994 1993
-------------------------------------------------
Estimated cash inflows $159,905 $147,843 $ 158,556
Less:
Related estimated future
development and production
costs (68,073) (60,051) (70,717)
Estimated income taxes (26,986) (25,178) (24,390)
--------- --------- ----------
Estimated net cash
flows 64,846 62,614 63,449
Discount to reduce estimated
net cash flows to present
value (23,115) (19,766) (18,498)
--------- --------- ----------
Discounted present value of
estimated net cash flows $ 41,731 $ 42,848 $ 44,951
========= ========= ==========
Changes in discounted net cash
flows:
Increase (decrease):
Additions to proved reserves
resulting from extensions
and discoveries less
related cost $ 5,637 $ 8,756 $ 9,612
Purchase of minerals in place 6,696 - 2,906
Accretion of discount 5,793 6,000 7,466
Sales of oil and gas net of
production costs of $8,112,
$9,739 and $11,530 (17,563) (20,350) (30,164)
Revisions of previous estimates
Changes in prices 5,184 (2,752) (8,009)
Changes in quantities 1,481 4,340 2,120
Changes in future development
costs (8,115) 6,116 1,869
Changes of production
rates (timing) and other (257) (4,243) (461)
Changes in estimated income taxes 27 30 4,162
--------- --------- ----------
Net increase (decrease) (1,117) (2,103) (10,499)
Balance:
Beginning of year 42,848 44,951 55,450
--------- --------- ----------
End of year $ 41,731 $ 42,848 $ 44,951
========= ========= ==========
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.
38
41
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:
Name Age Position with Company
---- --- ---------------------
Jesse Minor 43 President and Director
Rex Amini 45 Executive Vice President,
Treasurer and Director
Stanley A. Paris, Jr. 46 Vice President - Finance
Jay Hardy 62 Vice President - Engineering
Michael Amini 38 Executive Vice President,
Secretary and Director
Ronald Amini 41 Executive Vice President and
Director
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 35, 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 with
the law firm of Arter, Hadden, Johnson & Bromberg. From March 1990 until
39
42
June 1992, he was associated with the law firm of Johnson Bromberg and Leeds, a
predecessor to Arter, Hadden, Johnson & Bromberg.
Harold J. Conrad, age 58, 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, 1995, 1994
and 1993 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 $100,000 in fiscal 1995.
SUMMARY COMPENSATION TABLE
Annual
Compensation
Year All other
Name and Principal Ended Salary Bonus Compensation
Position June 30, ($) ($) (1) (3) ($) (2)
Jesse Minor 1995 200,000 100,000 30,500
President and Director 1994 200,000 120,000 14,185
1993 194,183 100,000 1,455
Rex Amini 1995 200,000 100,000 25,847
Executive Vice President 1994 200,000 120,000 14,107
Treasurer and Director 1993 194,183 100,000 1,260
Michael Amini 1995 200,000 100,000 29,342
Executive Vice President 1994 200,000 120,000 13,223
Secretary and Director 1993 194,183 100,000 1,455
Ronald Amini 1995 200,000 100,000 22,812
Executive Vice President 1994 200,000 120,000 11,653
and Director 1993 194,183 100,000 1,117
Jay Hardy 1995 119,265 7,726 6,818
Vice President 1994 119,265 9,102 2,141
of Engineering 1993 119,116 7,419 2,141
40
43
(1) Cash bonuses for services rendered in fiscal years 1993, 1994 and 1995,
have been listed in the fiscal year paid.
(2) The stated amounts are Company matching contributions to the Sage Energy
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
Non-employee Directors of the Company receive an annual retainer of
$10,000.00. 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 1995
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 meets at the end of
each calendar year to determine compensation for the following year. The
following report was issued in December 1994.
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
reviewed and considered (i) the performance of 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
and (iv) the historical compensation of the executives and the performance of
the Company's debentures. The Compensation committee also considered the
present compensation levels of each of the Company's executive officers. In
reviewing such multiple factors, the Company's Compensation Committee had
access to reports of independent financial consultants concerning the
compensation of the chief executive officer of the company and its other
executives. After reviewing all of such items, the Compensation Committee
reviewed the appropriateness of increasing or decreasing base compensation of
any executive employee or the award of bonuses or similar form of incentive
compensation. The Compensation Committee also took note of the fact that the
41
44
Board had adopted the overriding royalty plan pursuant to which certain of the
Company's executive officers may receive incentive compensation during the 1994
fiscal year. The Company does not have any long-term employment agreements
with any of its executive employees.
The Company's operating performance is accorded significant weight in
determining executive compensation. Of the factors considered by the
Compensation Committee in reviewing executive compensation, the market price of
debentures is accorded very little weight because of the Compensation
Committee's belief that a multitude of factors (many of which exclude the
performance of the Company) may affect the market price of debentures.
The Compensation Committee believes that, in order for the Company to
succeed, it must provide appropriate incentives to its qualified executives.
In reviewing the compensation of the chief executive officer, the Board
reviewed all of the factors set forth above which are generally applicable to
all executives, but also placed increased emphasis on the performance of the
Company and the performance of the chief executive officer, and, to a lesser
degree, on the chief executive officer's compensation in previous years and the
compensation of chief executive officers in similar companies. The
Compensation Committee also accounted for the present "team" management
structure of the Company, under which each of the Company's four (4) most
highly compensated executives (including the chief executive officer) are
accorded roughly equivalent responsibilities and compensation.
In determining the chief executive officer's compensation for calendar
1995, the Compensation Committee determined to award the chief executive
officer a bonus of $100,000 (representing a decrease of $20,000 over the
previous year's bonus) but to maintain the chief executive officer's salary at
the previous year's level. The Compensation Committee took particular note of
the Company's sustained profitability since 1990, its fiscal 1994 net income of
approximately $5,261,000 ($1,011,000 exclusive of cumulative effect of change
in accounting), the Company's successful exploration and development program
and its administrative cost saving measures. The Compensation Committee also
noted the Company's full and early repayment of its outstanding indebtedness to
its bank lenders during the 1994 fiscal year. The Compensation Committee also
noted that the chief executive officer's total cash compensation was within the
range of the chief executive officers of similar size of similar companies.
/s/ Mark S. Solomon /s/ Harold J. Conrad
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 director or officer was indebted to the Company during the year ended
June 30, 1995 except for immaterial indebtedness arising in the ordinary course
of business.
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, 1995, or any presently proposed
42
45
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 $313 to $886 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.
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, 1995.
The Family Members' percentage working interest in such prospects
generally was 5% 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 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 $1,710,000 to
the above named persons.
In fiscal 1995, the Company repurchased all Debentures owned by Margaret
Amini (mother of Rex Amini, Michael Amini, Ronald Amini and Susan Amini-Minor)
for approximately $43,030 (the face value of such Debentures was $50,000) in
connection with the Blanco transaction. The Company believes that its purchase
in this transaction was on comparable terms to similar transactions in the
industry among unrelated parties.
The Company provided certain oil and gas well services for Blanco Oil
Company which is wholly owned by K.K. Amini (father of Sue Amini-Minor, Rex
Amini, Ron Amini and Michael Amini) during the fiscal year 1995. Such charges
were approximately $50,000 and which the Company believes are consistent with
those of comparable transactions in the industry. In addition, the Company
acquired certain properties and assets from Blanco Oil Company which occurred
in May 1995. In this transaction, 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. The Company also obtained two vehicles and pipe
inventory in the transaction, Messrs. Rex Amini, Ronald Amini, Michael Amini
and Jesse Minor purchased the remaining 50% of the oil and gas properties from
Blanco Oil Company for the same purchase price and two other drilling rigs for
$700,000. The Company has received appraisals from third parties indicating
that the purchase price for the Blanco Oil assets was at least at the fair
market value thereof. Such appraisals excluded the pipe inventory and
vehicles.
43
46
Mr. Solomon is a member of the law firm of Arter, Hadden, Johnson &
Bromberg. 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............................. 21
Balance Sheets, June 30, 1995 and 1994................... 22
Statements of Operations, Years ended
June 30, 1995, 1994 and 1993.......................... 24
Statements of Stockholder's Equity,
Years ended June 30, 1995, 1994 and 1993.............. 25
Statements of Cash Flows,
Years ended June 30, 1995, 1994 and 1993.............. 26
Notes to Financial Statements............................ 27
(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.
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.
44
47
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. *
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 21
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.
45
48
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 27, 1995
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.
Signatures Title Date
---------- ----- ----
/s/ Jesse Minor President and Director September 27, 1995
- --------------------------
(Jesse Minor)
/s/ Rex Amini Executive Vice President, September 27, 1995
- --------------------------
(Rex Amini) Treasurer and Director
/s/ Ronald Amini Executive Vice President September 27, 1995
- --------------------------
(Ronald Amini) and Director
/s/ Michael Amini Executive Vice President, September 27, 1995
- --------------------------
(Michael Amini) Secretary and Director
/s/ Stanley A. Paris, Jr. Vice President-Finance September 27, 1995
- --------------------------
(Stanley A. Paris, Jr.)
/s/ Mark S. Solomon Director September 27, 1995
- --------------------------
(Mark S. Solomon)
/s/ Harold J. Conrad Director September 27, 1995
- --------------------------
(Harold J. Conrad)
46
49
EXHIBIT INDEX
Exhibit
Number Exhibit Page No.
- ------ ------- --------
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.
47
50
Exhibit
Number Exhibit Page No.
- ------ ------- --------
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. *
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 21
hereof.
27.1 Financial Data Schedule *
___________________________
*Filed herewith.
48