<PAGE>
UNITED STATES 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 (FEE REQUIRED)
For the fiscal year ended December 31, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
- ------
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from ________ to ________
Commission file number 0-9976
ARCH PETROLEUM INC.
(Exact name of registrant as specified in its charter)
DELAWARE 83-0248900
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
777 Taylor Street, Suite II,
Fort Worth, Texas 76102
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (817)332-9209
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Name of each exchange
Title of each class on which registered
------------------------- ----------------------
Common Stock, par value $0.01 per share NASDAQ National Market
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No ________
-------
As of February 29, 1996, the aggregate market value of the voting stock held by
nonaffiliates of the registrant was $34,295,700 based on the closing price
reported by NASDAQ National Market.
As of February 29, 1996, there were 17,141,404 shares of the registrants Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Part III information is included in the Registrant's definitive proxy statement
which will be filed within 45 days of the date of this Form 10-K.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<S> <C> <C>
PART I Page
Item 1. Business................................................. 3
Item 2. Properties............................................... 7
Item 3. Legal Proceedings........................................ 10
Item 4. Submission of Matters to a Vote of Security Holders...... 10
PART II
Item 5. Market for Company's Common Stock and Related
Shareholder 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. Consolidated Financial Statements and Supplementary Data. 20
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................... 48
PART III
Item 10. Directors and Executive Officers of the Company.......... 48
Item 11. Executive Compensation................................... 48
Item 12. Security Ownership of Certain Beneficial Owners
and Management........................................... 48
Item 13. Certain Relationships and Related Transactions........... 48
PART IV
Item 14. Exhibits, Consolidated Financial Statement Schedules,
and Reports on Form 8-K.................................. 49
</TABLE>
Signatures
<PAGE>
PART I
ITEM 1. BUSINESS
Arch Petroleum Inc., a Delaware corporation, (together with its
subsidiaries, "the Company") primarily engages in oil and natural gas
exploration, development, production, transportation and marketing in the
Southwestern United States and subsequent to January 31, 1996, in Western
Canada. The Company is also active in the acquisition of interests in oil and
gas leases, both producing and non-producing. Threshold Development Company
("TDC"), an oil and gas exploration company, owns approximately 16.5% of the
Company's common stock as of December 31, 1995.
On October 30, 1992, the Company's Board of Directors approved the
change of the Company's fiscal year end from October 31 to December 31
retroactive to December 31, 1991.
On October 20, 1994, the Company sold the following securities to four
institutional investors in a private placement (the "Placement"): (a) 727,273
shares of its 8% Exchangeable Convertible Preferred Stock (the "Preferred
Stock"), $.01 par value, having an aggregate liquidation preference of
$20,000,000, (b) $500,000 aggregate principal amount of its 9.75% Series A
Convertible Subordinated Notes due 2004 (the "Series A Notes") and (c)
$4,500,000 aggregate principal amount of its Adjustable Rate Series B Notes due
2004 (the "Series B Notes" and, together with the Series A Notes, the "Notes").
Gross proceeds from the Placement were $20 million for the Preferred Stock and
$5 million for the Notes. The proceeds were used to pay down the Company's
revolving credit facility (the "Revolver") with Bank One, Texas, N.A. The Bank
of Scotland participates with Bank One in the Revolver.
On January 31, 1995, the Company's shareholders, in a special meeting,
approved an amendment to the Company's articles of incorporation whereby the
number of authorized shares of the Company's capital stock was increased from
26,000,000 shares to 51,000,000 shares. Common stock is designated for
50,000,000 shares and preferred stock is designated for the remaining 1,000,000
shares. The Company has reserved 9,090,909 shares of common stock for issuance
upon conversion of the securities in the Placement, if necessary, and has also
reserved 361,690 shares of common stock for issuance upon exercise of options
under its current incentive stock option plan.
On April 11, 1995, the Company purchased 100,000 shares of common
stock for its treasury from TDC at the then current market price.
See Note 13 in the consolidated financial statements for information
regarding revenues, operating profit and identifiable assets of the Company's
segments.
RECENT DEVELOPMENTS:
OIL AND GAS OPERATIONS
- ----------------------
In November 1992 the Company sold a volumetric production payment to
Enron Reserve Acquisition Corp. ("Enron") for $24.3 million. The Company
contracted to deliver to Enron the equivalent of approximately 17.9 Bcf of
natural gas from Company operated properties in the Keystone Ellenburger Field
("Keystone") over 5.7 years beginning in December 1992. The Company is
responsible for all costs of production, development and marketing of the
dedicated gas. The deferred revenue associated with this transaction is
recognized as the dedicated gas is delivered to Enron. In May 1993 the Railroad
Commission
3
<PAGE>
of Texas ("RRC") amended the field rules for Keystone reducing the allowable
production. Subsequent to this ruling, until February 1995 the Company was not
able to produce enough gas to satisfy the monthly delivery obligations to Enron.
This created a delay in the scheduled volume deliveries under the volumetric
production payment agreement.
Effective February 1, 1995 through October 31, 1995, the RRC amended
its interim order and established a system of field-wide allowables which
allowed the Company to produce and sell approximately 20.2 million cubic feet
(16.0 million net) of natural gas per day from its operated leases in Keystone.
As of February 1, 1995, the Company resumed full scheduled natural gas volume
deliveries under the existing production payment agreement. Approximately 9.0
million cubic feet of the natural gas produced each day from Company operated
leases is delivered to Enron. Proceeds from the sale of a portion of the
remaining net volumes may be used to offset past delivery volume delays.
For two months effective November 1, 1995, the operators of Keystone
agreed (with the RRC's approval) to reduce by approximately one-half, the daily
production from the field. This temporary modification to current allowables was
designed to provide the operators with additional information concerning the
reservoir dynamics. The Company's net production from operated and nonoperated
leases during this period was approximately 10.1 million cubic feet of natural
gas per day. The curtailment did not significantly impact the Company's
scheduled deliveries under the production payment agreement. During 1996 the
Company anticipates the RRC to establish allowables for Keystone which will
allow the Company to sell approximately 10.1 million cubic feet of natural gas
per day from its operated leases.
On March 31, 1994, the Company consummated an agreement with Chevron
U.S.A. Inc. to purchase certain oil and gas properties for a cash consideration
of $17.9 million. The Company borrowed the purchase price under the Revolver.
The properties, located in Lea County, New Mexico, included interests in
approximately 130 producing oil and gas wells. The Company operates and has a
significant working interest in the majority of these properties. The effective
date of the purchase was April 1, 1994.
Effective January 31, 1996, the Company acquired Trax Petroleums
Limited ("Trax"), a Canadian oil and gas exploration and development company
headquartered in Calgary, Alberta, Canada. The Company's January 9, 1996, cash
offer of Cdn. $0.71 for each of Trax's approximately 14,100,000 shares was
accepted by more than 91% of Trax shareholders. Effective February 12, 1996,
the Company completed the statutory compulsory acquisition of the remaining
shares of Trax through the depository, Montreal Trust Company of Canada. The
acquisition was made through Northern Arch Resources Ltd., a wholly-owned
Canadian subsidiary of the Company. The current Trax staff of employees and its
headquarters will remain in Calgary. The acquisition purchase price was
approximately Cdn. $10,000,000 (approximately US $7,400,000 at January 31,
1996).
Trax's November 30, 1995, oil and gas reserves, as estimated by its
independent engineers,totalled 964,000 barrels of oil and 1.38 billion cubic
feet of natural gas (1,193,000 BOE). The estimated future net income
attributable to these reserves (discounted at 15%) is Cdn. $11,100,000
(approximately US $8,100,000 at January 31, 1996). Estimated daily production
currently approximates 600 BOE. In addition to the existing reserve base, Trax
holds a large working interest in approximately 40,000 net undeveloped acres.
This acreage includes more than thirty distinct, high quality prospects which
are in various stages of development.
4
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NATURAL GAS PIPELINE OPERATIONS
- -------------------------------
In July 1992 the Company, in conjunction with Central States Energy
Corporation ("CSE"), formed Saginaw Pipeline Company, L.C. ("Saginaw") and
Industrial Natural Gas, L.C. ("ING"). Concurrent with this event, Saginaw
acquired a 6" pipeline that extends approximately 100 miles from Wichita Falls,
Texas to Saginaw, Texas. ING was formed to market the sales and transmission of
natural gas through the Saginaw pipeline. On September 27, 1995, the Company
resolved a membership interest dispute with CSE. The Company issued $45,000 and
25,000 shares of the Companys' unissued common stock to CSE. As a result of
this transaction, the Company now owns a 95% membership interest in Saginaw and
ING.
In January 1993 the Company acquired a 50% membership interest in Onyx
Pipeline Company, L.C. ("Onyx"). PURECO Inc. and Sejita Pipeline Company each
own a 25% membership interest. Onyx owns four pipelines (approximately 25
miles) which supply natural gas to four electric power plants owned by Central
Power and Light ("CPL") in Nueces, Hidalgo, Webb and San Patricio Counties, in
South Texas. Onyx's contract with CPL includes a provision for a portion of the
base load to the four plants. Onyx also competes to supply additional
quantities of gas which the plants require. Onyx also owns other pipelines,
including approximately 40 miles of gathering systems.
PRINCIPAL PRODUCTS AND MARKETS:
The Company's principal products are oil and natural gas. The
principal markets for such products are those wherein 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 production.
In its natural gas marketing and transmission activities, the Company
buys and resells natural gas, receiving a gross margin or spread equal to the
difference between the purchase price and the resale price of such natural gas.
In addition, the Company receives a fee for transmission of natural gas over
pipeline systems owned by the Company.
CUSTOMERS:
The Company markets and will continue to market its oil and gas
products to a number of purchasers and does not believe that the loss of any
single purchaser of its crude oil, condensate or natural gas production would
adversely affect its operations. During the year ended December 31, 1995, the
Company had two customers that represented 62% of total revenues from oil and
gas sales, Cheveron U.S.A. Inc. (31%) and Enron Gas Marketing (31%).
During 1995 Onyx sold natural gas to approximately 70 customers. CPL
is the largest customer of the Company, representing 58% of gross revenues from
pipeline sales. Onyx has a contract to deliver gas to CPL into 1999.
BACKLOG ORDERS AND GOVERNMENT CONTRACTS:
The Company has no amount of firm backlog orders, and is not a party
to any material contracts the termination of which or renegotiation of terms of
which may be made at the election of any government.
5
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COMPETITION:
The Company competes with numerous other companies and individuals in
the search for and the acquisition of attractive oil and gas properties and in
the marketing of oil and gas. The Company's competitors include major oil
companies, other independent oil companies and individuals, most of which have
financial resources, staffs and facilities substantially in excess of those of
the Company. The Company is not a major factor in the petroleum industry.
Competition in the acquisition of oil and gas prospects and properties
has become increasingly intense in recent years. The Company's ability to
acquire reserves in the future will depend not only on its ability to develop
its present properties, but also on its ability to select and acquire suitable
prospects for exploratory drilling or development.
Marketing competition is affected in part by the production levels of
domestic crude oil, crude oil imports, the proximity of pipelines to producing
properties and the regulation by states of allowable rates of production. All
of these variable factors are dependent on economic and political forces which
cannot be accurately predicted in advance.
Natural gas marketing is a highly competitive business. The Company
sells natural gas to customers who can purchase natural gas from other
suppliers. The Company competes with traditional regulated distribution
companies as well as an increasing number of natural gas producers, marketers
and brokers for the business of buying, selling and transporting natural gas.
Other entities, including unregulated affiliates of regulated pipeline companies
attempting to arrange direct sales of their own, have created natural gas
marketing companies which also compete with the Company.
ENVIRONMENTAL REGULATION:
Production of oil and gas by the Company is affected by state and
federal regulations. In most areas, the production of oil and gas is regulated
by conservation laws and regulations which set allowable rates of production and
otherwise control the conduct of oil and gas operations. In addition, the
Company's producing and drilling operations are also subject to environmental
protection regulations established by federal, state and local agencies. The
Company believes that it is currently in compliance with all applicable federal,
state and local environmental regulations.
The Company does not believe that such environmental regulations in
their present form have or will have any material effect upon its capital
expenditures or earnings. The Company's competitors are subject to the same
regulations to which the Company is subject and, therefore, such regulations
will not have any material effect upon competitive position. The Company does
not project any material capital expenditures for environmental control
facilities for any succeeding year.
GOVERNMENT REGULATION:
Federal regulation has had and is expected to continue to have a
significant effect on the natural gas marketing activities of the Company. Such
activities are affected by the Federal Energy Regulatory Commission ("FERC")
rules and orders issued pursuant to the Natural Gas Act ("NGA") and the Natural
Gas Policy Act of 1978 ("NGPA"). In general, both of these acts authorize the
FERC to regulate certain activities of companies engaged in the interstate sale
and transport of natural gas.
6
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Under the NGPA, natural gas was classified according to category,
based primarily on the age of the well producing the natural gas and the
location, character and permeability of the formation from which the natural gas
is produced, and price ceilings were established for the various categories of
natural gas. Most of the price ceilings established by the NGPA have been
abolished and many categories of natural gas have been deregulated. The Company
must comply with the price ceilings for the very limited volume of gas still
subject to the price ceilings, if any.
The natural gas industry is presently in a state of significant change
because of the adoption by FERC of "Order 636". The Order directly affects the
natural gas pipeline companies regulated by FERC, primarily with regard to
natural gas transportation services provided by those companies. In addition,
because of Order 636, most of those pipeline companies are no longer directly
acting as gas suppliers to the natural gas distribution companies serving gas
consumers in the United States. Due to these changes, the distribution
companies are forced to make new gas supply arrangements for their needs.
All of these changes affect both gas producers and marketers.
However, the changes have not materially adversely affected Company operations.
The states in which the Company conducts oil and gas activities also
regulate oil and gas production. Such rules may control the method of developing
new fields, the maximum daily production allowed from a well and the operation
of a well.
EMPLOYEES:
As of February 29, 1996, the Company had 50 full-time employees. These
employees are not represented by labor unions and the Company considers its
employee relations to be satisfactory.
ITEM 2. PROPERTIES
GENERAL:
The Company's corporate headquarters occupy approximately 9,745
square feet of leased office space located in Fort Worth, Texas. The Company
also leases 2,200 square feet of office space in Midland, Texas. Onyx leases
3,664 square feet of office space in Corpus Christi, Texas. Saginaw leases 500
square feet of office space in Wichita Falls, Texas. The Company owns small
field offices in Kermit, Texas, and in Eunice and Artesia, New Mexico.
OIL AND GAS RESERVES:
A description of the Company's net quantity of oil and gas reserves is
contained in the Unaudited Supplemental Oil and Gas Disclosures of the
accompanying consolidated financial statements. All oil and gas reserves were
estimated by Ryder Scott Company, independent petroleum engineers, and are
detailed in a report prepared for the exclusive use of the Company. All such
estimations were made in accordance with regulations promulgated by the
Securities and Exchange Commission ("SEC"). The reserve report is available for
examination at the corporate headquarters.
The Company has no long-term supply or similar agreements with foreign
governments or authorities. The Company has not filed with or included in
reports to any federal authority or agency, other than the SEC any estimate of
total proved net oil and gas reserves since December 31, 1994. All of the
Company's production, acreage and drilling activity is located in the United
States. In 1996, Trax's results of operations and its oil and gas reserves, all
of which are located in Western Canada, will be consolidated into the
7
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Company's financial statements.
The Company operates in an industry that is subject to volatile prices
for its products. Revenues from oil and gas production may be affected to a
significant degree by fluctuations in prices that are brought on by factors
beyond the Company's control.
The following table sets forth a summary of the Company's oil and gas
reserve quantities and present value of future net revenues associated
therewith.
<TABLE>
<CAPTION>
December 31,
-------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Present value of discounted future
net revenues before income taxes $64,296,200 $61,078,500 $39,252,500
Quantities of reserves:
Proved developed and undeveloped:
Oil (Bbls) 4,030,300 3,586,400 1,585,700
Gas (Mcf) 61,286,400 61,546,200 43,553,600
Proved developed:
Oil (Bbls) 2,993,600 3,390,600 1,368,600
Gas (Mcf) 55,628,500 60,666,200 41,785,500
</TABLE>
The figures above exclude 11.9 Bcf, 15.5 Bcf and 16.1 Bcf of proved gas
reserves and $11,672,700, $12,566,300 and $12,860,100 of discounted future net
revenues at December 31, 1995, 1994 and 1993, respectively, which were sold to
Enron in the volumetric production payment discussed earlier. See the Unaudited
Supplemental Oil and Gas Disclosures in the accompanying consolidated financial
statements for key factors and additional information related to the Company's
reserve estimates.
WELLS DRILLED:
The following table shows the wells drilled by or participated in by the
Company since 1993. Gross wells refer to the total number of wells in which the
Company has an interest. Net wells are the gross wells multiplied by the
Company's working interest in each well. A dry well is one that is found to be
incapable of producing commercial amounts of oil or gas, and a productive well
is one that is not dry.
<TABLE>
<CAPTION>
Gross Wells Net Wells
------------------------- ---------------------
Produc- Produc-
tive Dry Total tive Dry Total
------- --- ----------- --------- --- -----
<S> <C> <C> <C> <C> <C> <C>
Year Ended December 31,1995:
Exploratory - 4 4 - 2.2 2.2
Development 110 - 110 13.4 - 13.4
Year Ended December 31,1994:
Exploratory - - - - - -
Development 34 - 34 17.9 - 17.9
Year Ended December 31,1993:
Exploratory - - - - - -
Development 32 - 32 12.6 - 12.6
</TABLE>
8
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LEASES AND WELLS OWNED:
At December 31, 1995, the Company owned interests in 83,333 gross developed
acres and 17,252 net developed acres. It also owned an interest in 117,433
gross undeveloped acres and 45,455 net undeveloped acres, the majority of which
is held by production.
The leases and wells acquired in the Trax purchase effective January 31, 1996,
are not included in the information below. See also the discussion of Proposed
Drilling Activity and Acquisitions.
As of December 31, 1995, the Company's interests in wells owned were as
follows:
<TABLE>
<CAPTION>
Total Texas New Mexico
----------------- ------------ ------------
Gross Net Gross Net Gross Net
Type Wells Wells Wells Wells Wells Wells
- ------- ----- ---------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Oil 1,356 253.3 1,223 145.5 133 107.8
Gas 204 121.0 117 55.8 87 65.2
----- ----- ----- ----- --- -----
1,560 374.3 1,340 201.3 220 173.0
===== ===== ===== ===== === =====
</TABLE>
In addition, the Company owns royalty interests in
approximately 400 productive wells located in West Texas.
PRODUCTION:
The following table reflects net quantities of oil (including
condensate and natural gas liquids) and of gas produced, the average price
received per barrel of oil and per Mcf of gas and the average production
(lifting) cost per equivalent barrel.
<TABLE>
<CAPTION>
Oil (Bbl) Gas (Mcf) Avg. Lifting
--------------------- ----------------------- Cost Per
Volume Avg Price Volume Avg Price Eq. Bbl (1)
------- --------- --------- --------- ------------
<S> <C> <C> <C> <C> <C>
1993 (2) 159,500 $17.36 3,851,500 $1.39 $5.35
1994 (3) 281,300 16.18 2,488,900 1.67 5.07
1995 (4) 382,100 17.28 7,382,900 1.32 4.45
</TABLE>
(1) Equivalent barrels are calculated using a conversion factor of six Mcf
of gas to one barrel of oil. Costs include severance taxes.
(2) Includes effect of production payment volume of 1,382,900 Mcf at an
average price of $1.30 and losses of $783,600 resulting from a natural gas swap
transaction.
(3) Includes effect of production payment volume of 183,300 Mcf at an
average price of $1.28.
(4) Includes effect of production payment volume of 3,090,400 Mcf at an
average price of $1.11.
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PROPOSED DRILLING ACTIVITY AND ACQUISITIONS:
In late 1995 the Company began an infill drilling program in the Teague
field area of its New Mexico properties. The first phase of this program
comprises seven wells to be drilled by the end of the first quarter 1996. As of
February 29, 1996, six of these wells had been successfully drilled and
completed. Phase two of the infill program identifies up to twenty wells.
Drilling commences upon the completion of phase one. If the Teague infill
program continues successfully, the Company could drill up to forty wells in
this field in the next three years. In addition the Company plans to recomplete
numerous existing wells in the next two years if economic conditions are
favorable. The Company expects to participate in similar development
operations in non-operated properties on various other wells.
The Company is involved in a 3-D seismic program encompassing three
different regions in North Texas, West Texas and the Texas Panhandle area. In
North Texas, the Company participated in the drilling of two successful
development wells during 1995 using the 3-D data. The 3-D data also confirmed
several quality development locations which had been tentatively identified by
geology before the 3-D survey was conducted. These locations can be developed
at reasonable costs and may be drilled to capitalize on improved product prices.
In addition to providing confirmation of the known locations, a number of deeper
structures were identified by the 3-D seismic program.
During 1995 the Company drilled two non-commercial wells in both the West
Texas and the Texas Panhandle prospect areas. The 3-D seismic and its
interpretation was very effective in locating the drilling targets zones as
expected. However, commercial quantities of hydrocarbons were not encountered
in these wells. There are productive multi-pay zones in both prospect areas.
The Company is continuing to develop and interpret the seismic information for
both of these prospects.
ITEM 3. LEGAL PROCEEDINGS
From time to time the Company is involved in litigation arising in the
normal course of business. In the opinion of management, the Company's ultimate
liability, if any, from lawsuits currently pending would not materially affect
the Company's financial condition or operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's shareholders during
the quarter ended December 31, 1995.
10
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PART II
ITEM 5. MARKET FOR COMPANY'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
The Company's common stock trades on the NASDAQ National Market under the
symbol "ARCH". The following table sets forth the high and low prices of the
Company's stock as reported by NASDAQ for the period from January 1, 1994,
through December 31, 1995. These price quotations represent prices between
dealers, do not include retail mark ups, mark downs, commissions or other
adjustments and do not necessarily represent actual transactions. On February
29, 1996, the closing price for the Company's common stock was $2-3/4.
<TABLE>
<CAPTION>
1995 1994
------------------ ----------------
Period High Low High Low
-------- -------- ------ --------
<S> <C> <C> <C> <C>
lst quarter $2-3/16 $1-11/16 $2-5/8 $2
2nd quarter 2-15/16 1-3/4 2-5/8 2-1/8
3rd quarter 3-1/16 2-1/4 2-3/8 1-15/16
4th quarter 2-11/16 1-11/16 2-1/4 1-15/16
</TABLE>
There were approximately 1,600 shareholders of record as of December 31,
1995.
No cash dividends have been paid on common stock to date. See Note 6 of
the accompanying consolidated financial statements for discussion of restriction
related to common stock dividends. The Company intends to maintain a policy of
retaining earnings for use in the expansion of business.
Transfer Agent: Harris Trust and Savings Bank
P. O. Box 755
Chicago, IL 60690-0755
Investor Relations: Arch Petroleum Inc.
Attention: Ralph Manoushagian
777 Taylor Street, Suite II
Fort Worth, Texas 76102
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ITEM 6. SELECTED FINANCIAL DATA
The selected financial information set forth below was derived from the
consolidated financial statements of the Company included in this report (see
Item 8) and should be read in conjunction with them and Item 7 "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
<TABLE>
<CAPTION>
Two Months Year
Year Ended December 31, Ended Ended
-------------------------------------------- December 31, October 31,
(In Thousands) 1995 1994 1993 1992 1991 1991
------- ------- ------- -------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
OPERATING DATA:
- ---------------
Operating revenues (1) $66,590 $82,696 $44,148 $ 7,226 $ 883 $16,021
Exploration expense 898 1,641 157 24 9 108
Income (loss) before
extraordinary item and
cumulative effect
of accounting change (164) (1,830) 176 68 60 6,991
Net income (loss) (164) (1,830) 176 68 - 6,991
Preferred stock dividends 1,600 311 - - - 152
Net income (loss) available
per common share (.10) (.12) .01 - - .42
Weighted average common and
common equivalent shares
outstanding 17,195 17,244 17,142 16,884 16,802 16,470
BALANCE SHEET DATA:
- --------------------------------
Total assets $79,672 $78,025 $51,069 $40,993 $26,238 $25,753
Deferred revenue 16,037 20,690 21,499 23,559 - -
Long-term debt 17,821 9,632 6,500 - 10,000 9,000
Convertible subordinated notes 5,000 5,000 - - - -
Convertible preferred stock 20,000 20,000 - - - -
Shareholders' equity 7,595 9,490 11,679 11,855 12,032 11,963
</TABLE>
No cash dividends have been paid on common stock since inception. See Note 6 of
the accompanying consolidated financial statements for discussion of restriction
on common stock dividends.
(1) Included in 1991 operating revenues is a gain on sale of properties of
$9,119,000.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
With the exception of historical information, the matters discussed herein are
forward-looking statements that involve risks and uncertainties including, but
not limited to, oil and gas price fluctuations, economic conditions, interest
rate fluctuations, the regulatory and political environments and other risks
indicated in filings with the Securities and Exchange Commission.
The following review of operations for the years ended December 31, 1995, 1994
and 1993 should be read in conjunction with the consolidated financial
statements presented elsewhere.
CAPITAL RESOURCES AND LIQUIDITY
FINANCIAL POSITION. At December 31, 1995 the Company's total assets increased
to $79.7 million from $78.0 million at December 31, 1994. Oil and gas
properties increased $5.2 million as a result of development drilling as well as
the recompletion and refurbishment of existing wells in New Mexico. The
Company's working capital ratio was .9 at December 31, 1995 and 1994.
The volumetric production payment sale to Enron on December 1, 1992, generated
$24.3 million cash. The proceeds of the sale were first used to retire all $16.1
million of bank debt outstanding at that time. The proceeds from the production
payment sale, less origination fees and revenue recognized as of December 31,
1992, were recorded as deferred revenue of $23.6 million. This revenue is
recognized as the gas reserves (originally 17.9 Bcf) from Company operated
interests in the Keystone Ellenburger Field ("Keystone") are produced and
delivered to Enron. The Company is responsible for all costs of production,
development and marketing of the dedicated gas.
The Company recognized deferred revenues of $3.5 million, $0.2 million and
$1.8 million during 1995, 1994 and 1993, respectively. The Company remitted
$1.2 million, $0.6 million and $0.3 million to Enron during 1995, 1994 and 1993,
respectively, in satisfaction of the Remedy Adjustment discussed below and in
Note 5 to the consolidated financial statements. The proceeds for these
payments were provided by a portion of the sale of allowable oil and casing head
gas, as well as from gas produced in excess of the scheduled production payment
volumes from Keystone, and which are made in addition to scheduled natural gas
volume deliveries. Based on the expected deliveries under the agreement and the
current product prices, estimated annual amortization of remaining deferred
revenue is expected to be $6.8 million, $6.6 million and $2.6 million for 1996,
1997 and 1998, respectively.
At December 31, 1995, the estimated remaining volumes deliverable to Enron
under the production payment agreement were 11.9 Bcf of natural gas (including
3.6 Bcf of natural gas attributable to volume delivery delays resulting from
field rule changes in prior periods). Pursuant to the agreement, the remedies
for these volume delivery delays (the "Remedy Adjustment") are confined to sales
only from Company operated properties in Keystone. Effective February 1, 1995
through October 31, 1995, the RRC amended its interim order issued in May 1993
and implemented a system of field-wide allowables which allowed the Company to
fully meet its scheduled delivery of volumes under the production payment
agreement and reduce the Remedy Adjustment. However, effective November 1, 1995,
the RRC once again restricted the allowables thereby impeding the Company's
ability to meet its scheduled deliveries. During 1996 the Company anticipates
the RRC to establish allowables for Keystone which will allow the Company to
sell approximately 10.1 million cubic feet of natural gas per day from its
operated leases in Keystone. However, there can be no assurance that the RRC
will issue orders which would allow production to resume at a rate to meet
scheduled deliveries and reduce the Remedy Adjustment. The amount of volumes,
if any, which will be necessary to satisfy the Remedy Adjustment is
13
<PAGE>
dependent upon future gas prices. Based upon economics at December 31, 1995,
the Company may deliver approximately 1.4 Bcf of natural gas volumes in excess
of the original contracted delivery volumes in this regard.
The Company's Revolver, which the Company entered into on April 6, 1990 (last
amended on September 30, 1995, the third amendment) is in place for use by the
Company at its discretion including drilling, development and acquisition of oil
and gas properties. The Company has borrowed $15.3 million against the Revolver
at December 31, 1995. The Revolver's borrowing base is the amount that the bank
commits to loan to the Company based on the designated loan value established by
the bank at its sole discretion and assigned to substantially all of the
Company's oil and gas properties which serve as collateral for any loan which
may be outstanding under the Revolver. The Revolver facility is $50.0 million
and the borrowing base is currently $30.0 million. The borrowing base is
reviewed semiannually by the bank at their discretion. A commitment fee of one
half of one percent of the unused borrowing base accrues and is payable
quarterly. Borrowings under the Revolver will, at the Company's option, bear
interest either at the bank's Base Rate (national prime rate) or a rate based on
the London Interbank Offered Rate (LIBOR). The average actual interest rate was
8.0% at December 31, 1995. Interest is payable monthly and no principal
payments are required until maturity, which is May 1, 1997.
The Onyx Term Loan Agreement (the "Onyx Note"), which Onyx entered into with
the Bank of Scotland on March 30, 1994 (last amended September 30, 1994, the
first amendment), is a separate facility and provided Onyx with $5.0 million.
The Onyx Note bears interest at national prime rate plus one-half of one percent
(9.00% at December 31, 1995). Interest on the unpaid principal amount of the
note is payable quarterly and commenced on June 30, 1994. The unpaid principal
($3,611,000 at December 31, 1995), is payable in eighteen quarterly installments
ending on March 31, 1999. Current maturities of the Onyx Note total $1.1
million at December 31, 1995. The Onyx Note is collateralized by certain of
Onyx's pipelines, gathering facilities and related transportation contracts. In
addition, the Onyx Note is guaranteed by the Company.
Both the Revolver and Onyx note contain normal and standard covenants
generally found in lending agreements. Among other things, these covenants
prohibit the declaration and payment of cash dividends on the Company's common
stock. In addition, the covenants stipulate the maintenance of financial
criteria including: a minimum level of net worth, a certain current ratio, a
certain debt to net worth ratio and a defined net income in excess of scheduled
interest and principal payments. The Company and Onyx are currently in
compliance with the loan agreements. Neither the Company nor Onyx has any
additional unused lines of credit.
Effective January 31, 1996, the Company acquired Trax Petroleums Limited
("Trax"), a Canadian oil and gas exploration and development company. The
Company acquired 100% of the approximately 14,100,000 Trax common shares through
Northern Arch Resources Ltd., ("Northern Arch") a wholly-owned Canadian
subsidiary of the Company. The acquisition price was approximately Cdn.
$10,000,000 (approximately U.S. $7,400,000 at January 31, 1996).
On February 20, 1996, the Company entered into two new bank credit facilities:
the Third Restated Revolving Credit Loan Agreement among the Company and Bank
One, Texas, N.A., the Agent bank, and other banks (the "Domestic Revolver") and
through its new 100% - owned subsidiary, Trax, the Credit Agreement among Trax
and Bank of Montreal, the Canadian Agent bank, and other financial institutions
(the "Canadian Revolver"). The two credit facilities are separate bank
revolvers. It was the Company's desire to have "cross border" facilities in
place to accommodate the Trax acquisition that led to these new credit
facilities.
The Domestic Revolver is a modification of the Company's existing Revolver
with Bank One, Texas, N.A. and its participant, the Bank of Scotland. The
principal changes to the former Revolver was the introduction of certain
language, terms and concepts such that the Domestic Revolver and the Canadian
Revolver
14
<PAGE>
will be accommodated in pari passu sharing and general administration. This
facility amends, restates and supersedes in its entirety the former Revolver.
The facility remains at $50,000,000 and the current borrowing
base also remains at $30,000,000. The Domestic Revolver matures on May 1, 1997.
The security collateral requirements and the bank covenants and default
provisions are essentially unchanged from the former Revolver.
The Canadian Revolver is similar to the Domestic Revolver in all significant
aspects. The loans under the Canadian Revolver are guaranteed by the Company
("the Guaranty") and is secured by, among other things, a first lien on 65% of
the issued and outstanding shares of Northern Arch's common stock and a first
lien on the oil and gas properties of the Company which serve as security in the
Domestic Revolver. The Guaranty is intended to rank pari passu with the
Company's obligations under the Domestic Revolver. The Canadian Revolver is
also guaranteed by Northern Arch.
The facility's initial commitment is U.S. $11,000,000. The proceeds of each
advance may be used to fund the loan from Trax to Northern Arch up to U.S.
$8,000,000 (which funded the acquisition of Trax), to acquire additional
borrowing base properties, to drill and recomplete oil and gas wells and for
general corporate purposes. Repayments shall be made relative to the currency
used in each borrowing. The Canadian Revolver matures on May 1, 1997. There is
a commitment fee of one half of one percent for the unused borrowing base which
accrues and is payable on the first day of each quarter.
The Trax borrowing base, which was designated as zero at date of closing, is
the loan value determined by the Canadian Agent bank in its sole discretion
based on its calculations of value of borrowing base properties utilizing
current and customary procedures and standards for petroleum industry customers.
The Canadian Agent bank is currently studying and evaluating Trax's properties.
On October 20, 1994, the Company sold in a private placement (the "Placement")
727,273 shares of its 8% Exchangeable Convertible Preferred Stock having a
liquidation preference of $20,000,000 and $5,000,000 of Convertible Subordinated
Notes. The Preferred Stock accrues annual dividends at the rate of $2.20 per
share. Dividends are payable semiannually and commenced April 20, 1995. During
1995 the Company paid $1,600,000 in dividends. The Notes bear interest at
9.75%. Interest on the unpaid principal balance of the Notes is payable
quarterly and commenced January 20, 1995. During 1995 the Company paid $488,000
in interest. Gross proceeds from the Placement were used to pay down the
Company's Revolver with Bank One, Texas, N.A. and the Bank of Scotland.
Sources and Uses of Capital Resources. In 1995 the Company's principal sources
of funds were $8.2 million (net) from the Revolver and $2.0 million from
operations (excluding production payment remedy adjustment). These funds were
consumed by: funding $6.1 million for development of existing properties in New
Mexico and Texas and providing $1.8 million to financing activities including
$1.6 million in preferred stock dividends and $0.2 million for treasury shares.
In 1994 the Company's significant sources of funds were $25.0 million from the
Placement and $32.9 million in borrowings from its debt facilities. These funds
were utilized to retire $28.7 million in bank debt, to fund $18.7 million in
developed and undeveloped oil and gas property acquisitions, to fund $5.8
million in development of existing properties in New Mexico and Texas, including
the Keystone Ellenburger Field properties, to fund $2.9 million in pipeline
acquisition and construction costs and to fund $1.6 million of the Company's 3-D
seismic activities in Stonewall County and the Panhandle of Texas.
In 1993 the Company's significant sources of funds were $6.5 million in
borrowings from its Revolver, $0.8 million from net operating cash flows and the
remaining cash proceeds ($7.0 million) from the Enron production payment sale.
These funds were utilized to fund $5.7 million in pipeline acquisition and
construction
15
<PAGE>
costs and $5.4 million in development of existing wells, including the Keystone
Ellenburger Field properties.
The RRC is empowered to prevent waste and protect correlative rights and, in
part, to oversee the oil and gas operators in Texas. It routinely rules in
disagreements among operators and establishes "allowables" for all wells.
Allowables are the rates of production for a specific well, generally stated in
terms of barrels of oil or thousand cubic feet ("Mcf") of natural gas per day.
Keystone is operated by three operators, including the Company. For at least
two decades this field has been produced at certain allowable rates, under rules
established by the RRC, so as to maximize the economic recovery of oil before
the vast reserves of natural gas are produced. There had arisen a difference of
opinion among the operators in the past three years concerning the appropriate
rules necessary to maximize the economic recovery of oil and natural gas
reserves in the field.
In May 1993 the RRC amended the field rules regarding formation water
production in Keystone. Subsequent to this ruling, until February 1995 the
Company produced approximately 18.9 million barrels of formation water, thus
earning and accumulating a bonus production allowable of approximately 9.5
million Mcf of natural gas. As a result, the Company incurred high water
lifting costs without realizing the related natural gas revenues during this
period.
Effective February 1, 1995 through October 31, 1995, the RRC amended its
interim order and established a system of field-wide allowables which allows
the Company to produce and sell approximately 20.2 million cubic feet (16.0
million, net) of natural gas per day from its operated leases in Keystone. The
Company continues to produce approximately 15,000 barrels of formation water per
day. Concurrent with the implementation of the new field rules, the Company
ceased to capitalize water lifting program costs and commenced amortization of
the deferred water production costs as the bonus production allowable is
produced. At December 31, 1995 and 1994, the Company had deferred $5.1 million
and $5.6 million, respectively, of net water production costs. These costs have
been included in proved oil and gas properties. As of December 31, 1995, the
Company has amortized approximately $0.6 million of the deferred water
production costs. On February 1, 1995, the Company resumed full scheduled
natural gas volume deliveries under the existing production payment agreement.
Approximately 9.0 million cubic feet of the natural gas produced each day from
Company operated leases is delivered to Enron. Proceeds from the sale of a
portion of the remaining net volumes is being used to offset past volume under
deliveries.
In November and December 1995 the operators of Keystone agreed (with the RRC's
approval) to reduce, by approximately one-half, the daily production from the
field. This temporary modification to current allowables was designed to
provide the operators with additional information concerning the reservoir
dynamics. The Company's net production from operated and nonoperated leases
during this two months period was approximately 10.1 million cubic feet of
natural gas per day. The curtailment did not significantly impact the Company's
scheduled deliveries under the production payment agreement. During 1996 the
Company anticipates the RRC to establish allowables for Keystone which will
allow the Company to sell approximately 10.1 million cubic feet of natural gas
per day from its operated leases. However, there can be no assurance that the
RRC will increase the allowables and, if they do, how long they will maintain
the increased allowables.
During 1995 the Company successfully drilled and completed six development
wells in New Mexico. Average daily production in the aggregate from these wells
is approximately 335 barrels of oil and 1,300 Mcf of gas. The Company also
successfully recompleted numerous wells in New Mexico. In late 1995 the Company
began an infill drilling program in the Teague field area of its New Mexico
properties. The first phase of this program comprises seven wells to be
drilled by the end of the first quarter 1996. As of February 29, 1996, six of
these wells had been successfully drilled and completed. Phase two of the
infill program identifies up to
16
<PAGE>
twenty wells. Drilling commences upon the completion of phase one. If the
Teague infill program continues successfully, the Company could drill up to
forty wells in this field in the next three years. In addition the Company plans
to recomplete numerous existing wells in the next two years if economic
conditions are favorable. The Company expects to participate in similar
development operations in non-operated properties on various other wells.
The Company is also involved in a 3-D seismic program encompassing three
different regions in North Texas, West Texas and the Texas Panhandle. In North
Texas, the Company participated in the drilling of two successful development
wells during 1995 using the 3-D data. The 3-D data also confirmed several
quality development locations which had been tentatively identified by geology
before the 3-D survey was conducted. These locations can be developed at
reasonable costs and may be drilled to capitalize on improved product prices. In
addition to providing confirmation of the known locations, a number of deeper
structures were identified by the 3-D seismic program.
During 1995 the Company drilled two non-commercial wells in both the West
Texas and the Texas Panhandle prospect areas. The 3-D seismic and its
interpretation was very effective in locating the drilling target zones as
expected. However, commercial quantities of hydrocarbons were not encountered
in these wells. There are productive multi-pay zones in both prospect areas. At
December 31, 1995, the Company had capitalized costs of approximately $1.0
million in total related to the 3-D seismic prospects included in unproved
properties. The Company is continuing to develop and interpret the seismic
information for both of these prospects. However, there can be no assurances
that our exploration efforts will result in finding commercial quantities of oil
and gas. Should the Company decide in the future that either of the prospects do
not warrant extension of the lease terms, the Company would recognize an
impairment charge at that time.
The Company has sufficient cash flows and borrowing base in the Revolver to
fund its anticipated drilling, development and acquisition programs for 1996 as
well as its debt service and preferred stock dividend requirements.
Additionally, the Company expects to meet its current operating cash
requirements from cash flows provided by current operations. Management
believes that the Company can continue to generate, or obtain through other
alternatives, resources sufficient to meet cash requirements for future
acquisition opportunities.
The Company operates in an industry that is subject to volatile prices for its
products. Cash flows from operations may be affected to a significant degree by
fluctuations in prices that are brought on by factors beyond the Company's
control.
RESULTS OF OPERATIONS
Year ended December 31, 1995 compared to
----------------------------------------
year ended December 31, 1994
----------------------------
The Company recorded a net loss before dividends of $164,000 in 1995 as
compared to a net loss before dividends of $1,830,000 in 1994. The net loss
before dividends decreased $1,666,000 resulting from increased oil and gas
sales, improved margins on pipeline sales and a decrease in exploration expense.
Pipeline sales decreased $24,276,000 in 1995 as compared to 1994, and were
offset by a corresponding decrease in natural gas purchases and operations of
$25,806,000 for an overall net margin increase of $1,530,000. Natural gas
volumes sold decreased 8,700,000 MMBtu in 1995 as compared to 1994. During 1994
gas was delivered to a major customer under a short-term contract that expired
during 1994 and was not renewed. There were also less spot sales of gas during
1995 as compared to 1994. Both of these factors contributed to
17
<PAGE>
the decline in volumes sold. During 1995 natural gas was purchased at an
average price of $1.52 and sold at an average price of $1.58. During 1994 gas
was bought and sold at an average price of $1.82 and $1.86, respectively. Gross
margin increased to 5.6% in 1995 as compared to 1.7% in 1994 reflecting higher
spreads in 1995.
Revenues from oil and gas sales increased $7,649,000 in 1995 as compared to
1994, as a result of increased gas production from Keystone and increased
production from the New Mexico properties as a result of the development and
exploitation program in New Mexico and a full year of production as compared to
nine months in 1994. Additionally, revenues were impacted by an increase in
average oil prices and a decrease in average gas prices. Gas production in 1995
increased to 7,383,000 Mcf as compared to 2,489,000 Mcf in 1994, resulting in a
$8,192,000 increase in sales. The average price received for gas was $1.32 in
1995 as compared to $1.67 in 1994, resulting in a $2,578,000 decrease in sales.
The average price of gas, excluding certain production payment volumes, was
$1.47 in 1995. Gas production increased primarily as a result of the RRC's
amended order effective February 1, 1995, allowing the Company to produce
approximately 18.1 million cubic feet of natural gas per day (net to its
interest) from its operated and non-operated leases in Keystone. Oil
production increased to 382,000 barrels in 1995 as compared to 281,000 barrels
in 1994, resulting in a $1,630,000 increase in sales. The increase in oil
production is due to the Company's successful drilling and development program
in New Mexico and a full year of production from these properties. The average
price received for oil increased to $17.28 in 1995 as compared to $16.18 in
1994, resulting in a $422,000 increase in sales.
Lease operating expenses ("LOE") related to oil and gas properties increased
$3,649,000 in 1995 as compared to 1994, primarily as a result of the amended RRC
order affecting Keystone and the increased operations in New Mexico. As a
result of the RRC's amended order effective February 1, 1995, the Company ceased
capitalizing the water lifting program costs and is charging these costs to LOE
as incurred. Lifting costs per equivalent barrel decreased to $4.45 in 1995 as
compared to $5.07 in 1994, as a result of the increased oil and gas production.
Exploration expense decreased $743,000 in 1995 as compared to 1994. During 1994
the Company incurred significant costs related to the early stages of a 3-D
seismic program. Depletion, depreciation and amortization increased $2,482,000
in 1995 primarily as a result of the increased oil and gas production and
investment in producing properties.
General and administrative expenses increased $591,000 in 1995 as compared to
1994, reflecting higher personnel costs.
Year ended December 31, 1994 compared to
----------------------------------------
year ended December 31, 1993
----------------------------
The Company recorded a net loss before dividends of $1,830,000 in 1994 as
compared to net income of $176,000 in 1993. Net income decreased $2,006,000
resulting from a $38,548,000 increase in revenues which was offset by a
$41,495,000 increase in costs and expenses and a $941,000 decrease in income tax
expense.
Pipeline sales increased $37,953,000 in 1994 as compared to 1993, but were
offset by an increase in natural gas purchases of $39,933,000 for the same
period for an overall net margin decrease of $1,980,000. The increase in sales
and purchases generally reflects substantially higher activity levels for Onyx
in 1994 compared to 1993. Purchases increased more than sales, reflecting the
fact that most of the increased volumes were from gas marketing activities from
which Onyx normally realizes lower spreads than from gas transportation.
Revenues from oil and gas sales increased $625,000 in 1994 as compared to
1993, primarily as a result of the revenues attributable to the acquired New
Mexico properties (effective April 1, 1994). Oil production in
18
<PAGE>
1994 increased to 281,000 barrels as compared to 159,000 barrels in 1993,
resulting in a $2,114,000 increase in sales. The average price received for oil
was $16.18 in 1994 as compared to $17.36 in 1993, resulting in a $332,000
decrease in sales. The New Mexico properties contributed additional volumes of
142,000 barrels and 856,000 Mcf in 1994. Gas production in 1994 decreased to
2,489,000 Mcf as compared to 3,851,000 in 1993, resulting in a $1,889,000
decrease in sales. The decrease in gas production is primarily the result of
the RRC's interim order in May 1993 suspending the sale of bonus gas production
allowables from the Keystone Ellenburger field until February 1995. The average
price received for gas was $1.67 in 1994 as compared to $1.39 in 1993, resulting
in a $715,000 increase in sales. The average price of gas, excluding certain
production payment volumes and a gas swap contract loss was $1.75 in 1993.
Lease operating expenses ("LOE") related to oil and gas properties decreased
$764,000 in 1994 as compared to 1993. As a result of the RRC's interim order
noted above the Company has capitalized its costs associated with the formation
water recovery and natural gas reinjection program in the Keystone. The Company
deferred $3,190,000 of these costs in 1994. LOE related to the acquired New
Mexico properties was $1,030,000. Lifting costs per equivalent barrel decreased
to $5.07 in 1994 as compared to $5.35 in 1993, primarily as a result of
capitalizing the Keystone water lifting costs for the full year in 1994 whereas
these costs were only capitalized from June through December in 1993. The
$1,484,000 increase in exploration expense is due to 3-D seismic programs that
the Company is undertaking in West Texas and the Panhandle of Texas. Current
developments in the industry employ the use of new sophisticated seismic shoots
and extensive computer modeling evaluation of this data to locate specific
drilling objectives. While the industry's expectations are that ultimately this
will limit exploration risks and make exploration efforts more deliberate, this
new technology is expensive. Accounting literature clearly calls for
identification of these costs as geological and geophysical expenses and,
accordingly, must be expensed as incurred. While this mandate is severe on the
early operations of such exploration programs, these targeted costs must be
expensed as incurred. Depletion, depreciation and amortization increased
$811,000 in 1994 primarily as a result of the New Mexico operations.
General and administrative expenses increased $407,000 in 1994 as compared to
1993 reflecting the increased pipeline operations. Net interest expense
increased $1,481,000 as a result of the increased outstanding bank debt during
most of 1994 as compared to 1993, until the consummation of the Placement in
October 1994.
19
<PAGE>
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ARCH PETROLEUM INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Accountants..................................... 21
Consolidated Balance Sheets at December 31, 1995 and 1994............. 22
Consolidated Statements of Operations for years ended December 31,
1995, 1994 and 1993.............................................. 24
Consolidated Statements of Changes in Shareholders' Equity for
years ended December 31, 1995, 1994 and 1993..................... 25
Consolidated Statements of Cash Flows for years ended December 31,
1995, 1994 and 1993.............................................. 26
Notes to Consolidated Financial Statements............................ 27
Unaudited Quarterly Financial Data.................................... 43
Unaudited Supplemental Oil and Gas Disclosures........................ 44
Index to Exhibits..................................................... 50
</TABLE>
All other schedules and compliance information are omitted since the
required information is not present or is not present in amounts sufficient
to require submission of the schedule, or because the information required
is included in the consolidated financial statements and the notes thereto.
20
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors
of Arch Petroleum Inc.
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, of changes in shareholders'
equity and of cash flows present fairly, in all material respects, the
financial position of Arch Petroleum Inc. and its subsidiaries at December
31, 1995 and 1994, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles. 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 of these statements in accordance
with generally accepted auditing standards which 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, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
Price Waterhouse LLP
Fort Worth, Texas
March 20, 1996
21
<PAGE>
ARCH PETROLEUM INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, December 31,
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $ 2,574,000 $ 1,553,000
Accounts receivable - trade 6,986,000 6,429,000
Accounts receivable - related parties - 1,815,000
Prepaid expenses and other 542,000 635,000
----------- -----------
Total current assets 10,102,000 10,432,000
Property and Equipment, at cost:
Oil and gas properties accounted for
by successful efforts method 66,375,000 61,145,000
Natural gas pipelines 11,448,000 11,184,000
Furniture, fixtures and other equipment 957,000 899,000
----------- -----------
78,780,000 73,228,000
Less accumulated depletion,
depreciation and amortization 12,968,000 8,371,000
----------- -----------
Net property and equipment 65,812,000 64,857,000
Accounts receivable - related parties 939,000 -
Notes receivable - related parties 1,645,000 1,412,000
Other 1,174,000 1,324,000
----------- -----------
$79,672,000 $78,025,000
=========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
22
<PAGE>
ARCH PETROLEUM INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, December 31,
1995 1994
------------- -------------
<S> <C> <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 9,552,000 $ 8,604,000
Accounts payable - related parties 75,000 1,375,000
Current maturities of long-term debt 1,111,000 1,111,000
Preferred stock dividends payable 311,000 311,000
----------- -----------
Total current liabilities 11,049,000 11,401,000
Deferred revenue 16,037,000 20,690,000
Long-term debt, less current maturities 17,821,000 9,632,000
Convertible subordinated notes 5,000,000 5,000,000
Deferred federal income taxes 1,711,000 1,797,000
Minority interest in consolidated subsidiaries 459,000 15,000
Exchangeable convertible preferred stock, $.01 par value,
727,273 shares authorized, issued and outstanding 20,000,000 20,000,000
Shareholders' Equity:
Preferred stock, $.01 par value, 1,000,000 shares
authorized, 727,273 issued as exchangeable convertible
preferred stock - -
Common stock, $.01 par value, 50,000,000 shares authorized,
17,141,404 and 17,186,404 shares issued and outstanding,
respectively 172,000 172,000
Additional paid-in capital 5,944,000 5,809,000
Employee notes for stock purchases (965,000) (905,000)
Treasury stock, 100,000 and none, respectively (206,000) -
Retained earnings 2,650,000 4,414,000
----------- -----------
7,595,000 9,490,000
Commitments and contingencies (Note 11)
$79,672,000 $78,025,000
=========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
23
<PAGE>
ARCH PETROLEUM INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1995 1994 1993
------------ ------------ -----------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales $16,379,000 $ 8,730,000 $ 8,105,000
Pipeline sales 49,249,000 73,525,000 35,572,000
Drilling and production overhead fees 220,000 203,000 249,000
Interest and other 742,000 238,000 222,000
----------- ----------- -----------
66,590,000 82,696,000 44,148,000
COSTS AND EXPENSES:
Oil and gas lease operations 7,176,000 3,527,000 4,291,000
Natural gas purchases and pipeline operations 46,859,000 72,665,000 33,732,000
Exploration 898,000 1,641,000 157,000
Depletion, depreciation and amortization 5,389,000 2,907,000 2,096,000
General and administrative 4,208,000 3,617,000 3,210,000
Interest 1,865,000 1,634,000 153,000
Minority interest in income (loss) of
consolidated subsidiaries 445,000 (524,000) 333,000
----------- ----------- -----------
66,840,000 85,467,000 43,972,000
----------- ----------- -----------
Income (loss) before income taxes and dividends (250,000) (2,771,000) 176,000
Deferred federal income tax benefit (86,000) (941,000) -
----------- ----------- -----------
Net income (loss) (164,000) (1,830,000) 176,000
Dividends on preferred stock 1,600,000 311,000 -
----------- ----------- -----------
Net income (loss) available to
common shareholders $(1,764,000) $(2,141,000) $ 176,000
=========== =========== ===========
Net income (loss) available
per common share $(0.10) $(0.12) $0.01
=========== =========== ===========
Weighted average common and
common equivalent shares outstanding 17,195,000 17,244,000 17,142,000
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
24
<PAGE>
ARCH PETROLEUM INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Years Ended December 31, 1995, 1994 and 1993
<TABLE>
<CAPTION>
Additional
Common Common Paid-in Retained Shareholders'
Shares Stock Capital Earnings Equity
----------- ----------- ----------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Balance -
December 31, 1992 8,305,924 $ 83,000 $5,307,000 $ 6,465,000 $11,855,000
Exercise of stock options 379,800 4,000 746,000 - 750,000
Purchases of stock
for employee notes - - (501,000) - (501,000)
Purchase of treasury shares (94,800) (1,000) (474,000) - (475,000)
Cash distributions to
minority interests
in subsidiary - - - (86,000) (86,000)
Two-for-one stock split 8,590,924 85,000 (85,000) - -
Interest on employee
notes - - (40,000) - (40,000)
Net income - - - 176,000 176,000
---------- ---------- ---------- ----------- -----------
Balance -
December 31, 1993 17,181,848 171,000 4,953,000 6,555,000 11,679,000
Exercise of stock options 4,556 1,000 8,000 - 9,000
Preferred stock dividends - - - (311,000) (311,000)
Interest on employee notes - - (57,000) - (57,000)
Net loss - - - (1,830,000) (1,830,000)
---------- ---------- ---------- ----------- -----------
Balance -
December 31, 1994 17,186,404 172,000 4,904,000 4,414,000 9,490,000
Preferred stock dividends - - - (1,600,000) (1,600,000)
Purchase of treasury shares (100,000) - (206,000) - (206,000)
Issue common stock as
compensation 30,000 - 60,000 - 60,000
Issue common stock for
interest in subsidiary 25,000 - 75,000 - 75,000
Repayment of employee
note receivable - - 14,000 - 14,000
Interest on employee notes - - (74,000) - (74,000)
Net loss - - - (164,000) (164,000)
---------- ---------- ---------- ----------- -----------
Balance -
December 31, 1995 17,141,404 $172,000 $4,773,000 $ 2,650,000 $ 7,595,000
========== ========== ========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
25
<PAGE>
ARCH PETROLEUM INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1995 1994 1993
------------ ------------- -------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (164,000) $ (1,830,000) $ 176,000
Adjustments to reconcile to net cash
provided (used) by operations:
Depletion, depreciation and amortization 5,389,000 2,907,000 2,096,000
Deferred taxes (86,000) (941,000) -
Deferred revenue (3,457,000) (235,000) (1,498,000)
Interest on notes receivable and other (198,000) (133,000) (69,000)
Issue common shares for compensation 35,000 - -
Minority interest in net income (loss)
of consolidated subsidiaries 445,000 (524,000) 333,000
Change in accounts receivable 319,000 (673,000) (5,320,000)
Change in other current assets 93,000 (317,000) (91,000)
Change in accounts payable and other
current liabilities (352,000) 1,491,000 5,479,000
Production payment remedy adjustment (1,196,000) (574,000) (281,000)
----------- ------------ ------------
Net operating cash flows 828,000 (829,000) 825,000
----------- ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (6,088,000) (27,443,000) (11,599,000)
Notes receivable and other assets (101,000) (15,000) (1,358,000)
----------- ------------ ------------
Net investing cash flows (6,189,000) (27,458,000) (12,957,000)
----------- ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings 11,800,000 32,921,000 6,500,000
Proceeds from preferred stock sale - 20,000,000 -
Proceeds from subordinated debt sale - 5,000,000 -
Payments of bank debt (3,612,000) (28,678,000) -
Debt issue costs - (916,000) -
Proceeds from exercise of stock options - 8,000 249,000
Purchase of treasury shares from related party (206,000) - (475,000)
Preferred stock dividends (1,600,000) - -
Cash distributions to minority interests
in subsidiary - (74,000) (86,000)
----------- ------------ ------------
Net financing cash flows 6,382,000 28,261,000 6,188,000
----------- ------------ ------------
Change in cash and cash equivalents 1,021,000 (26,000) (5,944,000)
Cash and cash equivalents at beginning of period 1,553,000 1,579,000 7,523,000
----------- ----------- ------------
Cash and cash equivalents at end of period $ 2,574,000 $ 1,553,000 $ 1,579,000
=========== =========== ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
26
<PAGE>
ARCH PETROLEUM INC.
Notes to Consolidated Financial Statements
1. SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION:
Arch Petroleum Inc., a Delaware corporation, (together with its
subsidiaries,"the Company") primarily engages in oil and natural gas
exploration, development, production, transportation and marketing in the
Southwestern United States. Arch is also active in the acquisition of interests
in oil and gas leases, both producing and non-producing. Threshold Development
Company ("TDC"), an oil and gas exploration company, owns approximately 16.5% of
the Company's common stock as of December 31, 1995. TDC's two majority
shareholders are also officers and directors of the Company. See Note 14 for
acquisition of Canadian subsidiary effective February 20, 1996.
On January 31, 1995, the Company's shareholders, in a special meeting,
approved an amendment to the Company's articles of incorporation whereby the
number of authorized shares of the Company's capital stock was increased from
26,000,000 shares to 51,000,000 shares. Common stock is designated for
50,000,000 shares and preferred stock is designated for the remaining 1,000,000
shares. The Company has reserved 9,090,909 shares of common stock for issuance
upon conversion of the securities in the Placement (see Note 7), if necessary,
and has also reserved 361,690 shares of common stock for issuance upon exercise
of options under its current incentive stock option plan.
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest was $1,466,000, $1,638,000 and $83,000 during 1995,
1994, and 1993, respectively. Cash paid for income taxes was $60,000 during
1993. During 1995 and 1994 the Company paid no income taxes.
BASIS OF CONSOLIDATION:
The consolidated financial statements include the accounts of the Company and
its subsidiaries: Arch Production Company, wholly-owned; Saginaw Pipeline
Company, L.C. ("Saginaw") and Industrial Natural Gas, L.C. ("ING"), 95%
membership interest; and Onyx Pipeline Company, L.C., Onyx Gathering Company,
L.C. and Onyx Gas Marketing Company, L.C. (all together, "Onyx"), 50%
membership interest. All significant intercompany balances and transactions are
eliminated.
REVENUE RECOGNITION:
The Company recognizes revenues as quantities of oil and gas are sold or
volumes of gas are transported, and utilizes the entitlement method of
accounting for oil and gas imbalances. Under this method the oil and gas
segment recognizes revenue for its proportionate share of volumes sold. Any
over-produced amount is recorded as deferred revenue and any under-produced
amount is recorded as current revenue and revenue receivable. The Company had
no significant over or under-produced positions as of December 31, 1995 and
1994.
The natural gas pipeline segment also utilizes the entitlement method,
recognizing a receivable or payable for over or underdelivered volumes, as
applicable. As of December 31, 1995 and 1994, the Company had net imbalance
receivables of $192,000 and $41,000 respectively.
27
<PAGE>
CASH AND CASH EQUIVALENTS:
Cash and cash equivalents consist of cash in banks and cash investments in
immediately available interest bearing accounts.
PROPERTY AND EQUIPMENT:
The Company follows the successful efforts method of accounting for costs
incurred in oil and gas exploration and development operations, all of which are
conducted in the United States. Under this method, the Company capitalizes all
costs to acquire mineral interests in oil and gas properties, to drill and equip
exploratory wells which discover proved reserves, and to drill and equip
development wells. Exploration costs, including geological and geophysical
costs, delay rentals and exploratory dry holes, are charged to expense when
incurred. The Company does not capitalize internal costs such as salaries and
related fringe benefits paid to employees directly engaged in the acquisition,
exploration and development of oil and gas properties or any other directly
identifiable general and administrative costs associated with such activities.
Under the successful efforts method all costs capitalized are aggregated on an
area basis and depleted using the units-of-production method based upon proved
reserves as estimated by independent petroleum engineers. Capitalized costs are
evaluated at least annually to determine whether their net book value has been
impaired; where permanent impairment is indicated, a loss is recognized as
additional depletion expense.
Interest is capitalized in accordance with the guidelines established in SFAS
No. 34, "Capitalization of Interest Cost", during the periods of drilling (or
preparation for drilling) and completing of wells or construction of natural gas
pipelines. Interest of $32,000, $127,000, and $21,000 was capitalized for the
years ended December 31, 1995, 1994 and 1993, respectively.
Costs of unproved properties that are individually significant are evaluated
at least annually for impairment of net book value.
Costs of proved properties that are abandoned or retired are charged against
accumulated reserves for depreciation, depletion and amortization for their
respective area and a loss is recognized to the extent of any excess.
Depreciation of property and equipment, other than oil and gas properties but
including natural gas pipelines, is determined on the straight-line method using
estimated useful lives, which vary from two to thirty years.
Maintenance and repairs are charged to expense; renewals and betterments are
capitalized. Upon sale or retirement of depreciable assets other than proved
oil and gas properties, the cost and related accumulated depreciation are
removed from the accounts, and the resulting gain or loss is included in
operations.
KEYSTONE ELLENBURGER FIELD
In May 1993 the Railroad Commission of Texas ("RRC") amended the field rules
regarding formation water production in the Keystone Ellenburger Field
("Keystone") in Winkler County, Texas. Subsequent to this ruling and until
February 1995 the Company produced approximately 18.9 million barrels of
formation water, thus earning and accumulating a bonus production allowable of
approximately 9.5 million Mcf of natural gas. As a result, the Company incurred
high water lifting costs without realizing the related natural gas revenues
during this period.
28
<PAGE>
Effective February 1, 1995 to October 31, 1995, the RRC amended its interim
order and established a system of field-wide allowables which allowed the
Company to produce and sell approximately 20.2 million cubic feet (16.0 million,
net) of natural gas per day from its operated leases in Keystone. The Company
continues to produce approximately 15,000 barrels of formation water per day.
Concurrent with the implementation of the new field rules, the Company ceased to
capitalize water lifting program costs and commenced amortization of the
deferred water production costs as the bonus production allowable is produced.
At December 31, 1995 and 1994, the Company had deferred $5.1 million and $5.6
million, respectively, of net water production costs. These costs have been
included in proved oil and gas properties. During 1995 the Company amortized
approximately $0.6 million of the deferred water production costs.
The water lifting program costs that have been capitalized arise from the
recovery, transportation and re-injection of formation water in Keystone. The
most significant costs are the following: rental of submersible electric pumps
used to produce the formation water, electricity to power the submersible pumps
and above-ground injection pumps, water disposal facilities and pipelines. The
wells in the water lifting program, as well as the water disposal facilities
used to collect and transport the water, are used exclusively for the lifting
and reinjection of formation water and are specifically identified by the
Company. The water lifting program was encouraged by the RRC to enhance future
recovery of oil and gas.
HEDGING ACTIVITIES:
In 1993 the Company entered into a natural gas swap transaction ("hedge") to
reduce the impact of historically volatile natural gas spot market prices during
the spring and summer months. The contract volume was 10,000 MMBtu per day for
the period April 1, 1993 to August 31, 1993. This agreement involved the cash
settlement of the differential between the contract price paid to the Company
and the average NYMEX natural gas futures contract price at each settlement
date. Due to the higher than expected gas futures prices in 1993, the Company
suffered a loss on this contract of $784,000 which has been included as a
reduction of oil and gas sales in the consolidated statements of operations.
The Company has not historically entered into hedging contracts. There were no
material contracts entered into in 1995 and 1994.
NET INCOME AVAILABLE PER COMMON SHARE:
Net income available per common share is computed by dividing net income
(loss) available to common shareholders (net income (loss) reduced by dividends
on convertible preferred stock; if applicable), by the weighted average number
of common shares outstanding for each period including common stock equivalents,
if dilutive. Common stock equivalents consist of stock options. The
exchangeable convertible preferred stock and convertible subordinated notes are
included under the "if converted" method for fully diluted computational
purposes. Fully diluted net income (loss) per share is not presented since it
is anti-dilutive.
INCOME TAXES:
The Company accounts for income taxes under Statement of Financial Accounting
Standards ("SFAS") No. 109, "Accounting for Income Taxes". SFAS No. 109
requires the use of the liability method for computing deferred income taxes and
allows the recognition of deferred tax assets for deductible temporary
differences and carryforwards. The standard also provides valuation allowances
for the amount of tax assets not expected to be realized.
29
<PAGE>
NEW ACCOUNTING STANDARDS:
In March 1995 the FASB issued FAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("FAS 121"),
which is effective for fiscal years beginning after December 15, 1995.
Effective January 1, 1996, the Company will adopt FAS 121 which requires that
long-lived assets (i.e, property, plant and equipment) held and used by an
entity be reviewed for impairment whenever events or changes in circumstances
indicate that the net book value of the asset may not be recoverable. An
impairment loss will be recognized if the sum of the expected future cash flows
(undiscounted and before interest) from the use of the asset is less than the
net book value of the asset. The amount of the impairment loss will be measured
as the difference between the net book value of the assets and the estimated
fair value of the related assets. FAS 121 requires that assets be grouped at
the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other group of assets. The Company does not
expect any material impact upon adoption of FAS 121 in the first quarter of
1996.
In October 1995, the FASB issued FAS No. 123, "Accounting for Stock-Based
Compensation" ("FAS 123"), which is effective for fiscal years beginning after
December 15, 1995. Effective January 1, 1996, the Company will adopt FAS 123
which establishes financial accounting and reporting standards for stock-based
employee compensation plans. The pronouncement defines a fair value based
method of accounting for an employee stock option or similar equity instrument.
However, it also allows an entity to continue to measure compensation cost for
those plans using the intrinsic value based method of accounting as prescribed
by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" ("APB No. 25"). Entities electing to remain with the accounting as
prescribed by APB 25 must make pro forma disclosures of net income and earnings
per share as if the fair value based method of accounting defined in FAS 123 had
been applied. The Company will continue to account for stock-based employee
compensation plans under the intrinsic method pursuant to APB 25 and will make
the disclosures in its footnotes as required by FAS 123.
PERVASIVENESS OF ESTIMATES:
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
effect the reported amounts of assets and liabilities, and related revenues and
expenses, and disclosure of gain and loss contingencies at the date of the
financial statements. Actual results could differ from those estimates.
ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
SFAS No. 107 "Disclosures about Fair Value of Financial Instruments" requires
the disclosure of the estimated fair value of financial instruments. The
estimated fair value amounts have been determined by the Company using available
market information and appropriate valuation methodologies. Unless otherwise
noted, the estimated fair values of the Company's financial instruments
approximate their carrying value.
Exchangeable convertible preferred stock and convertible subordinated notes:
In determining the estimated fair value of the Preferred Stock and Notes, the
Company used market-based prices of similar securities recently traded. The
estimated fair value of the Preferred Stock was $18.8 million at December 31,
1995, and $20.0 million at December 31, 1994, as compared with the carrying
value of $20.0 million at December 31, 1995 and 1994, respectively. The
estimated fair value of the Notes was $4.7 million at December 31, 1995 and $5.0
million at December 31, 1994, as compared to the carrying value of $5.0 million
at December 31, 1995 and 1994, respectively.
30
<PAGE>
RECLASSIFICATION:
Certain amounts in prior years have been reclassified to conform to
classifications adopted in 1995.
CONCENTRATION OF CREDIT RISK:
The Company is exposed to credit risk with respect to receivables and related
party receivables from entities associated and involved with the oil and gas
industry.
2. PROPERTY AND EQUIPMENT
A summary of property and equipment is as follows:
<TABLE>
<CAPTION>
December 31, December 31,
1995 1994
------------ ------------
<S> <C> <C>
Oil and gas properties:
Unproved properties $ 958,000 $ 849,000
Proved properties 65,417,000 60,296,000
----------- -----------
66,375,000 61,145,000
Less accumulated depreciation and
depletion of proved properties 11,658,000 7,526,000
----------- -----------
Net oil and gas properties 54,717,000 53,619,000
Natural gas pipelines 11,448,000 11,184,000
Less accumulated depreciation 786,000 426,000
----------- -----------
Net natural gas pipelines 10,662,000 10,758,000
Furniture, fixtures and other equipment 957,000 899,000
Less accumulated depreciation 524,000 419,000
----------- -----------
Net furniture, fixtures and other equipment 433,000 480,000
----------- -----------
Net property and equipment $65,812,000 $64,857,000
=========== ===========
</TABLE>
3. PURCHASES OF PROPERTIES
There were no significant purchases of oil and gas properties in 1995. On
March 31, 1994, the Company consummated an agreement with Chevron U.S.A. Inc. to
purchase certain oil and gas properties for a cash consideration of $17,900,000.
The Company financed the purchase price through its revolving credit facility.
The properties, located in Lea County, New Mexico, include interests in
approximately 130 producing oil and gas wells. The Company operates and has a
significant working interest in the majority of these properties. The effective
date of the purchase was April 1, 1994. The Company has accounted for this
acquisition as a purchase and operations from the properties have been included
in the accompanying consolidated statements of operations since April 1, 1994.
The following unaudited pro forma information has been prepared as if the
acquisition had occurred at the beginning of each period presented, and is
provided for comparative purposes only. The pro forma information presented is
not necessarily indicative of the combined financial results and the combined
financial position as they may be in the future or as they might have been for
the periods or as of the dates indicated had the acquisition been consummated at
the beginning of such periods.
31
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------
1994 1993
-------- -------
<S> <C> <C>
(In thousands except per share data)
Total consolidated revenues $83,757 $49,393
Net income (loss) (1,695) 1,128
Net income (loss) available per common share $ (0.12) $ 0.07
</TABLE>
4. ACQUISITION OF NATURAL GAS PIPELINES
In January 1993 the Company acquired a 50% membership interest in Onyx.
Onyx owns four pipelines (approximately 25 miles) which supply natural gas to
four electric power plants owned by Central Power and Light ("CPL") in Nueces,
Hidalgo, Webb and San Patricio Counties, in South Texas. Onyx's contract with
CPL includes a provision for a portion of the base load to the four plants.
Onyx also competes to supply additional quantities of gas which the plants
require. In January 1994 Onyx was awarded a contract by CPL to supply natural
gas to an electric power plant located in Webb County, Texas into 1999. Onyx
also owns other pipelines, including approximately 40 miles of gathering
systems. In conjunction with the acquisition and construction of pipelines, the
Company has loaned to Onyx through December 31, 1995, $6,614,000 (of which
$1,131,000 was loaned in 1995) including accrued interest. Onyx has repaid the
Company $4,412,000 (of which $369,000 was paid in 1995) of those loan advances
including interest as of December 31, 1995. At December 31, 1995, Onyx's loan
balance to the Company was $2,021,000.
In July 1992 the Company, in conjunction with Central States Energy
Corporation ("CSE"), formed Saginaw and ING. Concurrent with this event,
Saginaw acquired a 6" pipeline that extends approximately 100 miles from Wichita
Falls, Texas to Saginaw, Texas. ING was formed to market the sales and
transmission of natural gas through the Saginaw pipeline. The Company initially
received a 47.5% membership interest in Saginaw and ING. Effective January 1,
1993, the Company's interest increased to 75% in both Saginaw and ING. On
September 27, 1995, the Company resolved a membership interest dispute with CSE.
The Company issued $45,000 and 25,000 shares of the Company's unissued common
stock to CSE. As a result of this transaction, the Company now owns a 95%
membership interest in Saginaw and ING.
5. VOLUMETRIC PRODUCTION PAYMENT AND DEFERRED REVENUE
On November 30, 1992, the Company closed the sale of a volumetric
production payment to Enron Reserve Acquisition Corp. ("Enron") for $24,300,000.
The Company contracted to deliver to Enron the equivalent of approximately 17.9
Bcf of natural gas from a certain property in Winkler County, Texas beginning
December 1, 1992. The Company is responsible for all costs of production,
development and marketing of this dedicated gas. The sale was recorded as
deferred revenue in 1992, net of transaction fees. The Company recognizes
deferred revenue from the production payment as deliveries of production are
made. The Company recognized deferred revenues related to the production payment
of $3,457,000, $235,000 and $1,779,000 during 1995, 1994 and 1993 respectively.
The Company remitted $1,196,000, $574,000 and $281,000 to Enron during 1995,
1994 and 1993, respectively in satisfaction of the Remedy Adjustment discussed
below. Gas was delivered to Enron from December 1992 through May 1993 in full
satisfaction of the delivery schedule which is part of the production payment
agreement.
As discussed in Note 1, the interim ruling in May 1993 by the RRC related
to this field reduced the volumes of natural gas that all operators, including
the Company, could remove from the reservoir and, accordingly, reduced the
volumes of natural gas that the Company had available to deliver to Enron in
satisfaction of the production payment agreement. This created a delay in the
scheduled volume deliveries during the period May 1993 to January 1995. The
agreement with Enron provides a mechanism to remedy
32
<PAGE>
both under and over delivery of production payment volumes. The under
deliveries (volume delivery delays) on production payment volumes are converted
into a dollar obligation ("Remedy Adjustment") which is calculated on a monthly
basis by multiplying the deficient volumes by the market price of the gas at the
end of the month. This Remedy Adjustment is satisfied by the dedication of a
portion of the proceeds from oil and casing head gas production and the future
proceeds from gas produced from the reservoir in excess of the future scheduled
production payment volumes. All of the dedicated gas in the production payment
is confined to Company operated properties in Keystone. The original delivery
schedule has not been extended or amended.
At December 31, 1995, the estimated remaining volumes deliverable to Enron
under the production payment agreement were 11.9 Bcf of natural gas (including
3.6 Bcf of natural gas attributable to volume delivery delays resulting from
field rule changes in prior periods). These gas reserves dedicated to Enron are
excluded from the Undaudited Supplemental Oil and Gas Disclosures herein.
Effective February 1, 1995 through October 31, 1995, the RRC amended its interim
order issued in May 1993 and implemented a system of field-wide allowables which
allowed the Company to fully meet its scheduled delivery of volumes under the
production payment agreement and reduce the Remedy Adjustment. However,
effective November 1, 1995, the RRC once again restricted the allowables thereby
impeding the Company's ability to meet its scheduled deliveries. During 1996
the Company anticipates the RRC to establish allowables for Keystone which will
allow the Company to sell approximately 10.1 million cubic feet of natural gas
per day from its operated leases in Keystone. However, there can be no
assurance that the RRC will issue orders which would allow production to resume
at a rate to meet scheduled deliveries and reduce the Remedy Adjustment. The
amount of volumes, if any, which will be necessary to satisfy the Remedy
Adjustment is dependent upon future gas prices. Based upon economics at
December 31, 1995, the Company may deliver approximately 1.4 Bcf of natural gas
volumes in excess of the original contracted delivery volumes in this regard.
As of December 31, 1995, the estimated annual amortization of the remaining
deferred revenue, based on contracted deliveries under the production payment
agreement, is expected to be as follows:
<TABLE>
<S> <C>
1996 $ 6,819,000
1997 6,635,000
1998 2,583,000
-----------
$16,037,000
===========
</TABLE>
6. LONG-TERM DEBT TO BANKS
A summary of long-term debt to banks is as follows:
<TABLE>
<CAPTION>
December 31,
------------------------
1995 1994
----------- -----------
<S> <C> <C>
Bank credit facilities $18,932,000 $10,743,000
Less current maturities 1,111,000 1,111,000
----------- -----------
$17,821,000 $ 9,632,000
=========== ===========
</TABLE>
Maturities of long-term bank debt are as follows (excluding maturity of
Company's Revolver which matures in 1997 but is expected to be extended): 1996 -
$1,111,000 (included in current liabilities), 1997 -$1,111,000, 1998 -
$1,111,000 and 1999 - $278,000.
33
<PAGE>
The Company's revolving credit facility (the "Revolver"), which the Company
entered into on April 6, 1990, (last amended on September 27, 1995 by the third
amendment to the Second Restated Revolving Credit Loan Agreement dated March 31,
1994) is in place for use by the Company at its discretion including drilling,
development and acquisition of oil and gas properties. The Bank of Scotland
participates with Bank One, Texas. N.A., the lead bank, in the Revolver. The
Company has borrowed $15,321,000 against the Revolver at December 31, 1995. The
Revolver borrowing base is the amount that the bank commits to loan to the
Company based on the designated loan value established by the lead bank at its
sole discretion and assigned to substantially all of the Company's oil and gas
properties which serve as collateral for any loan which may be outstanding under
the Revolver. The Revolver facility is $50,000,000 and the borrowing base is
currently $30,000,000. The borrowing base is reviewed semiannually by the lead
bank at its discretion. A commitment fee of one half of one percent of the
unused borrowing base accrues and is payable quarterly. Borrowings under the
Revolver will, at the Company's option, bear interest either at the lead bank's
Base Rate (national prime rate) or a rate based on the London Interbank Offered
Rate (LIBOR). The LIBOR rate is increased by an additional margin of 1.75% to
2.50% based on the ratio of total outstanding revolver debt to the borrowing
base (1.75% if ratio is less than 25%, 2.00% if ratio is more than 25% but less
than 50%, 2.25% if ratio is more than 50% but less than 75% and 2.50% if ratio
is greater than 75%). The average actual interest rate was 8.0% at December 31,
1995. Interest is payable monthly and no principal payments are required until
maturity, which is May 1997.
The Onyx Term Loan Agreement (the "Onyx Note"), which Onyx entered into
with the Bank of Scotland on March 30, 1994, as amended, is a separate facility
and provided Onyx with $5,000,000. The Onyx Note bears interest at national
prime rate plus one-half of one percent (9.0% at December 31, 1995). Interest
on the unpaid principal amount of the note is payable quarterly and commenced on
June 30, 1994. The unpaid principal ($3,611,000 at December 31, 1995), is
payable in eighteen quarterly installments ending on March 31, 1999. Current
maturities of the Onyx Note total $1,111,000 at December 31, 1995. The Onyx
Note is collateralized by certain of Onyx's pipelines, gathering facilities and
related transportation contracts. In addition, the Onyx Note is guaranteed by
the Company.
Both the Revolver and Onyx Note contain normal and standard covenants
generally found in lending agreements. Among other things, these covenants
prohibit the declaration and payment of cash dividends on the Company's common
stock. In addition, the covenants stipulate the maintenance of financial
criteria including: a minimum level of net worth, a certain current ratio, a
certain debt to net worth ratio and a defined net income in excess of scheduled
interest and principal payments. The Company and Onyx are currently in
compliance with the loan agreements. Neither the Company nor Onyx has any other
unused lines of credit. See Note 15 for discussion of new credit facilities
entered into as of February 20, 1996.
7. EXCHANGEABLE CONVERTIBLE PREFERRED STOCK
AND CONVERTIBLE SUBORDINATED NOTES
On October 20, 1994, the Company sold the following securities to four
institutional investors (the "Investors") in a private placement (the
"Placement"): (a) 727,273 shares of its 8% Exchangeable Convertible Preferred
Stock (the "Preferred Stock"), $0.01 par value, having an aggregate liquidation
preference of $20,000,000, (b) $500,000 aggregate principal amount of its 9.75%
Series A Convertible Subordinated Notes due 2004 (the "Series A Notes") and (c)
$4,500,000 aggregate principal amount of its Adjustable Rate Series B Notes due
2004 (the "Series B Notes" and, together with the Series A Notes, the "Notes").
The Series B Notes currently bear interest at an annual rate of 9.75%. Gross
proceeds from the Placement were $20,000,000 for the Preferred Stock and
$5,000,000 for the Notes. The proceeds were used to pay down the Company's
Revolver with Bank One, Texas, N.A. and the Bank of Scotland. The Company
incurred $916,000 of debt issuance costs related to the Placement, which is
being amortized over the period the Preferred Stock
34
<PAGE>
and Notes are outstanding.
The Preferred Stock accrues annual dividends at the rate of $2.20 per share
and the dividends are cumulative. Dividends are payable April 20 and October 20
of each year. During 1995 the Company paid $1,600,000 in dividends on the
Preferred Stock. If dividends remain unpaid for more than one semiannual
period, the holders of the Preferred Stock have the right to elect two
additional directors to the Company's board of directors until such time that
all cumulative dividends have been paid. The Preferred Stock has a liquidation
preference of $27.50 per share and is exchangeable in whole at the option of the
Company, for its 10.563% Series C Convertible Subordinated Notes due 2004 (the
"Series C Notes"). The Series C Notes possess attributes similar to the Series
A Notes, except for the higher rate of interest associated with the Series C
Notes. The Preferred Stock is exchangeable on April 20 and October 20 of each
year.
After October 20, 1998, and upon the achievement of certain stated
objectives for the market price of its common stock, the Company earns the right
to require the conversion of all of the Preferred Stock and the Notes into
common stock of the Company. The market price objectives are as follow: after
August 20, 1998, the closing price of the Company's common stock on the NASDAQ
National Market System, or similarly recognized system, must list for a period
of sixty consecutive trading days at a price equal to or greater than 125% of a
certain target price. The target price ranges from $2.837 at October 20, 1998
to $2.764 at October 20, 2003. Each share of Preferred Stock is convertible, at
any time at the option of the holder thereof, into shares of common stock of the
Company, par value $0.01 per share, at a price of $2.75 per share. Based on the
number of shares (17,141,404) of the Company's common stock outstanding at
December 31, 1995, if all the Preferred Stock and Notes were converted into
common stock of the Company, 26,232,313 shares of common stock would be
outstanding. Upon such conversion the institutional investors, being Travelers,
Travelers Life, Connecticut General and CIGNA Mezzanine would own 16.6%, 4.2%,
4.9% and 8.9% of the Company's common stock, respectively.
The Preferred Stock entitles each holder to one vote per share on an as
converted basis. The vote or consent of at least 66 2/3% (or at least a
majority in the event the Investors and their affiliates own less than 66 2/3%
of the Preferred Stock and Notes on an as converted basis) of the issued and
outstanding shares of Preferred Stock, voting as a separate class, is required
for the Company to (a) issue or authorize the issuance of any class or series of
equity securities senior to the Preferred stock, (b) change the par value of the
Preferred Stock, (c) alter or change the powers, preferences or special rights
of the shares of Preferred Stock or any other provision of the Company's
Certificate of Incorporation so as to affect the shares of Preferred Stock
adversely, (d) merge, consolidate or amalgamate with other person or (e) sell,
lease, transfer or otherwise dispose of all or substantially all of the assets
of the Company.
Interest on the unpaid principal balance of the Notes is payable quarterly
and commenced January 20, 1995. During 1995 the Company paid $488,000 in
interest on the Notes. The Company has the option at any time on or after
October 20, 1998, to prepay the Notes in whole or in part, together with accrued
interest, plus the applicable prepayment premium (expressed as a percentage of
the principal amount to be prepaid). The prepayment premium ranges from 3.150%
at October 20, 1998 to 0.525% at October 20, 2003.
On or after October 20, 1998, the Preferred Stock is redeemable, in whole
or in part at any time at the option of the Company at redemption prices ranging
from $28.366 per share at October 20, 1998 to $27.644 per share at October 20,
2003. On October 20, 2004 all outstanding shares of the Preferred Stock are
mandatorily redeemable by the Company at a price of $27.50 plus accrued and
unpaid dividends.
35
<PAGE>
8. INCOME TAXES
Deferred taxes are provided for temporary differences between the financial
reporting basis and federal income tax basis of the Company's assets,
liabilities and other tax attributes. Deferred tax liabilities and assets are
comprised of the following at December 31:
<TABLE>
<CAPTION>
1995 1994
----------- ----------
<S> <C> <C>
Gross deferred tax liabilities:
Depreciation, depletion and intangible drilling costs $ 8,755,000 $7,672,000
Volumetric production payment 1,249,000 735,000
----------- ----------
10,004,000 8,407,000
Gross deferred tax assets:
Net operating loss carryforwards 6,712,000 5,087,000
Statutory depletion carryforwards 888,000 830,000
Alternative minimum tax credit carryforwards 592,000 592,000
Investment tax credit carryforwards 101,000 101,000
----------- ----------
8,293,000 6,610,000
----------- ----------
Deferred federal income taxes $ 1,711,000 $1,797,000
=========== ==========
</TABLE>
The provision for income taxes differs from the amount determined by
applying the U.S. federal statutory income tax rate to income before income
taxes as a result of the following differences:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1995 1994 1993
--------- ---------- ---------
<S> <C> <C> <C>
Provision based upon federal statutory rate $(86,000) $(941,000) $ 60,000
Statutory depletion (53,000) (26,000) (60,000)
Other 53,000 26,000 -
-------- --------- --------
$(86,000) $(941,000) -
======== ========= ========
</TABLE>
At December 31, 1995, the Company has tax benefit carryforwards of
approximately $17,899,000, $2,369,000, $592,000 and $101,000 relating to net
operating losses, statutory depletion, alternative minimum tax credits and
investment tax credits, respectively, which expire at various dates beginning in
1996, except for statutory depletion which does not have an expiration date.
36
<PAGE>
9. TRANSACTIONS WITH RELATED PARTIES
The Company rents, on an as-needed basis, an aircraft from TDC. Charges
for this service are billed to the Company based on time used. Rental charges
amounted to $39,000, $20,000 and $25,000 for the years ended December 31, 1995,
1994 and 1993, respectively. With the approval of the board of directors, on
April 11, 1995, the Company purchased 100,000 shares of common stock for its
treasury from TDC valued at $206,000 at the then current market price.
The Board of Directors of the Company authorized notes receivable from key
employees and directors in 1991, 1992 and 1993, for purposes of exercising stock
options. The notes bear interest at the Revolver interest rate and all of the
notes are secured by the stock certificates that were issued upon exercise of
the stock options by each employee. The notes mature May 13, 1997. The
balances due to the Company in this regard including interest were $962,000 and
$905,000 at December 31, 1995 and 1994, respectively. These amounts are offset
against equity on the consolidated balance sheet. No new notes were authorized
during 1995 and 1994.
The Board of Directors of the Company also authorized cash advances to
certain officers in 1993 in exchange for notes receivable. These notes also
bear interest at the Revolver rate and are secured by stock certificates of the
Company owned by those individuals. The notes mature May 13, 1997. The notes,
including interest, total $1,645,000 and $1,412,000 at December 31, 1995 and
1994, respectively. Cash advances to officers totalled $115,000 and $15,000
during 1995 and 1994, respectively. The Company recognized interest income on
its outstanding notes receivable from officers, directors and key employees of
$188,000, $150,000 and $91,000 during 1995, 1994 and 1993, respectively.
Onyx has transactions in the ordinary course of business with PURECO and
Sejita which each own 25% interests in Onyx. Onyx also has transactions in the
ordinary course of business with other companies in which the owners of PURECO
and Sejita have ownership interests.
The consolidated financial statements include certain amounts and balances
that arise from transactions with related parties in the normal course of
business. The following table quantifies those transactions.
<TABLE>
<CAPTION>
At December 31, 1995 At December 31, 1994
-------------------- --------------------------------
Accounts Accounts Accounts Accounts
Receivable Payable Receivable Payable
---------- -------- ---------- --------------------
<S> <C> <C> <C> <C>
TDC, net in 1995 $939,000 $ - $1,746,000 $1,301,000
Libra Marketing - - 2,000 -
PURECO - 31,000 9,000 1,000
Puma Resources - - 2,000 5,000
Cedar Energies, Inc. - 44,000 53,000 68,000
Other - - 3,000 -
---------- ------- ---------- ----------
$939,000 $75,000 $1,815,000 $1,375,000
========== ======= ========== ==========
</TABLE>
37
<PAGE>
<TABLE>
<CAPTION>
For Year Ended For Year Ended
December 31, 1995 December 31, 1994
------------------- -----------------------------
Purchases Sales Purchases Sales
From To From To
--------- -------- ---------- -----------------
<S> <C> <C> <C> <C>
Libra Marketing $ 5,000 $ - $ 260,000 $ 37,000
PURECO - - 2,523,000 9,000
Cedar Energies, Inc. 239,000 - 394,000 312,000
Puma Resources - 171,000 - 627,000
Sejita Pipeline 8,000 - - -
-------- -------- ---------- --------
$252,000 $171,000 $3,177,000 $985,000
======== ======== ========== ========
</TABLE>
Amounts receivable from TDC are classified as long-term and do not accrue
interest. The increase in the receivable from TDC in 1995 primarily relates to
operations on producing wells jointly owned by the related parties and operated
by TDC. TDC receives revenue from the purchase of the oil and gas and pays
related LOE and capital costs associated with the wells. Under agreement with
TDC in 1995, the Company has the right of offset with TDC. Accordingly, the
1995 TDC balances are presented net in the financial statements. The 1994 TDC
balances are presented gross in the financial statements. During 1995 the
Company's share of revenue exceeded its share of LOE and capital expenditures on
the jointy owned properties by approximately $365,000, accounting for the
largest portion of the increase in the net amount due from TDC. All other
related party receivables and payables related to the Company's gas marketing
and transmission segment.
10. MAJOR CUSTOMERS
The following major customers represent 10% or more of total operating
revenues by segment for the years ended December 31, 1995, 1994 and 1993:
<TABLE>
<CAPTION>
Oil and Gas 1995 1994 1993
----------- ----- ----- -----
<S> <C> <C> <C>
Chevron U.S.A. Inc. 31% 40% *
Enron Gas Marketing 31% * 34%
</TABLE>
The Company's principal products are oil and natural gas. The principal
market for such products is primarily the Southwestern United States wherein the
Company's oil and gas properties are physically located. 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
production.
<TABLE>
<CAPTION>
Natural Gas Pipelines 1995 1994 1993
--------------------- ----- ----- -----
<S> <C> <C> <C>
Central Power and Light 58% 35% 72%
Entergy Corp. * 17% *
Aquila Southwest Marketing * * 10%
</TABLE>
In its natural gas marketing and transmission activities, the Company buys
and resells natural gas, receiving a gross margin or spread equal to the
difference between the purchase price and the resale price of such natural gas.
In addition, the Company receives a fee for transmission of natural gas over
pipeline systems owned by the Company.
* - Less than 10%.
38
<PAGE>
11. COMMITMENTS AND CONTINGENCIES
COMMITMENTS:
The Company leases office space, office equipment and vehicles under
various lease agreements with primary lease terms ranging from three to five
years. Rental expense on these leases was $202,000, $215,000, and $175,000 in
the years ended December 31, 1995, 1994 and 1993, respectively. Aggregate
future minimum rental payments required pursuant to noncancellable leases
follow: 1996 - $326,000, 1997 - $192,000, 1998 -$150,000 and 1999 - $127,000.
CONTINGENCIES:
From time to time the Company is involved in litigation arising in the
normal course of business. In the opinion of management, the Company's ultimate
liability, if any, from lawsuits currently pending would not materially affect
the Company's financial condition or operations.
12. STOCK OPTIONS
In the annual meeting of shareholders held on May 27, 1993, the
shareholders of the Company approved the Arch Petroleum Inc. 1993 Stock Option
plan ("the 93 Plan"). The 93 Plan is an incentive stock option plan under which
1,660,000 shares are reserved for issuance to employees in the ten year period
commencing June 1, 1993. The exercise price will be set by the 93 Plan
Committee in its best judgement but shall not be less than 100% of the fair
market value per share at grant date. On July 7, 1993, the 93 Plan Committee
granted 334,000 options at $1.8125 with an expiration date of May 31, 2003, to
twenty-three employees. The first third of these options were exercisable six
months from grant date and thereafter, an additional third of the options may be
exercised each anniversary year after the initial first six months date. During
the years ended December 31, 1995, 1994 and 1993, none, 4,556 and none of the
options were exercised under the 93 Plan, respectively. During 1995, 50,000 and
25,000 options were granted at $1.8125 and $2.1875, respectively, under the 93
Plan to two employees. These options have expiration dates of March 20, 2000 and
May 22, 2000, respectively.
Stock option transactions, in the period from December 31, 1993 to December
31, 1995 are summarized below:
<TABLE>
<CAPTION>
Number Option Price
of Shares Per Share
---------- --------------------
<S> <C> <C>
December 31, 1992 760,000 $0.232 - $ 1.313
Granted 334,000 1.813
Exercised (760,000) 0.232 - 1.313
--------
December 31, 1993 334,000 1.813
Cancelled (37,000) 1.813
Exercised (4,000) 1.813
--------
December 31, 1994 293,000 1.813
Granted 75,000 1.813 - 2.1875
Cancelled (6,000) 1.813
--------
December 31, 1995 362,000 1.813 - 2.1875
========
</TABLE>
39
<PAGE>
13. INDUSTRY SEGMENT INFORMATION
The Company operates in two industry segments: oil and gas exploration,
development and production and natural gas marketing, transportation and
distribution. Operating income by segment is defined as revenues less operating
expenses. Income and expense items excluded from operating income include:
interest income, other income, interest expense, minority interest and income
taxes. Identifiable assets are those assets used exclusively in the operations
of each business segment. Operating results for the oil and gas segment of the
Company are significantly affected by the Company's ability to acquire reserves
in the future through the development of existing properties and also its
ability to select and acquire suitable prospects for exploratory drilling or
development. The buying, selling and transporting of natural gas by the
Company's pipeline segment is a highly competitive business. The Company
markets natural gas to customers who can purchase natural gas from various
suppliers. Marketing of both oil and natural gas is affected in part by
domestic production levels, imports, the proximity of pipelines to producing
properties and the regulation by states of allowable rates of production. Cash
flow from operations for both segments may be affected to a significant degree
by fluctuations in prices that are brought on by factors beyond the Company's
control. All of these variable factors are dependent on economic and political
forces which cannot be accurately predicted in advance.
The following table shows industry segment information for the years ended
December 31, 1995, 1994 and 1993.
<TABLE>
<CAPTION>
Natural Gas
(In thousands) Oil and Gas Pipelines Total
------------ ------------ --------
<S> <C> <C> <C>
1995
Identifiable assets $61,547 $18,125 $79,672
Revenues 16,599 49,249 65,848
Exploration costs and expenses 898 - 898
Depletion, depreciation and amortization 4,973 416 5,389
Operating income 648 670 1,318
Capital expenditures 5,824 264 6,088
1994
Identifiable assets $60,908 $17,117 $78,025
Revenues 8,933 73,525 82,458
Exploration costs and expenses 1,641 - 1,641
Depletion, depreciation and amortization 2,604 303 2,907
Operating loss (1,135) (764) (1,899)
Capital expenditures 24,591 2,852 27,443
1993
Identifiable assets $36,139 $14,930 $51,069
Revenues 8,354 35,572 43,926
Exploration costs and expenses 157 - 157
Depletion, depreciation and amortization 1,944 152 2,096
Operating income (loss) (516) 956 440
Capital expenditures 5,902 5,697 11,599
</TABLE>
40
<PAGE>
14. SUBSEQUENT EVENT - ACQUISITION OF TRAX PETROLEUMS LIMITED
Effective January 31, 1996, the Company acquired Trax Petroleums Limited
("Trax"), a Canadian oil and gas exploration and development company
headquartered in Calgary, Alberta, Canada. The Company's January 9, 1996, cash
offer of Cdn. $0.71 for each of Trax's approximately 14,100,000 shares was
accepted by more than 91% of Trax shareholders. Effective February 12, 1996,
the Company completed the statutory compulsory acquisition of the remaining
shares of Trax through the depository, Montreal Trust Company of Canada. The
acquisition of 100% of the common stock of Trax was made through Northern Arch
Resources Ltd.("Northern Arch"), a wholly-owned Canadian subsidiary of the
Company. The current Trax staff of employees and its headquarters will remain
in Calgary. The acquisition purchase price was approximately Cdn. $10,000,000
(approximately US $7,400,000 at January 31, 1996).
UNAUDITED
---------
Trax's November 30, 1995, oil and gas reserves, as estimated by its
independent engineers, totalled 964,000 barrels of oil and 1.38 billion cubic
feet of natural gas (1,193,000 BOE). The estimated future net income
attributable to these reserves (discounted at 15%) is Cdn. $11,100,000
(approximately US $8,100,000 at January 31, 1996). Estimated daily production
currently approximates 600 BOE. In addition to the existing reserve base, Trax
holds a large interest in approximately 40,000 net undeveloped acres. This
acreage includes more than thirty distinct, high quality prospects which are in
various stages of development.
15. SUBSEQUENT EVENT - NEW BANK CREDIT AGREEMENTS
On February 20, 1996, the Company entered into two new bank credit
facilities: the Third Restated Revolving Credit Loan Agreement among the
Company and Bank One, Texas, N.A., the Agent bank, and other banks (the
"Domestic Revolver") and through its new 100% - owed subsidiary, Trax, the
Credit Agreement among Trax and Bank of Montreal, the Canadian Agent bank, and
other financial institutions (the "Canadian Revolver"). The two credit
facilities are separate bank revolvers. The lenders in the Domestic Revolver
(the "U.S. lenders") and the lenders in the Canadian Revolver (the "Canadian
lenders") have entered into an associated Intercreditor Agreement also on
February 20, 1996. In this Intercreditor Agreement the Canadian lenders and the
U.S. lenders have agreed that they shall rank pari passu with one another in
respect of certain payments or recoveries and that certain matters related to
the administration of the Canadian Revolver and the Domestic Revolver shall be
made on the basis of their combined commitments. Each of the revolvers is
described briefly, as follows:
THE DOMESTIC REVOLVER
---------------------
The Domestic Revolver is a modification of the Company's existing Revolver.
The principal change to the former Revolver was the introduction of certain
language, terms and concepts such that the Domestic Revolver and the Canadian
Revolver will be accommodated in pari passu sharing and general administration.
This facility amends, restates and supersedes in its entirety the former
Revolver.
The facility remains at $50,000,000 and the current borrowing base also
remains at $30,000,000. The borrowing base is designated the "U.S. Allocated
Borrowing Base" to distinguish it from the related "Canadian Allocated Borrowing
Base" contained and described in the Canadian Revolver below. As of the first
business day of each calendar quarter (commencing April 1, 1996), the Company
may allocate all or any portion of its Consolidated Borrowing Base (the U.S.,
Domestic Revolver borrowing base plus the Trax properties, Canadian borrowing
base, the "CBB") to the Canadian facility provided that such amount shall not be
less than the outstanding balance of the Canadian Revolver at that time. The
initial allocation of the CBB was $20,000,000
41
<PAGE>
to the Domestic Revolver and $10,000,000 to the Canadian Revolver.
The Company may select an interest rate option with each borrowing advance
between a Floating Base Rate ("FBR") or an Interbank Offered Rate ("IOR"). The
FBR is the rate of interest announced from time to time by the Agent bank and
usually will track the U.S. national prime rate. The IOR is generally the
London interbank market rate. For purposes of the IOR, the effective interest
rate occurring will be increased relative to Borrowing Base Percentage
("BBP"), the aggregate of the unpaid principal balance of the Domestic Revolver
and the Canadian Revolver to the CBB, as follows:
BBP IOR plus
--- --------
Less than 25% 1.75%
More than 25%, but less than 50% 2.0%
More than 50%, but less than 75% 2.25%
More than 75% 2.50%
There is a commitment fee of one half of one percent for the unused borrowing
base which accrues and is payable quarterly commencing April 1, 1996. The
Domestic Revolver matures on May 1, 1997. The security collateral requirements
and the bank covenants and default provisions are essentially unchanged from the
former Revolver.
THE CANADIAN REVOLVER
---------------------
The Canadian Revolver is similar to the Domestic Revolver in all
significant aspects. The loans under the Canadian Revolver are guaranteed by
the Company ("the Guaranty") and is secured by, among other things, a first lien
on 65% of the issued and outstanding shares of Northern Arch's common stock and
a first lien on the oil and gas properties of the Company which serve as
security in the Domestic Revolver. The facility's initial commitment is U.S.
$11,000,000. The Canadian lenders agree to make revolving credit loans to Trax
in one or more advances (U.S. $500,000 minimum, in intervals of U.S. $100,000,
"Revolving Loans") of LIBO Rate loans, Prime Rate loans, Base Rate loans and/or
purchase Bankers' Acceptances.
The various interest rates used in the Canadian Revolver are adjusted for
applicable margins based on the ratio of aggregate outstanding balances relative
to CBB (similar to the Domestic Revolver) as follows:
<TABLE>
<CAPTION>
Type of Loan CBB Ratio Applicable Margin
-------------- ---------------------------------- -----------------
<S> <C> <C>
LIBO Rate & BA Less than 25% 1.75%
Prime Rate 0.75%
LIBO Rate & BA More than 25%, but less than 50% 2.00%
Prime Rate 1.00%
LIBO Rate & BA More than 50%, but less than 75% 2.25%
Prime Rate 1.25%
LIBO Rate & BA More than 75% 2.50%
Prime Rate 1.50%
Base Rate At all times 0.00%
</TABLE>
42
<PAGE>
The proceeds of each advance may be used to fund additional borrowing
base properties, to drill and recomplete oil and gas wells and for general
corporate purposes. Repayments shall be made relative to the currency used in
each borrowing. The Canadian Revolver matures on May 1, 1997. There is a
commitment fee of one half of one percent for the unused borrowing base which
accrues and is payable on the first day of each quarter.
The Trax borrowing base, which was undetermined at date of closing, is
the loan value determined by the Canadian Agent bank in its sole discretion
based on its calculations of value of borrowing base properties utilizing
current and customary procedures and standards for petroleum industry customers.
The Canadian Agent bank is currently studying and evaluating Trax's properties.
The cross border allocation of borrowing base procedures described above in the
Domestic Revolver are contained in the Canadian Revolver, also, and are
referenced to each other in both facilities.
UNAUDITED QUARTERLY FINANCIAL DATA
(In thousands, except per share amounts)
Unaudited quarterly financial data is as follows:
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Year Ended December 31, 1995
- ------------------------------------
Operating revenues $14,047 $16,813 $18,741 $16,989
Exploration costs and expenses 304 19 507 68
Gross profit 898 2,275 1,342 1,753
Net income (loss) (279) 435 (327) 7
Net income (loss) per share (1) $ (0.04) $ - $ (0.04) $ (0.02)
Year Ended December 31, 1994
- ------------------------------------
Operating revenues $17,451 $25,510 $26,764 $12,971
Exploration costs and expenses (2) 132 12 14 1,483
Gross profit (loss) (2) 504 860 1,115 (523)
Net loss (2) (250) (170) (169) (1,241)
Net loss per share (1)(2) $ (0.01) $(0.01) $ (0.01) $ (0.09)
</TABLE>
Gross profit represents income before income taxes excluding general and
administrative expense, interest expense and minority interest in income (loss)
of consolidated subsidiaries.
(1) - After dividends on preferred stock.
(2) - In the fourth quarter of 1994, the Company expensed $1,452,000 of costs
related to a 3-D seismic program performed throughout 1994 on undeveloped
acreage in Stonewall County and the Panhandle of Texas. These costs were
deferred during the first three quarters of 1994 as the Company was soliciting
participation by third parties in these exploration projects and expected to
proportionately recover its investment in these properties, plus the 3-D seismic
costs incurred, from these potential participants. As of December 31, 1994, an
agreement was not completed. Accordingly, the seismic costs were expensed.
43
<PAGE>
ARCH PETROLEUM INC.
Unaudited Supplemental Oil and Gas Disclosures
Estimates of Reserves and Future
Production Performance Are Subjective
and May Change Materially as Actual
Production Information Becomes Available
The following table sets forth the proved oil and gas reserves of the Company
for the years ended December 31, 1995, 1994 and 1993, and the changes therein.
All of the Company's oil and gas activities are located within the United
States. None of the Company's reserves are subject to long-term supply
agreements with a governmental agency.
<TABLE>
<CAPTION>
Oil Gas
Oil and Gas Reserve Quantities (Bbl) (Mcf)
- -------------------------------------------- ---------- -----------
<S> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
Quantity, December 31, 1992 2,485,200 46,544,900
Extensions and discoveries 29,300 54,000
Production (159,500) (2,277,500)
Revisions of previous estimates (769,300) (767,800)
--------- ----------
Quantity, December 31, 1993 1,585,700 43,553,600
Purchases of minerals in place 2,675,800 19,840,700
Extensions and discoveries 6,900 5,000
Production (282,300) (1,974,800)
Revision of previous estimates (399,700) 121,700
--------- ----------
Quantity, December 31, 1994 3,586,400 61,546,200
Extensions and discoveries 1,126,000 4,138,000
Production (382,100) (4,291,900)
Revision of previous estimates (300,100) (106,000)
--------- ----------
Quantity, December 31, 1995 4,030,200 61,286,300
========= ==========
PROVED DEVELOPED RESERVES:
As of December 31, 1993 1,368,600 41,785,500
As of December 31, 1994 3,390,600 60,666,200
As of December 31, 1995 2,993,600 55,628,500
</TABLE>
The Company's proved reserves exclude 11.9 Bcf, 15.5 Bcf and 16.1 Bcf of
gas reserves at December 31, 1995, 1994 and 1993, respectively, which were sold
under a volumetric production payment to a major gas company in December 1992
for $1.30 per Mcf. The Company is required to deliver this gas production over
the next 2.7 years under the terms of the production payment agreement. The
revenue associated with these reserves, which is deferred, is recognized as
production is delivered. The ultimate quantity of gas to be delivered pursuant
to the term of the producion payment agreement may vary from the original
contracted amount as discussed in Note 5.
44
<PAGE>
Costs Incurred in Oil and Gas Activities
- ----------------------------------------
Costs incurred in oil and gas property acquisition, exploration and
development activities are set forth below:
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Acquisition of properties:
Proved $ 274,000 $ 18,142,000 $ 279,000
Unproved 108,000 590,000 260,000
Exploration 898,000 1,641,000 157,000
Development 4,937,000 5,799,000 5,176,000
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
- ----------------------------------------------------------------------------
Relating to Proved Oil and Gas Reserves
- ---------------------------------------
<TABLE>
<CAPTION>
December 31,
----------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows $182,785,400 $163,551,600 $125,914,300
Future production and development costs 66,311,500 54,407,600 46,702,000
Future income tax expenses 22,434,000 22,440,700 18,816,200
------------ ------------ ------------
Future net cash flows undiscounted 94,039,900 86,703,300 60,396,100
10% annual discount for estimated timing
of cash flows 42,127,800 38,182,900 28,606,800
------------ ------------ ------------
Standardized measure of discounted
future net cash flows $ 51,912,100 $ 48,520,400 $ 31,789,300
============ ============ ============
</TABLE>
Future net cash flows were computed using year end prices and costs. For
the reserve report as of December 31, 1995, the average prices were $18.82 for
oil and $1.76 for gas. As of December 31, 1994, the average prices were $16.02
for oil and $1.74 for gas. As of December 31, 1993, the average prices were
$13.38 for oil and $2.13 for gas.
The standardized measure of discounted future net cash flows at December
31, 1995, 1994 and 1993, as presented in the table above, excludes future net
cash flows associated with the remaining original volumes of gas to be delivered
pursuant to the volumetric production payment agreement as described in Note 5.
The discounted future net cash flows, before future income tax expenses, related
to the volumetric production payment approximates $11,672,700, $12,566,300 and
$12,860,100 which amounts are net of discounted future production costs of
$1,912,700, $2,557,800 and $3,156,500 at December 31, 1995, 1994 and 1993,
respectively.
45
<PAGE>
The Company operates in an industry that is subject to volatile prices for
its products. The standardized measure of discounted future net cash flows may
be affected to a significant degree by fluctuations in prices that are brought
on by factors beyond the Company's control. The following are the principal
sources of change in the standardized measure of discounted future net cash
flows:
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Standardized measure of discounted future net
cash flows at beginning of period $48,520,400 $31,789,000 $42,133,000
Changes resulting from:
Purchases of minerals in place - 28,124,500 -
Net changes in prices and costs, exclusive of
properties sold 2,736,100 (5,041,400) (9,553,400)
Net change in income taxes 174,100 (1,594,000) 3,071,100
Sales of oil and gas produced, net of
production costs (6,001,800) (4,364,600) (1,852,000)
Revisions of previous quantity estimates (1,464,900) (1,619,800) (3,857,500)
Extensions and discoveries, less related costs 9,241,100 73,600 256,200
Changes in estimated future development costs (5,899,500) (237,300) 2,495,900
Development costs incurred previously estimated 740,700 40,200 287,900
Accretion of discount 4,852,000 3,178,900 4,213,400
Timing and other (986,100) (1,828,700) (5,405,600)
----------- ----------- -----------
Standardized measure of discounted future net
cash flows at end of period $51,912,100 $48,520,400 $31,789,000
=========== =========== ===========
</TABLE>
46
<PAGE>
Results of Operations from Oil and Gas Producing Activities
- -----------------------------------------------------------
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Revenues $16,599,000 $ 8,933,000 $ 8,354,000
Production costs (7,176,000) (3,527,000) (4,291,000)
Exploration expenses (898,000) (1,641,000) (157,000)
Depletion, depreciation and amortization (4,973,000) (2,604,000) (1,944,000)
----------- ----------- -----------
3,552,000 1,161,000 1,962,000
Income tax expense (1,208,000) (395,000) -
----------- ----------- -----------
Results of operations $ 2,344,000 $ 766,000 $ 1,962,000
=========== =========== ===========
</TABLE>
47
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Reference is made to the material under the captions, "Election of
Directors" in the Registrant's definitive Proxy Statement to be filed on or
about March 22, 1996, pursuant to Regulation 14A in connection with its Annual
Meeting of Shareholders to be held on April 25, 1996, which is incorporated
herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to the material under the caption, "Compensation of
Executive Officers and Directors" in the Registrant's definitive Proxy Statement
to be filed on or about March 22, 1996, pursuant to Regulation 14A in connection
with its Annual Meeting of Shareholders to be held on April 25, 1996, which is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is made to the material under the caption, "Outstanding Voting
Securities of the Company and Certain Shareholders" in the Registrant's
definitive Proxy Statement to be filed on or about March 22, 1996, pursuant to
Regulation 14A in connection with its Annual Meeting of Shareholders to be held
on April 25, 1996, which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is made to the material under the caption "Certain Relationships
and Related Transactions" in the Registrant's definitive Proxy Statement to be
filed on or about March 22, 1996 , pursuant to Regulation 14A in connection with
its Annual Meeting of Shareholders to be held on April 25, 1996, which is
incorporated herein by reference.
48
<PAGE>
PART IV
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
A. Consolidated Financial Statements and Schedules
1. Consolidated Financial Statements
---------------------------------
Consolidated financial statements and supplemental data are shown by
index thereto, page 20.
2. Consolidated Financial Statement Schedules
------------------------------------------
There are no consolidated financial statement schedules which are
required to be filed (SEC Release No. 33-7118) or the related amounts
are not present in amounts sufficient to require submission of the
schedule.
3. Exhibits
--------
The exhibits listed on the accompanying index to exhibits (page 50)
are filed by reference as part of this Form 10-K.
B. Reports on Form 8-K
No reports on Form 8-K were filed by the Company during the quarter ended
December 31, 1995.
49
<PAGE>
ARCH PETROLEUM INC.
INDEX TO EXHIBITS
Exhibit 4.1 Term Loan Agreement, dated March 30, 1994, between Onyx Pipeline
Company, L.C., Onyx Gathering Company, L.C., Onyx Gas Marketing
Company, L.C. and Bank of Scotland, incorporated herein by
reference to Exhibit 4.4 to Amendment No. 1 to Forms S-3 dated
July 14, 1994.
Exhibit 4.2 Certificate of Designation of Preferences and Rights of
Exchangeable Convertible Preferred Stock of the Company, dated
October 20, 1994, filed with the Secretary of State of Delaware,
incorporated herein by reference to Exhibit 4.1 to Form 8-K
dated October 20, 1994.
Exhibit 10.1 Purchase and Sale Agreement, dated November 24, 1992, between
the Company and Enron Reserve Acquisition Corp., incorporated
herein by reference to Exhibit 10.1 to Form 10-K/A-1 for the
year ended December 31, 1993.
Exhibit 10.2(a) Financing Statement, dated January 15, 1993, between the
Company and Onyx Gathering Company, L.C., incorporated herein by
reference to Exhibit 10.2(a) to Form 10-K/A-1 for the year ended
December 31, 1993.
Exhibit 10.2(b) Pledge Agreement, dated January 15, 1993, between the Company
and Onyx Gathering Company, L.C., incorporated herein by
reference to Exhibit 10.2(b) to Form 10-K/A-1 for the year ended
December 31, 1993.
Exhibit 10.2(c) Promissory Note, dated January 15, 1993, between the Company and
Onyx Gathering Company, L.C., incorporated herein by reference
to Exhibit 10.2(c) to Form 10-K/A-1 for the year ended December
31, 1993.
Exhibit 10.2(d) Loan Agreement, dated January 15, 1993, between the Company and
Onyx Gathering Company, L.C., incorporated herein by reference
to Exhibit 10.2(d) to Form 10-K/A-1 for the year ended December
31, 1993.
Exhibit 10.3 Agreement of Purchase and Sale, dated January 15, 1993, between
Onyx Gathering Company, L.C. and Onyx Pipeline Company,
incorporated herein by reference to Exhibit 10.3 to Form 10-K/A-
1 for the year ended December 31, 1993.
Exhibit 10.5(a) Second Restated Revolving Credit Loan Agreement, dated March 31,
1994, between the Company and Bank One, Texas, N.A.,
incorporated herein by reference to Exhibit 10.5 (a) to Form 10-
K/A-1 for the year ended December 31, 1993.
Exhibit 10.5(b) Revolving Promissory Note, dated March 31, 1994, between the
Company and Bank One, Texas, N.A., incorporated herein by
reference to Exhibit 10.5 (b) to Form 10-K/A-1 for the year
ended December 31, 1993.
Exhibit 10.6 Asset Sale Agreement, dated January 20, 1994, between the
Company and Chevron U.S.A. Inc., incorporated herein by
reference to Item 7(C) to Form 8-K dated March 31, 1994.
50
<PAGE>
Exhibit 10.7(a) Securities Purchase Agreement, dated as of October 15, 1994,
between the Company and Travelers Indemnity, incorporated herein
by reference to Exhibit 10.1 to Form 8-K dated October 20, 1994.
Exhibit 10.7(b) Securities Purchase Agreement, dated as of October 15, 1994,
between the Company and Travelers Life, incorporated herein by
reference to Exhibit 10.2 to Form 8-K dated October 20, 1994.
Exhibit 10.7(c) Securities Purchase Agreement, dated as of October 15, 1994,
between the Company and Connecticut General, incorporated herein
by reference to Exhibit 10.3 to Form 8-K dated October 20, 1994.
Exhibit 10.7(d) Securities Purchase Agreement, dated as of October 15, 1994,
between the Company and Cigna Mezzanine, incorporated herein by
reference to Exhibit 10.4 to Form 8-K dated October 20, 1994.
Exhibit 10.8(a) Cash Offer Circular by Arch Petroleum Inc. to purchase all of
the Common Shares of Trax Petroleums Limited, incorporated
herein by reference to Exhibit 10.8(a) to From 8-K/A-1 dated
January 31, 1996.
Exhibit 10.8(b) Notice of Guaranteed Delivery, incorporated herein by reference
to Exhibit 10.8(b) to Form 8-K/A-1 dated January 31, 1996.
Exhibit 10.8(c) Letter of Acceptance and Transmittal, incorporated herein by
reference to Exhibit 10.8(c) to Form 8-K/A-1 dated January 31,
1996.
Exhibit 10.9 Third Restated Revolving Credit Loan Agreement dated February
20, 1996, among Arch Petroleum Inc. and Bank One, Texas, N.A.,
as Agent, and other Banks, incorporated herein by reference to
Exhibit 10.9 to Form 8-K/A-1 dated January 31, 1996.
Exhibit 10.10 Credit Agreement, dated as of February 20, 1996, among Trax
Petroleums Limited and Bank of Montreal, as Agent, and other
Financial Institutions, incorporated herein by reference to
Exhibit 10.10 to Form 8-K/A-1 dated January 31, 1996.
Exhibit 24 Independent Accountant's Consent.
51
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this Annual Report to
be signed on its behalf by the undersigned, thereunto duly authorized.
ARCH PETROLEUM INC.
-------------------
Registrant
By: /s/Larry Kalas
---------------
Larry Kalas, March 20, 1996
Director, President and Chief Executive Officer
(Principal Executive Officer)
By: /s/Fred Cantu
--------------
Fred Cantu, March 20, 1996
Treasurer and Chief Financial Officer
(Principal Accounting and Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
By: /s/Johnny H. Vinson
--------------------
Johnny H. Vinson, March 20, 1996
Director
By: /s/Randall W. Scroggins
------------------------
Randall W. Scroggins, March 20, 1996
Director
By: /s/Dick Harris
---------------
Dick Harris, March 20, 1996
Director
By: /s/C. Randall Hill
-------------------
C. Randall Hill, March 20, 1996
Director
By: /s/John F. Gilsenan
--------------------
John F. Gilsenan, March 20, 1996
Director
52
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 2,574,000
<SECURITIES> 0
<RECEIVABLES> 6,986,000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 10,102,000
<PP&E> 78,780,000
<DEPRECIATION> 12,968,000
<TOTAL-ASSETS> 79,672,000
<CURRENT-LIABILITIES> 11,049,000
<BONDS> 0
20,000,000
0
<COMMON> 172,000
<OTHER-SE> 7,423,000
<TOTAL-LIABILITY-AND-EQUITY> 79,672,000
<SALES> 65,628,000
<TOTAL-REVENUES> 66,590,000
<CGS> 54,035,000
<TOTAL-COSTS> 54,035,000
<OTHER-EXPENSES> 6,287,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,865,000
<INCOME-PRETAX> (250,000)
<INCOME-TAX> (86,000)
<INCOME-CONTINUING> (164,000)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (164,000)
<EPS-PRIMARY> (0.10)
<EPS-DILUTED> 0
</TABLE>
