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, 1997
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 March 31, 1998, the aggregate market value of the voting
stock held by nonaffiliates of the registrant was $33,132,000 based
on the closing price reported by NASDAQ National Market.
As of March 31, 1998, there were 17,321,804 shares of the regis-
trants 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
PART I Page
Item 1. Business......................................... 3
Item 2. Properties....................................... 5
Item 3. Legal Proceedings................................ 9
Item 4. Submission of Matters to a Vote of Security
Holders.......................................... 9
PART II
Item 5. Market for Company's Common Stock and Related
Shareholder Matters.............................. 10
Item 6. Selected Financial Data.......................... 11
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............. 12
Item 8. Consolidated Financial Statements and
Supplemental Data................................ 16
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.............. 41
PART III
Item 10. Directors and Executive Officers of the Company.. 42
Item 11. Executive Compensation........................... 42
Item 12. Security Ownership of Certain Beneficial Owners
and Management................................... 42
Item 13. Certain Relationships and Related Transactions... 42
PART IV
Item 14. Exhibits, Consolidated Financial Statement
Schedules, and Reports on Form 8-K............... 43
Signatures................................................. 46
<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 Western Canada. The Company is
also active in the acquisition of interests in oil and gas leases,
both producing and non-producing. Subsidiaries of the Company
include: Arch Petroleum Ltd. ("APL"), and Northern Arch Resources
Ltd. ("NARL") both wholly-owned Canadian companies; 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. The Company sold it's entire interest in
Onyx effective June 30, 1997. The Company reduced its domestic
long-term debt by $7.8 million and recognized a pre-tax book gain
of approximately $5.0 million. Threshold Development Company
("TDC"), an oil and gas exploration company, owns approximately 13.9%
of the Company's common stock as of December 31, 1997.
The Company's shareholders, in a special meeting on January 31,
1995, 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 sold on October 20, 1994,
in a private placement (the "Placement"), if necessary. The Company
has also reserved approximately 339,300 shares of common stock for
issuance upon exercise of options under its current incentive stock
option plan.
The Company sold the following securities to four institutional
investors in 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 bank credit facility.
See Note 13 to the consolidated financial statements for
information regarding revenues, operating profit and identifiable
assets of the Company's segments.
Recent Developments:
Oil and Gas Operations
<PAGE>
The Company acquired Trax Petroleums Limited ("Trax"), a
Canadian oil and gas exploration and development company
headquartered in Calgary, Alberta, Canada effective January 31, 1996.
The acquisition was made through Northern Arch Resources Ltd., a
wholly- owned Canadian subsidiary of the Company. The acquisition
purchase price was approximately $7.6 million. The Company changed
the name of Trax to Arch Petroleum Ltd. effective March 31, 1997.
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 on March 31, 1994. The Company borrowed the purchase
price through its bank credit facility. 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
has drilled and recompleted approximately 75 wells in this area since
the purchase.
The Company sold a volumetric production payment (the "VPP") to
Enron Reserve Acquisition Corp. ("Enron") for $24.3 million in
November 1992. 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 of Texas ("RRC") amended the
field rules for Keystone reducing the allowable production.
Subsequent to this ruling, the Company has not been able to produce
sufficient gas to satisfy the monthly delivery obligation to Enron.
This created a gas delivery deficiency under the VPP. During April
1997, the RRC further reduced the allowable production from Keystone.
See Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations and Note 5 to the
consolidated financial statements, for additional discussion of this
matter.
Natural Gas Pipeline Operations
The Company acquired a 50% membership interest in Onyx in
January 1993. The Company entered into an agreement to sell it's
entire 50% membership interest in Onyx on July 10, 1997. The
transaction was closed on July 31, 1997, and was effective June 30,
1997. 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.
The Company, in conjunction with Central States Energy
Corporation ("CSE"), formed Saginaw and ING in July 1992. 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 purchased CSE's 20%
membership interest in Saginaw and ING on September 27, 1995. The
Company now owns a 95% membership interest in Saginaw and ING.
<PAGE>
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 has sold 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, 1997, the Company sold to three customers that
represented 62% of total revenues from oil and gas sales: Genesis
Crude Oil, L.P. (29%), Richardson Products Company (21%) and Enron
Gas Marketing (12%).
Onyx sold natural gas to approximately sixty customers in 1997.
CPL was the largest customer of the Company, representing 50% of
gross revenues from pipeline sales.
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.
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.
<PAGE>
Marketing competition is affected in part by the production
levels of 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 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.
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.
<PAGE>
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 the
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:
The Company had 42 full-time employees as of February 28, 1998.
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. APL leases approximately 4,951 square feet of office space in
Calgary, Alberta, Canada. Saginaw leases 500 square feet of office
space in Wichita Falls, Texas. The Company maintains 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 domestic 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. The APL
(Canadian) oil and gas reserves were estimated by Ryder Scott Company
and Sproule Associates Limited, both independent petroleum engineers
in Canada in 1997 and 1996, respectively. All such estimations were
made in accordance with regulations promulgated by the Securities and
Exchange Commission ("SEC"). The reserve reports are 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, 1996. All of the Company's production, acreage and
drilling activity is located in the United States and Western Canada.
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.
<PAGE>
The following table sets forth a summary of the Company's oil
and gas reserve quantities and present value of future net cash flows
associated therewith.
<TABLE>
<S> United States Canada Total
Present value of <C> <C> <C>
discounted future
net cash flows before
income taxes:
December 31, 1997 $60,289,500 $ 8,422,300 $ 68,711,800
December 31, 1996 101,701,100 11,775,700 113,476,800
December 31, 1995 64,296,200 - 64,296,200
Proved developed and
undeveloped reserves:
Oil (Bbls)
December 31, 1997 5,060,500 812,900 5,873,400
December 31, 1996 3,861,000 856,900 4,717,900
December 31, 1995 4,030,200 - 4,030,200
Gas (Mcf)
December 31, 1997 68,430,700 6,575,000 75,005,700
December 31, 1996 59,120,900 1,136,000 60,256,900
December 31, 1995 61,286,300 - 61,286,300
Proved developed
reserves:
Oil (Bbls)
December 31, 1997 4,475,600 693,800 5,169,400
December 31, 1996 3,128,400 809,900 3,938,300
December 31, 1995 2,993,600 - 2,993,600
Gas (Mcf)
December 31, 1997 65,324,800 6,489,000 71,813,800
December 31, 1996 54,981,200 504,000 55,485,200
December 31, 1995 55,628,500 - 55,628,500
</TABLE>
The United States figures above exclude 1.9 Bcf, 8.7 Bcf and
11.9 Bcf of proved gas reserves and $436,400, $2,960,600 and
$11,672,700 of discounted future net cash flows (after operating
expenses and severance taxes) at December 31, 1997, 1996 and 1995,
respectively, which were sold to Enron in the VPP. 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.
<PAGE>
Wells Drilled:
The following table shows the wells drilled by or participated
in by the Company since 1995. 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>
Gross Wells Net Wells
Produc- Produc-
<S> tive Dry Total tive Dry Total
Year Ended December 31, 1997: <C> <C> <C> <C> <C> <C>
United States - Exploratory 2 1 3 1.5 1.0 2.5
United States - Development 127 1 128 32.2 .5 32.7
Canada - Exploratory - 2 2 - 1.8 1.8
Canada - Development 7 - 7 1.6 - 1.6
Year Ended December 31, 1996:
United States - Exploratory 1 2 3 .3 1.3 1.6
United States - Development 150 - 150 24.4 - 24.4
Canada - Exploratory 1 1 2 .3 .7 1.0
Canada - Development 3 - 3 1.1 - 1.1
Year Ended December 31, 1995:
United States - Exploratory - 4 4 - 2.2 2.2
United States - Development 110 - 110 13.4 - 13.4
Canada - Exploratory - - - - - -
Canada - Development - - - - - -
</TABLE>
<TABLE>
Leases and Wells Owned:
At December 31, 1997, the Company owned interests in the
following acreage.
<S> United States Canada Total
Developed acres: <C> <C> <C>
Gross 67,017 35,223 102,240
Net 16,950 3,810 20,760
Undeveloped acres:
Gross 74,435 106,705 181,140
Net 23,452 51,777 75,229
</TABLE>
See also the discussion of Proposed Drilling Activity and
Acquisitions. As of December 31, 1997, the Company's interests in
wells owned were as follows:
<TABLE>
<S> Total United States Canada
Gross Net Gross Net Gross Net
Type Wells Wells Wells Wells Wells Wells
<C> <C> <C> <C> <C> <C>
Oil 1,209 363.7 1,076 344.8 133 18.9
Gas 134 62.8 131 62.2 3 .6
1,343 426.5 1,207 407.0 136 19.5
</TABLE>
<PAGE>
<TABLE>
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.
<S> 1997 1996 1995
Oil volumes (Bbl): <C> <C> <C>
United States 528,400 459,300 382,100
Canada 128,600 120,300 -
-
Total 657,000 579,600 382,100
Average Oil Prices ($/Bbl):
United States $19.47 $21.59 $17.28
Canada 19.17 18.81 -
Composite $19.41 $21.02 $17.28
Gas volumes (Mcf):
United States (1) 5,076,500 6,596,400 7,382,900
Canada 182,500 152,200 -
Total 5,259,000 6,748,600 7,382,900
Average Gas Prices ($/Mcf):
United States (1) $2.10 $1.73 $1.32
Canada 1.08 1.06 -
Composite $2.07 $1.72 $1.32
Average Lifting Cost per
Equivalent Barrel (2):
United States $5.76 $4.87 $4.45
Canada 6.47 4.80 -
Composite $5.83 $4.86 $4.45
(1) Includes production payment natural gas volumes (Mcf) of
1,713,900, 2,751,100 and 3,090,400 at an average price of $1.20,
$0.83 and $1.11 for the years ended December 31, 1997, 1996 and 1995,
respectively.
(2) Equivalent barrels are calculated using a conversion factor of
six Mcf of gas to one barrel of oil. Costs include severance and ad
valorem taxes.
</TABLE>
<PAGE>
Proposed Drilling Activity and Acquisitions:
The Company was very successful drilling new developmental wells
and recompleting existing wells in 1997. This coming year the
Company has budgeted approximately $16.6 million to its oil and gas
capital expenditures program. Domestically, the Company has budgeted
$4.7 million for eight new wells and fifteen recompletions in
southeast New Mexico. This area continues to lead the Company's
growth both in production and additional reserves. In total current
plans call for the drilling of approximately thirty new wells and the
recompletion of approximately twenty-one existing wells in the United
States for approximately $7.1 million.
The Company was also successful in the development drilling
efforts by APL in 1997. Current year plans include eighteen new
wells for approximately $9.5 million. APL also increased its acreage
positions and expanded its 3-D seismic coverage in 1997.
Saginaw also anticipates expansion and growth opportunities in
the coming year. In addition to the existing business of gas
transportation and marketing, it is evaluating its participation in
several power generation projects. Most of these projects represent
opportunities for profitable activities in our existing lines of
business while adding another dimension to our future potential.
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, 1997.
<PAGE>
PART II
ITEM 5. MARKET FOR COMPANY'S COMMON STOCK AND RELATED SHARE-
HOLDER 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, 1996, through December 31, 1997. 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 March 31, 1998, the
closing price for the Company's common stock was $ 2.500.
<TABLE>
<S> 1997 1996
Quarter High Low High Low
<C> <C> <C> <C>
First $3.375 $2.250 $2.938 $1.938
Second 3.281 2.438 2.688 2.000
Third 3.875 2.938 2.750 1.688
Fourth 3.688 2.219 3.031 2.250
</TABLE>
There were approximately 1,390 shareholders of record as of
December 31, 1997.
No cash dividends have been paid on common stock to date. See
Note 7 to the 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: Larry Shannon
777 Taylor Street, Suite II
Fort Worth, Texas 76102
<PAGE>
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>
Year Ended December 1997 1996 1995 1994 1993
31, (In Thousands,
except per share data)
OPERATING DATA:
<S> <C> <C> <C> <C> <C>
Operating revenues (1) $80,862 $ 99,926 $66,590 $82,696 $44,148
Oil and gas sales 23,622 23,748 16,379 8,730 8,105
Pipeline sales 51,392 74,309 49,249 73,525 35,572
Exploration expense 1,134 593 898 1,641 157
Net income (loss) 2,828 3,022 (164) (1,830) 176
Preferred stock
dividends 1,600 1,600 1,600 311 -
Net income (loss)
available per common
share - basic 0.07 0.08 (0.10) (0.12) 0.01
Weighted average
common shares
outstanding 17,294 17,159 17,141 17,183 17,054
BALANCE SHEET DATA:
Total assets $93,171 $101,039 $79,672 $78,025 $51,069
Deferred revenue 2,123 12,528 16,037 20,690 21,499
Non-recourse
production
payment obligation 13,317 - - - -
Long-term debt,
less current
maturities 30,000 30,134 17,821 9,632 6,500
Convertible
subordinated notes 5,000 5,000 5,000 5,000 -
Convertible preferred
stock 20,000 20,000 20,000 20,000 -
Shareholders' equity 10,138 9,065 7,595 9,490 11,679
</TABLE>
<PAGE>
No cash dividends have been paid on common stock since inception.
See Note 7 to the consolidated financial statements for discussion
of restriction on common stock dividends.
(1) - Operating revenues for 1997 include a gain of $5,046,000 from
the sale of pipeline subsidiary. See Note 3 to the consolidated
financial statements. Operating revenues for 1996 include a gain of
$1,037,000 from the sale of certain oil and gas properties. See Note
2 to the consolidated financial statements.
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, reserve estimates, interest
rate fluctuations, the regulatory and political environments,
estimated volumes of gas to be delivered pursuant to the VPP and
other risks indicated in filings with the Securities and Exchange
Commission.
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.
The following review of operations for the years ended
December 31, 1997, 1996 and 1995 should be read in conjunction
with the consolidated financial statements presented elsewhere.
CAPITAL RESOURCES AND LIQUIDITY
Financial Position. At December 31, 1997 the Company's total
assets were $93.2 million compared to $101.0 million at December 31,
1996. Oil and gas properties increased $11.5 million as a result
of development drilling as well as the recompletion of existing
wells, chiefly in New Mexico and North Texas and $3.1 million as a
result of additional drilling in Canada. The Company's working
capital ratio was 1.07 and 1.05 at December 31, 1997 and 1996,
respectively.
The Company participates in two 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 the Credit Agreement among APL and Bank of Montreal,
the Canadian Agent bank (the " Canadian Revolver" ). Together, the
agent bank and the Canadian Agent bank (the "Lenders"). The two
credit facilities are separate bank revolvers.
<PAGE>
The Company's Revolvers are in place for use by the Company at
its discretion for certain activities including drilling, development
and acquisition of oil and gas properties. The Company has borrowed
$16.5 million and $13.5 million against the Domestic and Canadian
Revolvers at December 31, 1997, respectively. The Revolvers'
borrowing base is the amount that the Lenders commit to loan to the
Company based on the designated loan value established by the Lenders
at their sole discretion and assigned to certain of the Company's oil
and gas properties which serve as collateral for any loan which may
be outstanding under the Revolvers. The Revolver facility is $50.0
million. The borrowing base was redetermined and amended effective
August 1, 1997, and the borrowing base is currently allocated $23.0
million Domestic and $14.0 million Canadian. The Revolvers'
borrowing base is reviewed semiannually by the Lenders at their
discretion. A commitment fee of one half of one percent of the unused
borrowing base accrues and is payable quarterly. The Revolvers mature
on May 1, 1999. Borrowings under the Revolvers will, at the Company's
option, bear interest either at the Lenders' Base Rate or a rate
based on the London Interbank Offered Rate (LIBOR). The effective
interest rate was 8.15% at December 31, 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 is
collateralized by certain of Onyx's pipelines, gathering
facilities and related transportation contracts.
The Company closed the sale of its interest in Onyx on July 31,
1997, and realized approximately $8.1 million in cash. The Company
used $7.8 million of the proceeds to pay down the Domestic Revolver
as of July 31, 1997. As a result of the sale of Onyx, the Company
is no longer a party to the Onyx Note described above and does not
guarantee that facility as of July 31, 1997. All collateral
requirements and security instruments formerly associated with the
Onyx Note were released and cleared as regards to the Company as
of July 31, 1997.
The Revolvers 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 is currently in compliance with the
covenants in loan agreements. The Company has no other unused lines
of credit.
<PAGE>
The Company sold 727,273 shares of its 8% Exchangeable
Convertible Preferred Stock having a liquidation preference of
$20,000,000 and Convertible Subordinated Notes of $5,000,000 in the
Placement in 1994. The Preferred Stock accrues annual dividends at
the rate of $2.20 per share. Dividends are payable semiannually ($1.6
million in 1997). The Notes bear interest at 9.75%. Interest on the
unpaid principal balance of the Notes is payable quarterly ($0.5
million in 1997).
The VPP sold to Enron generated $24.3 million cash in 1992. The
Company contracted to deliver to Enron the equivalent of
approximately 17.9 Bcf of natural gas volumes from Keystone beginning
December 1, 1992. The Company is responsible for all costs
of production, development and marketing of these dedicated gas
volumes. The VPP gas reserves dedicated to Enron are excluded
from the Unaudited Supplemental Oil and Gas Disclosures, herein.
Certain rulings by the RRC in May 1993, which affected all the
Keystone operators, curtailed the production of natural gas from this
field. These production curtailments created delays in the Company's
scheduled volume deliveries to Enron. The VPP provides a mechanism
to remedy both under and over delivery of scheduled volumes. The
under deliveries of production payment volumes are converted into a
volumetric obligation which is also denominated in dollars (the
"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 that month. In addition, the VPP provides for interest at
10% per year on the outstanding Remedy Adjustment. This Remedy
Adjustment is satisfied by proceeds received from the sale of
dedicated hydrocarbons from Keystone in excess of the future
scheduled volume deliveries. The Company remitted $0.3 million,
$1.2 million and $1.2 million to Enron during 1997, 1996 and 1995,
respectively, in satisfaction of a portion of the Remedy Adjustment.
During 1997, the RRC imposed further production limitations of
natural gas from Keystone. It became evident at that time that the
Company would incur significant future deficiencies and interest
under the VPP. Accordingly, in 1997 the Company has reclassified
amounts due under the Remedy Adjustment from Deferred revenue to Non-
recourse production payment obligation in the accompanying
financial statements. At December 31, 1997 the Company has treated
the past deficiencies as a repurchase of the volumetric production
payment and therefore approximately 6.0 Bcf associated with these
deficiencies have been restored to the Company's unaudited
Supplemental Oil and Gas disclosures, herein.
The Company anticipates that the RRC will continue to impose
production limitations for Keystone in 1998 that will create
additional deficiencies in scheduled volume deliveries. The scheduled
volumes deliverable during 1998 under the VPP at December 31, 1997
are approximately 1.9 Bcf. In 1997, interest expense of $1.0
million relating to the Remedy Adjustment is reflected in the
accompanying consolidated financial statements.
<PAGE>
Sources and Uses of Capital Resources. In 1997 the Company's chief
sources of funds were: $8.1 million from the sale of Onyx, $6.3
million from operations and $1.4 million (net) from its bank credit
facilities. These funds were primarily used to: fund $11.1 million
of domestic drilling, primarily in New Mexico and North Texas, $3.1
million for the drilling of new wells in Canada, including
construction of supporting facilities and pipelines and $1.6 million
for preferred stock dividends.
In 1996 the Company's chief sources of funds were $11.1 million
(net) from its bank credit facilities and $5.9 million from
operations. These funds were used to: purchase its Canadian
subsidiary, APL, for $7.6 million, to drill new wells and develop
existing leases domestically and in APL for a total of $7.9 million,
to pay $1.6 million of preferred stock dividends and to fund $1.8
million in working capital changes.
In 1995 the Company's principal sources of funds were $8.2
million (net) from its bank credit facilities and $1.2 million from
operations. 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 illion for treasury shares.
The Company was very successful drilling new developmental wells
and recompleting existing wells in 1997. This coming year the
Company has budgeted approximately $16.6 million to its oil and gas
capital expenditures program. Domestically, the Company has budgeted
$4.7 million for eight new wells and fifteen recompletions in
southeast New Mexico. This area continues to lead the Company's
growth both in production and additional reserves. In total current
plans call for the drilling of approximately thirty new wells and the
recompletion of approximately twenty-one existing wells in the United
States for approximately $7.1 million.
The Company was also successful in the developmental drilling
efforts by APL in 1997. Current year plans include eighteen new
wells for approximately $9.5 million. APL also increased its acreage
positions and expanded its 3-D seismic coverage in 1997.
Saginaw also anticipates expansion and growth opportunities in
the coming year. In addition to the existing business of gas
transportation and marketing, it is evaluating its participation in
several power generation projects. Most of these projects represent
opportunities for profitable activities in our existing lines of
business while adding another dimension to our future potential.
<PAGE>
The Company believes that it has sufficient cash flows and
available borrowing base in the Revolvers to fund its anticipated
drilling, development and acquisition programs for 1998 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.
RESULTS OF OPERATIONS
Year ended December 31, 1997 compared to
year ended December 31, 1996
The Company recorded net income before dividends of $2,828,000
in 1997 as ompared to net income of $3,022,000 before dividends in
1996. Total revenues and expenses decreased as a result of
diminished natural gas pipeline segment operations after the sale
of Onyx effective June 30, 1997. Net income was decreased primarily
as a result of lower oil and gas prices during 1997.
Revenues from oil and gas sales decreased $126,000 in 1997 as
compared to 1996. Oil production increased to 657,000 barrels in 1997
as compared to 580,000 barrels in 1996, resulting in a $1,622,000
sales increase. The Company has begun realizing production from the
new wells drilled during 1997. The average price received for oil was
$19.41 in 1997 as compared to $21.02 in 1996, resulting in a
$1,052,000 sales decrease. Gas production in 1997 decreased to
5,259,000 Mcf as compared to 6,749,000 Mcf in 1996, resulting in a
$2,553,000 sales decrease. The decrease in gas production is
attributable primarily to the reduced allowable production from
Keystone. The average price received for gas increased to $2.07 in
1997 as compared to $1.72 in 1996, resulting in a $1,857,000 sales
increase. The average price received for gas excluding certain
production payment volumes was $2.72 in 1997 as compared to $2.32 in
1996.
Lease operating expenses (" LOE") related to oil and gas
properties increased $680,000 as a result of the new wells drilled
during 1997 and general increases in the cost of services. Lifting
costs per equivalent barrel increased in 1997 to $5.83 from $4.86 in
1996, primarily as a result of decreased gas production from
Keystone. Exploration expense increased $541,000 as a result of three
uneconomic exploratory wells drilled by the Company during the
current year.
<PAGE>
Depletion, depreciation and amortization increased only $207,000
in 1997 primarily as a result of the decreased gas production from
Keystone. General and administrative expenses remained relatively
constant primarily as a result of the Onyx sale effective June 30,
1997. Interest expense increased $1,183,000 in 1997 primarily due to
interest of $1,049,000 related to the VPP Remedy Adjustment.
The Company recognizes a deferred tax asset in APL. No valuation
allowance was provided against this deferred tax asset since it is
management's belief that it is more likely than not that this
deferred tax asset will be utilized. See Note 8 to the
consolidated financial statements.
Year ended December 31, 1996 compared to
year ended December 31, 1995
The Company recorded net income before dividends of $3,022,000
in 1996 as compared to a net loss of $164,000 before dividends in
1995. Net income increased due to higher oil and gas sales and
improved margins on pipeline sales. In addition, the Company
recognized a pre- tax gain of $1,037,000 on the sale of certain oil
and gas properties located in West Texas, in April 1996. There was
also a corresponding increase in almost all categories of costs and
expenses.
Pipeline sales increased $25,060,000 in 1996 as compared to
1995, but were offset by an increase in natural gas purchases of
$24,450,000. The increase in sales and purchases is due primarily to
the increase in the cost of gas which averaged $2.19 in 1996 as
compared to $1.52 in 1995. During 1996 natural gas was sold at
an average price of $2.38 as compared to $1.58 in 1995. Gross margin
increased by $610,000 in 1996 to $3,000,000.
Revenues from oil and gas sales increased $7,369,000 in 1996 as
compared to 1995. Oil and gas revenues attributable to APL were
$2,425,000 during 1996. Increased production from the New Mexico
properties as a result of the development and exploitation program
and higher average oil and gas prices also contributed to the
increase in sales. Oil production increased to 580,000 barrels
in 1996 as compared to 382,000 barrels in 1995, resulting in a
$3,414,000 sales increase. The increase in oil production is due
to the Company's successful drilling and development program in New
Mexico as well as the APL production (120,000 barrels). The average
price received for oil was $21.02 in 1996 as compared to $17.28 in
1995, resulting in a $2,163,000 sales increase. Gas production
in 1996 decreased to 6,749,000 Mcf as compared to 7,383,000 Mcf
in 1995, resulting in a $840,000 sales decrease. The decrease
in gas production is attributable primarily to the reduced
allowable production from Keystone. The average price received for
gas increased to $1.72 in 1996 as compared to $1.32 in 1995,
resulting in a $2,632,000 sales increase. The average price
received for gas excluding certain production payment volumes was
$2.32 in 1996.
<PAGE>
LOE related to oil and gas properties increased $905,000
primarily as a result of the addition of the APL operations. LOE was
$699,000 for APL during 1996. The new wells successfully completed in
New Mexico also added to LOE. Lifting costs per equivalent barrel
(including APL operations) increased in 1996 to $4.86 from $4.45 in
1995. Exploration expense decreased $305,000 in 1996 as compared to
1995. Depletion, depreciation and amortization (" DD&A") increased
$1,515,000 in 1996 as a result of increased production, primarily
from the New Mexico operations, as well as the added APL operations.
DD&A was $1,139,000 for APL in 1996.
General and administrative expenses increased $852,000 in 1996
as compared to 1995, as a result of increased personnel costs
and the addition of APL. General and administrative expense was
$589,000 for APL in 1996. Interest expense increased $992,000
as a result of the increased outstanding bank debt during 1996.
For the years ended December 31, 1997, 1996 and 1995, the
Company recorded income tax expense of $1,818,000, $1,438,000 and
($86,000) respectively, resulting in effective tax rates of 37.5%,
32.3% and (34.0%). The Company's provision for income taxes was
less than the statutory federal rate of 35% due to statutory
depletion deductionsin 1996 and 1995. The Company also recognized
a deferred tax asset related to APL. No valuation allowance
was provided against this deferred tax asset since it was
management's belief that it was more likely than not that this
deferred tax asset would be utilized. See Note 8 to the consolidated
financial statements.
<PAGE>
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
ARCH PETROLEUM INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Page
Reports of Independent Accountants.................................... 17
Consolidated Balance Sheets at December 31, 1997 and 1996............. 19
Consolidated Statements of Operations for years ended December 31,
1997, 1996 and 1995 ............................................. 21
Consolidated Statements of Changes in Shareholders' Equity for
years ended December 31, 1997, 1996 and 1995 .................... 22
Consolidated Statements of Cash Flows for years ended December 31,
1997, 1996 and 1995 ............................................. 23
Notes to Consolidated Financial Statements............................ 24
Unaudited Supplemental Oil and Gas Disclosures........................ 37
Index to Exhibits..................................................... 44
<PAGE>
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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Arch Petroleum Inc.
We have audited the accompanying consolidated balance sheet of
Arch Petroleum Inc. (a Delaware corporation) and subsidiaries as of
December 31, 1997, and the related consolidated statements of
operations, changes in shareholders' equity and cash flows for the
year then ended. 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 audit.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
Arch Petroleum Inc. and subsidiaries as of December 31, 1997, and
the results of their operations and their cash flows for the year
then ended December 31, 1997, in conformity with generally accepted
accounting principles.
<PAGE>
Fort Worth, Texas ARTHUR ANDERSEN LLP
April 15, 1998
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, 1996, and the results of
their operations and their cash flows for each of the two years in
the period ended December 31, 1996, 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 25, 1997
<PAGE>
<TABLE>
ARCH PETROLEUM INC.
CONSOLIDATED BALANCE SHEETS
December 31, December 31,
1997 1996
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $2,160,000 $3,192,000
Accounts receivable - trade 3,585,000 15,948,000
Accounts receivable - related parties 729,000 423,000
Prepaid expenses and other 544,000 968,000
Total current assets 7,018,000 20,531,000
Property and Equipment, at cost:
Oil and gas properties accounted for
by successful efforts method 99,178,000 81,620,000
Natural gas pipelines 5,657,000 12,361,000
Furniture, fixtures and other equipment 1,033,000 1,038,000
105,868,000 95,019,000
Less accumulated depletion,
depreciation and amortization 25,320,000 19,617,000
Net property and equipment 80,548,000 75,402,000
Accounts receivable - related parties 1,406,000 1,403,000
Notes receivable - related parties 1,874,000 1,759,000
Deferred income taxes 1,511,000 705,000
Other 814,000 1,239,000
$93,171,000 $101,039,000
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
ARCH PETROLEUM INC.
CONSOLIDATED BALANCE SHEETS
December 31, December 31,
1997 1996
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
Current Liabilities:
Accounts payable $6,239,000 $16,193,000
Accounts payable - related parties - 1,971,000
Current maturities of long-term debt - 1,119,000
Preferred stock dividends payable 311,000 311,000
Total current liabilities 6,550,000 19,594,000
Long-term debt, less current maturities 30,000,000 30,134,000
Non-recourse production payment obligation 13,317,000 -
Deferred revenue 2,123,000 12,528,000
Convertible subordinated notes 5,000,000 5,000,000
Deferred federal income taxes 5,770,000 3,450,000
Other liabilities 273,000 186,000
Minority interest in consolidated
subsidiaries - 1,082,000
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,
17,321,804 and 17,271,804
shares issued and outstanding,
respectively 173,000 172,000
Additional paid-in capital 6,137,000 6,012,000
Employee notes for stock purchases (1,047,000) (1,022,000)
Treasury stock, 100,000 shares (206,000) (206,000)
Cumulative translation adjustment (219,000) 37,000
Retained earnings 5,300,000 4,072,000
Total shareholders' equity 10,138,000 9,065,000
Commitments and contingencies
(Note ____)
</TABLE> $93,171,000 $101,039,000
<PAGE>
The accompanying notes are an integral part of these
consolidated financial statements.
<TABLE>
ARCH PETROLEUM INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<S> Year Ended December 31,
1997 1996 1995
Revenues: <C> <C> <C>
Oil and gas sales $23,622,000 $23,748,000 $16,379,000
Pipeline sales 51,392,000 74,309,000 49,249,000
Interest and other 802,000 832,000 962,000
Gain on sale of properties 5,046,000 1,037,000 -
80,862,000 99,926,000 66,590,000
Costs and Expenses:
Oil and gas lease operations 8,761,000 8,081,000 7,176,000
Natural gas purchases and
pipeline operations 49,175,000 71,309,000 46,859,000
Exploration 1,134,000 593,000 898,000
Depletion, depreciation and
amortization 7,111,000 6,904,000 5,389,000
General and administrative 5,197,000 5,060,000 4,208,000
Interest 4,040,000 2,857,000 1,865,000
Foreign currency transaction loss 492,000 40,000 -
Minority interest in income of
consolidated subsidiaries 448,000 622,000 445,000
76,358,000 95,466,000 66,840,000
Income (loss) before income taxes
and dividends 4,504,000 4,460,000 (250,000)
Income tax expense (benefit) 1,676,000 1,438,000 (86,000)
Net income (loss) 2,828,000 3,022,000 (164,000)
Dividends on preferred stock 1,600,000 1,600,000 1,600,000
Net income (loss) available to
common shareholders $ 1,228,000 $1,422,000 $(1,764,000)
Net income (loss) available
per common share - $ 0.07 $ 0.08 $ (0.10)
basic and diluted
Weighted average common
shares outstanding - basic 17,294,000 17,159,000 17,141,000
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
<PAGE>
<TABLE>
ARCH PETROLEUM INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Years Ended December 31, 1997, 1996 and 1995
Employee
Additional Notes Cumulative
Common Treasury Common Paid-in Treasury for Stock Translation Retained Shareholders'
<S> Shares Shares Stock Capital Stock Purchases Adjustment Earning Equity
Balance -
December <C> <C> <C> <C> <C> <C> <C> <C>
31, 1994 17,186,404 $ 172,000 $5,809,000 $ (905,000) $ 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 stock
as compensation 30,000 - - 60,000 - - - 60,000
Issue stock for
interest in
subsidiary 25,000 - - 75,000 - - - 75,000
Repayment of
employee note - - - - - 14,000 - 14,000
Interest on
employee notes - - - - - (74,000) - (74,000)
Net loss - - - - - - (164,000) (164,000)
Balance -
December
31, 1995 17,241,404 100,000 172,000 5,944,000 (206,000) (965,000) 2,650,000 7,595,000
Preferred
stock dividends - - - - - - (1,600,000) (1,600,000)
Exercise of
stock options 400 - - 1,000 - - - 1,000
Issue stock
as compensation 30,000 - - 67,000 - - - 67,000
Interest on
employee notes - - - - - (57,000) - (57,000)
Translation
adjustment - - - - - - $ 37,000 - 37,000
Net income - - - - - - - 3,022,000 3,022,000
Balance -
December
31, 1996 17,271,804 100,000 172,000 6,012,000 (206,000) (1,022,000) 37,000 4,072,000 9,065,000
Preferred
stock dividends - - - - - - - (1,600,000) (1,600,000)
Exercise of
stock options 20,000 - - 39,000 - - - - 39,000
Issue stock
as compensation 30,000 - 1,000 86,000 - - - - 87,000
Interest on
employee notes - - - - - (64,000) - - (64,000)
Repayment of
employee note - - - - - 39,000 - - 39,000
Translation
adjustment - - - - - - (255,000) - (256,000)
Net income - - - - - - - 2,828,000 3,074,000
Balance -
December
31, 1997 17,321,804 100,000 $ 173,000 $6,137,000 $ (206,000)$ (1,047,000) (219,000) $ 5,300,000 $ 10,138,000
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
ARCH PETROLEUM INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
<S> 1997 1996 1995
Cash flows from operating <C> <C> <C>
activities:
Net income (loss) $2,828,000 $3,022,000 $ (164,000)
Adjustments to reconcile to
net cash provided (used) by
operations:
Depletion, depreciation and
amortization 7,111,000 6,904,000 5,389,000
Deferred taxes 1,676,000 1,438,000 (86,000)
Deferred revenue (2,050,000) (2,309,000) (3,457,000)
Dry hole costs and other 915,000 387,000 340,000
Interest on notes receivable
and other (179,000) (213,000) (198,000)
Interest on production
payment obligation 1,049,000 - -
Issue shares for compensation 87,000 64,000 35,000
Minority interest in net income
of consolidated subsidiaries 448,000 622,000 445,000
Foreign currency transaction
loss 492,000 40,000 -
Gain on sale of assets (5,046,000) (1,037,000) -
7,331,000 8,918,000 2,304,000
Change in accounts receivable 3,299,000 (8,266,000) 319,000
Change in other current assets 308,000 (406,000) 93,000
Change in accounts receivable
- related parties (401,000) (612,000) -
Change in accounts payable and
other current liabilities (3,882,000) 7,466,000 (352,000)
Production payment remedy
adjustment (312,000) (1,200,000) (1,196,000)
Net operating cash flows 6,343,000 5,900,000 1,168,000
Cash flows from investing
activities:
Capital expenditures (14,551,000) (9,334,000) (6,428,000)
Proceeds from sale of assets,
net of cash disposed 7,260,000 1,601,000 -
Notes receivable and other
assets (80,000) (181,000) (101,000)
Acquisition of subsidiary - (7,645,000) -
Net investing cash flows (7,371,000) (15,559,000) (6,529,000)
Cash flows from financing
activities:
Proceeds from bank borrowings 13,000,000 26,504,000 11,800,000
Payments of bank debt (11,564,000) (15,371,000) (3,612,000)
Proceeds from note payable -
minority interestholder 82,000 744,000 -
Purchase of treasury shares
from related party - - (206,000)
Preferred stock dividends (1,600,000) (1,600,000) (1,600,000)
Other 78,000 - -
Net financing cash flows (4,000) 10,277,000 6,382,000
Change in cash and cash
equivalents (1,032,000) 618,000 1,021,000
Cash and cash equivalents at
beginning of period 3,192,000 2,574,000 1,553,000
Cash and cash equivalents at
end of period $ 2,160,000 $ 3,192,000 $2,574,000
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
<PAGE>
ARCH PETROLEUM INC.
Notes to Consolidated Financial Statements
1. SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization and Basis of Presentation:
Arch Petroleum Inc., a Delaware corporation, (together with its
subsidiaries,"the Company") engages primarily in oil and natural gas
exploration, development, production, transportation and marketing in
the Southwestern United States and 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 13.9%
of the Company's common stock as of December 31, 1997. Two of TDC's
shareholders are also officers and directors of the Company.
The Company acquired Trax Petroleums Ltd. on January 31, 1996,
which was subsequently renamed Arch Petroleum Limited ("APL")
effective March 31, 1997. See Note 4. The Company's consolidated
financial statements include the results of APL from the January 31,
1996 acquisition date.
In a special meeting on January 31, 1995, the Company's
shareholders 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 a private placement
(the "Placement"), if necessary. See Note 7. The Company has
also reserved 339,300 shares of common stock for issuance upon
exercise of options under its current incentive stock option plan.
The consolidated financial statements include the accounts of
the Company and its subsidiaries: APL and Northern Arch Resources
Ltd. ("NARL"), both wholly-owned Canadian companies; 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. The Onyx interests were sold in July 1997.
See Note 3. All significant intercompany balances and transactions
are eliminated.
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.
<PAGE>
Supplemental Cash Flow Information:
Cash paid for interest was $2,811,000, $2,731,000 and $1,466,000
during 1997, 1996, and 1995, respectively. The Company issued stock
as compensation to a third party totaling $87,000, $67,000 and
$60,000 during 1997, 1996 and 1995, respectively. The Company paid
$241,000 in income taxes in 1997. During 1996 and 1995 the Company
paid no income taxes.
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 gas imbalances. Under this method the 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, 1997 and 1996.
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, 1997 and
1996, the Company had net imbalance receivables of nil and $298,000,
respectively.
Foreign Currency Translation:
The assets and liabilities of APL are translated into U.S.
dollars at current exchange rates, and revenues and expenses are
translated at average exchange rates for the year. Resulting
translation adjustments are reflected as a separate component of
shareholders' equity.
The Canadian dollar is the functional currency of APL.
Transaction gains and losses that arise from exchange rate
fluctuations on transactions denominated in a currency other than the
functional currency are included in the results of operations as
incurred.
Cash and Cash Equivalents:
Cash and cash equivalents consist of cash in banks and cash
investments in immediately available interest bearing accounts.
<PAGE>
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 and
Western Canada. 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.
Interest is capitalized in accordance with the guidelines
established in Statement of Financial Accounting Standards ("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. The Company has had no
significant capitalized interest since 1994.
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.
Impairment of Assets:
Effective January 1, 1996, the Company adopted SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of", which had no impact upon the
Company's financial condition or results of operations. As required,
the Company periodically evaluates the realizability of its long-
lived assets based upon expectations of undiscounted cash flows
before interest. An impairment loss is recognized if the sum of the
expected undiscounted cash flows from the use of the asset is less
than the book value of the asset. Generally, the amount of impairment
loss is measured as the difference between the net book value and the
estimated fair value of the assets. There was no impairment provision
required in 1997 or 1996.
<PAGE>
Keystone Ellenburger Field
A water lifting program was encouraged by the Railroad
Commission of Texas ("RRC") in 1993 to enhance future recovery of oil
and gas from the Keystone Ellenburger Field ("Keystone") in Winkler
County, Texas. The capitalized water lifting program costs arose
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 re-injection of formation water and are specifically
identified by the Company.
The RRC amended the field rules in May 1993, regarding formation
water production in Keystone. 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 water lift
period.
The Company ceased capitalizing water lifting program costs on
January 31, 1995 concurrent with the issue of modified field rules
and commenced amortization of the deferred water production costs as
the bonus production allowable is produced. The Company's net
capitalized water production costs were $4.4 million and $4.6 million
at December 31, 1997 and 1996, respectively. These costs are
included in proved oil and gas properties. The Company amortized
approximately $188,000 and $563,000 of the deferred water production
costs in 1997 and 1996, respectively.
Net Income Available Per Common Share:
Effective December 31, 1997, the Company adopted SFAS No. 128,
"Earnings per Share" which prescribes standards for computing and
presenting earnings per share and supersedes APB Opinion No. 15,
"Earnings per Share." In accordance with SFAS No. 128, net income
(loss) available per common share has been calculated based on the
weighted average shares outstanding during the year and net income
(loss) available per common share-assuming dilution, has been
calculated assuming the exercise or conversion of all dilutive
securities as of the beginning of the period, or as of the date of
issuance, if later. Net income (loss) available to common
shareholders is net income (loss) reduced by dividends on preferred
stock.
As of December 31, 1997 and 1996, there were 119,000 and 88,000
dilutive shares of stock options, respectively, which did not effect
the EPs computation. As of December 31, 1995, stock options were
anti-dilutive. The only other potentially dilutive securities the
Company has outstanding as of December 31, 1997, 1996 and 1995, were
exchangeable convertible preferred stock and convertible subordinated
notes, which were convertible into 7,273,000 and 1,818,000 shares of
common stock, respectively, in each of these periods.
<PAGE>
Income Taxes:
Deferred tax liabilities and assets are recognized for the
anticipated future tax effects of temporary differences between the
financial statement basis and the tax basis of the Company's assets
and liabilities using the current tax rates in effect at year-end. A
valuation allowance for deferred tax assets is recorded when it is
more likely than not that the benefit from the deferred tax asset
will not be realized.
Stock Based Employee Compensation:
In October 1995, the Financial Accounting Standards Board issued
SFAS No. 123, "Accounting for Stock-Based Compensation", which
establishes accounting and reporting standards for various stock
based compensation plans. SFAS No. 123 encourages the adoption of a
fair value based method of accounting for employee stock options, but
permits continued application of the accounting method prescribed by
Accounting Principles Board Opinion No. 25 ("Opinion 25"),
"Accounting for Stock Issued to Employees". The Company has elected
to continue to apply the provisions of Opinion 25. Under Opinion 25,
if the exercise price of the Company's stock options equals the
market value of the underlying stock on the date of grant, no
compensation expense is recognized. SFAS No. 123 requires disclosure
of pro forma information regarding net income and earnings per share
as if the Company had accounted for its employee stock options under
the fair value method of the statement. See Note 12.
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 $19.0 million and $18.8 million at December 31,
1997 and 1996, respectively, as compared with the carrying value of
$20 million at December 31, 1997 and 1996, respectively. The
estimated fair value of the Notes was $4.8 million and $4.7 million
at December 31, 1997 and 1996, respectively, as compared to the
carrying value of $5 million at December 31, 1997 and 1996,
respectively.
Reclassification:
Certain amounts in prior years have been reclassified to conform
to classifications adopted in 1997.
<PAGE>
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. The Company performs
ongoing credit evaluations and generally does not require collateral.
The Company's cash and cash equivalents are maintained in major
banks. As a result, the Company believes the credit risk in such
instruments is minimal.
<TABLE>
2. PROPERTY AND EQUIPMENT
<S>
A summary of property and
equipment is as follows:
December 31, December 31,
1997 1996
Oil and gas properties: <C> <C>
Unproved properties $3,398,000 $3,059,000
Proved properties 95,780,000 78,561,000
99,178,000 81,620,000
Less accumulated depreciation and
depletion of proved properties 24,007,000 17,821,000
Net oil and gas properties 75,111,000 63,799,000
Natural gas pipelines 5,657,000 12,361,000
Less accumulated depreciation 603,000 1,202,000
Net natural gas pipelines 5,054,000 11,159,000
Furniture, fixtures and other equipment 1,033,000 1,038,000
Less accumulated depreciation 650,000 594,000
Net furniture, fixtures and other
equipment 383,000 444,000
Net property and equipment $80,548,000 $75,402,000
The Company sold its working and royalty interests in certain
oil and gas properties located in West Texas for net proceeds of
$1,570,000 effective April 30, 1996. The Company recognized a pre-
tax gain of $1,037,000 on the sale of the properties.
</TABLE>
<PAGE>
3. SALE OF ONYX
The Company entered into an agreement on July 10, 1997, to sell
it's entire 50% membership interest in Onyx. The transaction was
closed on July 31, 1997, and was effective June 30, 1997. The
proceeds consisted of a $6.3 million sales price plus a $1.8 million
repayment to the Company for advances formerly made to Onyx for
pipeline construction and other uses. The Company reduced its
domestic long-term debt by $7.8 million, concurrently, and recognized
a pre-tax book gain of approximately $5.0 million.
The following unaudited pro forma information has been prepared
as if the sale transaction has occurred on January 1, 1996 and that
the proceeds from the sale had been used to retire domestic long-
term bank debt. Management believes that the unaudited pro forma
information presented is not necessarily indicative of the financial
results as they may be in the future or as they might have been, had
the Company been able to utilize proceeds from the sale at the
beginning of such period, to develop existing leases and to acquire
additional oil and gas properties. This information is presented
for comparative purposes only.
<TABLE>
<S> Year ended December 31,
(In thousands, except per share data) 1997 1996
<C> <C>
Revenues 30,686 28,689
Net income (loss) before dividends (231) 2,963
Net income (loss) per share - basic (.11) .08
</TABLE>
4. ACQUISITION OF TRAX PETROLEUMS LIMITED
The Company acquired Trax Petroleums Limited ("Trax"), a
Canadian oil and gas exploration and development company
headquartered in Calgary, Alberta, Canada effective January 31, 1996.
The acquisition of 100% of the common stock of Trax was made through
NARL. The Trax headquarters remains in Calgary. The aggregate acqui-
sition purchase price was approximately $7,645,000 at January
31, 1996. As described in Note 1, Trax changed its name to Arch
Petroleum Ltd. ("APL") effective March 31, 1997. The Company
accounted for the acquisition of APL as a purchase. No goodwill was
recorded as the total purchase price was allocated to the net assets
of APL.
<PAGE>
5. VOLUMETRIC PRODUCTION PAYMENT
The Company sold a volumetric production payment (the "VPP") to
Enron Reserve Acquisition Corp. ("Enron") for $24,300,000 on November
30, 1992. The Company contracted to deliver to Enron the equivalent
of approximately 17.9 Bcf of natural gas from Keystone beginning
December 1, 1992. The Company is responsible for all costs of
production, development and marketing of these dedicated gas volumes.
The VPP gas reserves dedicated to Enron are excluded from the
Unaudited Supplemental Oil and Gas Disclosures, herein.
Certain rulings by the RRC in May 1993, which affected all the
Keystone operators, curtailed the production of natural gas from this
field. These production curtailments created delays in the Company's
scheduled volume deliveries to Enron. The VPP provides a mechanism
to remedy both under and over delivery of scheduled volumes. The
under deliveries of production payment volumes are converted into a
volumetric obligation which is denominated in dollars (the
"Remedy Adjustment"), which is calculated on a month ly basis by
multiplying the deficient volumes by the market price of the gas at
the end of that month. In addition, the VPP provides for interest
at 10% per year on the outstanding Remedy Adjustment. This Remedy
Adjustment is satisfied by proceeds received from the sale of
dedicated hydrocarbons from Keystone in excess of the future
scheduled volume deliveries. The Company remitted $312,000,
$1,200,000 and $1,196,000 to Enron during 1997, 1996 and 1995,
respectively, in satisfaction of a portion of the Remedy Adjustment.
During 1997, the RRC imposed further production limitations of
natural gas from Keystone. It became evident at that time that the
Company would incur significant future deficiencies and interest
under the VPP. Accordingly, in 1997 the Company has reclassified
amounts due under the Remedy Adjustment from Deferred Revenue to
Non-recourse Production Payment Obligation in the accompanying
financial statements. At December 31, 1997, the Company has treated
the past deficiencies as a repurchase of the volumetric production
payment and therefore approximately 6.0 Bcf associated with these
deficiencies have been restored to the Company's Unaudited
Supplemental Oil and Gas disclosures herein and approximately $4.2
million net has been capitalized in oil and gas property costs.
Repayment of the Remedy Adjustment is recourse only to future
production from Keystone.
The Company anticipates that the RRC will continue to impose
production limitations for Keystone in 1998 that will create
additional deficiencies in scheduled volume deliveries. The
scheduled volumes deliverable during 19 98 under the VPP at December
31, 1997 are approximately 1.9 Bcf. The Non-recourse obligation
recorded as a result of the Remedy Adjustment is approximately $13.3
million at December 31, 1997.
<PAGE>
The Company recognizes deferred revenue as deliveries of natural
gas are made under the VPP. The Company recognized deferred revenue
of $2,050,000, $2,309,000 and $3,457,000 during 1997, 1996 and 1995,
respectively. Deferred revenue was amortized at $1.20, $1.11 and
$.83 during 1997, 1996 and 1995, respectively. The amortization rate
was reduced in year s prior to 1997 to provide for the additional
volumes that would be delivered to Enron as interest on the Remedy
Adjustment. In 1997, interest expense of $1,049,000 relating to
the Remedy Adjustment is reflected in the accompanying consolidated
financial statements.
6.LONG-TERM DEBT
A summary of long-term debt is as follows:
<TABLE>
December 31,
1997 1996
<S> <C> <C>
Bank credit facilities $30,000,000 $28,009,000
Term note - 2,500,000
Note payable - minority interest holder - 744,000
Less current maturities - 1,119,000
$30,000,000 $30,134,000
</TABLE>
The Company entered into two new bank credit facilities on
February 20, 1996: 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 the Credit
Agreement among APL and Bank of Montreal, the Canadian Agent bank
(the "Canadian Revolver"). The consolidated borrowing base was
increased to $37,000,000 from $35,000,000 by third amendment to both
revolvers on August 1, 1997. The maturity date of both revolvers was
extended from May 1, 1998 to May 1, 1999 by fourth amendment on
November 1, 1997. Each of the revolvers is described briefly, as
follows:
Domestic Revolver
The Domestic Revolver is a modification of the Company's former
revolver with Bank One, Texas, N.A. and its participant, the Bank of
Scotland. The principal changes to the former revolver were the
inclusion of the Bank of Montreal as an additional participant and
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.
<PAGE>
The facility's commitment is $50,000,000 and the current
domestic borrowing base is $33,000,000. 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, so long as no event of default has
occurred and is continuing, the Company may allocate all or any
portion of its Consolidated Borrowing Base (the U.S., Domestic
Revolver borrowing base plus the APL 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 current allocation of the CBB is
$23,000,000 to the Domestic Revolver and $14,000,000 to the Canadian
Revolver.
The Company may select an interest rate option with each
borrowing advance ($500,000 minimum, in increments of $100,000)
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 in place
two business days before the commencement of an interest period of a
Eurodollar advance. A Eurodollar advance is the principal amount
under a note with respect to which an IOR is selected. For purposes
of the IOR, the effective interest rate occurring on Eurodollar
advance notes 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. The
effective interest rate increase ranges from a low of 1.75% if the
BBP is less than 25% to a high of 2.50% if the BBP is more than 75%.
There is a commitment fee of one-half of one percent for the
unused borrowing base which accrues and is payable quarterly. The
effective interest rate was 8.09% in 1997. The security collateral
requirements include essentially all of the Company's oil and gas
properties.
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 are secured by, among
other things, a first lien on 65% of the issued and outstanding
shares of NARL'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
Companys' obligations under the Domestic Revolver. The Canadian
Revolver is also guaranteed by NARL. The facility 's commitment is
US $14,000,000 and the current Canadian borrowing base is set at US
$4,000,000.
The various interest rates used in the Canadian Revolver are
based on the LIBOR or Prime Rate and are adjusted for applicable
margins based on the ratio of aggregate outstanding balances relative
to CBB (similar to the Domestic Revolver) and range from a low of
0.75% if the CBB is less than 25% to a high of 2.25% if the CBB is
more than 75%.
<PAGE>
The proceeds of each advance may be used 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 effective
interest rate was 8.14% in 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 APL borrowing base, which is currently US $4,000,000, 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.
Term Note
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. Interest on the unpaid principal amount of the note is
payable quarterly. The unpaid principal totaled $2,501,000 at
December 31, 1996, and was payable in eighteen quarterly installments
ending on March 31, 1999. Current maturities of the Onyx Note
totaled $1,111,000 at December 31, 1996. The Onyx Note is
collateralized by certain of Onyx's pipelines, gathering facilities
and related transportation contracts. In addition, the Onyx Note was
guaranteed by the Company. Onyx also had a note payable of $785,000
including interest of $41,000 as of December 31, 1996, payable to
Sejita Natural Gas, L.C., a 50% interest holder in Onyx. This note
was subordinated to the Company's bank debt and was due on
August 31, 1999.
The Company sold its interest in Onyx effective June 30, 1997.
As a result of the sale, the Company is no longer a party to the Onyx
Note described above and does not guarantee that facility as of July
31, 1997. All collateral requirements and security instruments
formerly associated with the Onyx Note were released and clear as
regards the Company as of July 31, 1997.
Both the Domestic and Canadian Revolvers 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 APL are currently
in compliance with the covenants in loan agreements. The Company
has no other unused lines of credit.
7. EXCHANGEABLE CONVERTIBLE PREFERRED STOCK
AND CONVERTIBLE SUBORDINATED NOTES
<PAGE>
On October 20, 1994, the Company sold the following securities
to four institutional investors (the "Investors") in 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 bank debt. The Company incurred $916,000
of debt issuance costs related to the Placement, which are being
amortized over the period the Preferred Stock 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 and commenced April 20,
1995. The Company paid $1,600,000 in dividends on the Preferred
Stock in 1997, 1996 and 1995. 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 follows: 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 (17,321,804) of the Company's common stock outstanding at
December 31, 1997, if all the Preferred Stock and Notes were
converted into common stock of the Company, 26,412,713 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.
<PAGE>
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. The Company paid $488,000
in interest on the Notes in 1997, 1996 and 1995. 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.
<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>
<S> 1997 1996
Domestic:
Gross deferred tax liabilities: <C> <C>
Depreciation, depletion and
intangible drilling costs $12,942,000 $ 9,628,000
Volumetric production payment - 547,000
12,942,000 10,175,000
Gross deferred tax assets:
Net operating loss carryforwards 3,452,000 4,884,000
Volumetric production payment 1,712,000 -
Statutory depletion carryforwards 1,042,000 1,042,000
Alternative minimum tax credit
carryforwards 778,000 698,000
Investment tax credit carryforwards 98,000 98,000
Other 90,000 3,000
7,172,000 6,725,000
Long term deferred tax liability $5,770,000 $3,450,000
Foreign:
Gross deferred tax assets:
Net operating loss carryforwards $ 109,000 $ 24,000
Excess of net tax basis over
book basis of property 1,279,000 477,000
Excess of net tax basis over
book basis of liabilities 123,000 122,000
Other - 82,000
Long term deferred tax asset $1,511,000 $ 705,000
</TABLE>
The components of income (loss)
before income taxes are as follows:
<TABLE>
Year Ended December 31,
<S> 1997 1996 1995
<C> <C> <C>
Domestic $6,683,000 $5,260,000 $ (250,000)
Foreign (2,179,000) (800,000) -
$4,504,000 $4,460,000 $ (250,000)
<PAGE>
The income tax provision consisted
of the following:
Year Ended December 31,
1997 1996 1995
Current:
U.S. Federal $ 89,000 $ 107,000 $ -
Foreign - - -
89,000 107,000 -
Deferred:
U.S. Federal 2,427,000 1,611,000 (86,000)
Foreign (840,000) (280,000) -
1,587,000 1,331,000 (86,000)
Income tax expense (benefit) $1,676,000 $1,438,000 $ (86,000)
</TABLE>
The provision for income taxes differs from the amount determined by
applying the U.S. federal statutory rate to income before income
taxes as a result of the following differences:
<TABLE>
Year Ended December 31,
1997 1996 1995
<S>
Provision based on federal <C> <C> <C>
statutory rate 35.0% 34.0% (34.0%)
Statutory depletion - (3.1%) (21.2%)
Effects on foreign taxes - (0.2%) -
State tax and other 2.5% 1.6% 21.2%
37.5% 32.3% (34.0%)
</TABLE>
At December 31, 1997, the Company has gross domestic tax benefit
carryforwards of approximately $9,148,000, $3,656,000, $692,000 and
$38,000 relating to net operating losses, statutory depletion,
alternative minimum tax credits and investment tax credits,
respectively, and gross foreign tax benefits of $245,000 relating to
net operating losses which expire at various dates beginning in 2000,
except for statutory depletion which does not have an expiration
date.
As a result of the acquisition of Trax, the utilization of a
portion of the Company's deferred assets are subject to limitations
imposed by various Canadian tax authorities. However, based upon the
Company's Canadian reserves and its estimated future net income
related thereto, it is management's belief that it is more likely
than not that its Canadian deferred tax assets will be utilized.
<PAGE>
9. TRANSACTIONS WITH RELATED PARTIES
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 Domestic Revolver interest rate and all of the notes are secured
by stock certificates that were issued upon exercise of the stock
options by each employee. The notes mature May 13, 1999. The
balances due to the Company in this regard, including interest, were
$1,047,000 and $1,022,000 at December 31, 1997 and 1996,
respectively. These amounts are offset against equity on the
Company's consolidated balance sheet. There have not been any
additional notes of this nature since 1993.
The Board of Directors of the Company also authorized one time
cash advances to certain officers in 1993 in exchange for notes
receivable. These notes also bear interest at the Domestic Revolver
interest rate and are secured by stock certificates of the Company
owned by those individuals. The notes mature May 13, 1999. The
notes, including interest, total $1,872,000 and $1,759,000 at
December 31, 1997 and 1996, respectively. The Company recognized
interest income on all its outstanding notes receivable from
officers, directors and key employees of $179,000, $174,000 and
$188,000 during 1997, 1996 and 1995, respectively.
Onyx had transactions in the ordinary course of business with
Corpus Christi Gas Marketing ("CCGM"). CCGM's president serves as
one of Onyx's Managers. At December 31, 1996, Onyx had a gas
imbalance payable of $120,000 to CCGM.
The consolidated financial statements include certain amounts
and balances that arise from transactions with related parties:
<TABLE>
At December 31, 1997 At December 31, 1996
Accounts Accounts Accounts Accounts
<S> Receivable Payable Receivable Payable
<C> <C> <C> <C>
TDC, net $2,135,000 $ - $1,551,000 $ -
CCGM - - 275,000 1,911,000
Cedar Energies, Inc. - - -
60,000
$2,135,000 $ - $1,826,000 $1,971,000
</TABLE>
<PAGE>
<TABLE>
For Year Ended For Year Ended For Year Ended
December 31, 1997 December 31, 1996 December 31, 1995
Purchases Sales Purchases Sales Purchases Sales
From To From To From To
<S> <C> <C> <C> <C> <C> <C>
CCGM $10,246,000 $1,518,000 $10,196,000 $1,120,000 $ 39,000 $ 265,000
Sejita
Natural Gas - - - - 8,000 -
Libra
Marketing - - - - 5,000 -
Cedar
Energies,
Inc. 157,000 - 266,000 - 239,000 -
Puma
Resources - - - - - 171,000
$10,403,000 $1,518,000 $10,462,000 $1,120,000 $291,000 $ 436,000
</TABLE>
The Company rented an aircraft from TDC, on an as-needed basis,
prior to 1997. Charges for this service were billed to the Company
based on time used. Rental charges amounted to $20,000 and $39,000
for the years ended December 31, 1996 and 1995, respectively. TDC
is the operator of certain wells in North Texas in which the Company
owns interests. The increase in the receivable from TDC in 1997
primarily relates to revenues earned for 1997 production from
those wells. TDC paid the Company those revenues subsequent to
December 31, 1997. Commencing January 1, 1997,the net unpaid balance
due to the Company by TDC accrues interest at the Company's
Domestic Revolver interest rate. Under agreement with TDC, the
Company has the right of offset with TDC. Accordingly, the 1997 and
1996 TDC balances are shown net in the financial statements.
10. MAJOR CUSTOMERS
The following major customers represent 10% or more of total
operating revenues by industry segment for the years ended December
31, 1997, 1996 and 1995:
<TABLE>
<S>
Oil and Gas 1997 1996 1995
<C> <C> <C>
Genesis Crude Oil, L.P. 29% 32% 13%
Enron Gas Marketing 12% 23% 31%
Richardson Products Company 21% * *
Chevron U.S.A. Inc. * 12% 31%
</TABLE>
The Company's principal products are oil and natural gas. The
principal market for such products is primarily the Southwestern
United States and Western Canada where in 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>
<S>
Natural Gas Pipelines 1997 1996 1995
<C> <C> <C>
Central Power and Light 50% 61% 58%
</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% in period.
<PAGE>
11. COMMITMENTS AND CONTINGENCIES
Commitments:
The Company leases office space, an airplane, office equipment
and vehicles under various lease agreements with primary lease terms
ranging from three to five years. Rental expense on these leases was
$365,000, $249,000 and $202,000 in the years ended December 31,
1997, 1996 and 1995, respectively. Aggregate future minimum
rental payments required pursuant to noncancellable leases are as
follows: 1998 - $377,000, 1999 - $313,000, 2000 - $211,000, 2001
- $131,000 and 2002 - $3,000.
Contingencies:
The Company has entered into employment agreements with certain
key employees in 1996 and 1997. In the event that following a change
of control employment is terminated for those key employees for
reasons specified in the agreements, the employees would receive a
lump sum payment at the time of termination as specified in the
agreement. There is a calculated ceiling in the agreement. As of
February 28, 1998, the maximum payout attributable to these
employment agreements is approximately $975,000.
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
The Company's 1993 Stock Option 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. The majority of currently outstanding
options vest over a three year period (33%, 66%, 100%).
Unaudited pro forma information regarding net income and
earnings per share is required by SFAS No. 123, if material, and has
been determined as if the Company had accounted for its employee
stock options under the fair value method of that statement. The
fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following
weighted average assumptions used for grants in 1997 and 1995,
respectively: no dividend yield, expected volatility of 48% and 37%,
risk free interest rate of 6% and 7% and expected lives of four and
five years. There were no option grants during 1996.
For purposes of pro forma disclosures, the estimated fair value
of the options is amortized to expense over the options' vesting
period. Applying the effect of the pro forma expense did not
materially affect the Company's 1997, 1996 and 1995 reported net
income (loss) and income (loss) per common share.
<PAGE>
Stock option transactions, in the period from January 1, 1995 to
December 31, 1997 are summarized below:
<TABLE>
1997 1996 1995
Wtd. Wtd. Wtd.
Avg. Avg. Avg.
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
<S> <C> <C> <C> <C> <C> <C>
Outstanding
at beginning
of year 319,300 $1.84 361,700 $1.84 292,700 $1.81
Granted 75,000 2.89 - 75,000 1.94
Exercised (20,000) 2.00 (400) 1.81
Forfeited (35,000) 1.97 (42,000) 1.81 (6,000) 1.81
Outstanding at
end of year 339,300 $2.05 319,300 $1.84 361,700 $1.84
Exercisable at
end of year 242,600 $1.87 259,300 $1.82 230,300 $1.82
Weighted average
fair value of
options granted
during the year $1.32 - $0.85
</TABLE>
<PAGE>
The following table summarizes information about the options
outstanding at December 31, 1997:
<TABLE>
Wtd. Wtd. Wtd.
Avg. Avg. Avg.
Range of Contrac Exerci Exerci
tual se se
Grant Date Expiration Prices Outstan Life in Price Exercisa Price
Date ding Years ble
<S> <S> <C> <C> <C> <C> <C> <C>
July 7, May 31,
1993 2003 $1.81 214,300 5.41 214,300
May 20, May 20,
1995 2000 1.81 50,000 2.39 20,000
March 1, March 1,
1997 2002 2.56 30,000 4.16 -
April 8, April 8,
1997 2002 2.69 10,000 4.25 -
May 26, May 26,
1997 2002 2.91 10,000 4.40 -
July 9, July 9,
1997 2000 3.22 10,000 2.50 3,300
September September
15, 1997 15, 2000 3.44 15,000 2.70 5,000
$1.81 - 339,300 4.59 $2.05 242,600 $1.87
$3.44
</TABLE>
At December 31, 1997, 1,310,700 shares were available for grant.
<PAGE>
13. GEOGRAPHIC AND INDUSTRY SEGMENT INFORMATION
The Company operates in two industry segments: oil and
gas exploration, development and production and natural gas
marketing, transportation and distribution. In addition, the
Company has oil and gas operations in the United States and
Western Canada. Operating profit by segment is defined as
revenues less operating expenses. Income and expense items excluded
from operating profit 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
all 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.
Financial information by geographic and industry segment for
the years ended December 31, 1997, 1996 and 1995 follows. Prior to
1996, the Company operated only in the United States.
<PAGE>
<TABLE>
Natural Gas
(In thousands) Oil and Gas Pipelines Total
<S> <C> <C> <C>
1997
Identifiable assets $ 86,721 $ 6,450 $ 93,171
Revenues (1) 23,750 56,438 80,188
Exploration costs and expenses 1,134 - 1,134
Depletion, depreciation and
amortization 6,782 329 7,111
Operating income 1,703 6,615 8,318
Capital expenditures 14,108 443 14,551
1996
Identifiable assets $ 75,785 $ 25,254 $ 101,039
Revenues (1) 24,914 74,309 99,223
Exploration costs and expenses 593 - 593
Depletion, depreciation and
amortization 6,460 444 6,904
Operating income 5,758 1,475 7,233
Capital expenditures 8,421 913 9,334
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 6,164 264 6,428
(In thousands) United States Canada Total
1997
Identifiable assets $ 79,343 $ 13,828 $ 93,171
Revenues (1) 77,521 2,667 80,188
Exploration costs and expenses 401 733 1,134
Depletion, depreciation and
amortization 5,627 1,484 7,111
Operating income (loss) 9,737 (1,419) 8,318
Capital expenditures 11,471 3,080 14,551
1996
Identifiable assets $ 89,672 $ 11,367 $101,039
Revenues (1) 96,785 2,438 99,223
Exploration costs and expenses 200 393 593
Depletion, Depreciation and
amortization 5,763 1,141 6,904
Operating income (loss) 7,447 (214) 7,233
Capital expenditures 6,991 2,343 9,334
</TABLE>
<PAGE>
15. UNAUDITED QUARTERLY FINANCIAL DATA
A summary of consolidated financial data for 1997 and 1996
follows (in thousands, except per share amounts):
<TABLE>
First Second Third Fourth
Quarter Quarter Quarter Quarter
Year Ended December
31, 1997
<S> <C> <C> <C> <C>
Operating
revenues (1) (3) $ 33,142 $ 27,307 $ 12,634 $ 7,779
Exploration costs and
expenses 75 127 649 283
Gross profit (3) 3,975 2,644 6,554 1,508
Net income (loss) 900 55 2,919 (1,046)
Net income (loss) per
share (2) " basic $ 0.03 $(0.02) $0.15 $(0.08)
Net income per share
(2) " diluted N/A N/A $0.12 N/A
Year Ended December
31, 1996
Operating
revenues (1) $19,765 $23,416 $23,071 $33,674
Exploration costs and
expenses 51 127 312 103
Gross
profit 2,523 3,924 2,864 3,728
Net income 488 938 595 1,001
Net income per share
(2) - basic $ 0.01 $ 0.03 $ 0.01 $ 0.04
Net income per share
(2) - diluted N/A N/A N/A N/A
</TABLE>
Gross profit represents income before income taxes excluding
general and administrative expense, interest expense, foreign
currency transaction loss and minority interest in income of
consolidated subsidiaries.
(1) - Includes gain on sale of natural gas pipeline of $5,046,000 in
1997 and gain on sale of domestic oil and gas properties of
$1,037,000 in 1996.
(2) - After dividends on preferred stock.
(3) - Includes $224,000, $233,000, $273,000 and none which has been
reclassified as additional gas sales in accordance with the
accounting for the Remedy Adjustments disccused in Note 5.
<PAGE>
<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, 1997, 1996 and 1995,
and the changes therein. All of the Company's oil and gas activities
are located within the United States and Western Canada. None of the
Company's reserves are subject to long-term supply agreements with a
governmental agency.
<PAGE>
<TABLE>
<S> United States Canada Total
Natural Gas (Mcf)
Net proved reserves, <C> <C> <C>
December 31, 1994 61,546,200 - 61,546,200
Extensions and discoveries 4,138,000 - 4,138,000
Production (4,291,900) - (4,291,900)
Revision of previous
estimates (106,000) - (106,000)
Net proved reserves,
December 31, 1995 61,286,300 - 61,286,300
Purchases of minerals
in place - 1,015,200 1,015,200
Sales of minerals
in place (1,191,500) - (1,191,500)
Extensions and discoveries 1,776,000 273,000 2,049,000
Production (3,845,200) (152,200) (3,997,400)
Revisions of previous
estimates 1,095,300 - 1,095,300
Net proved reserves,
December 31, 1996 59,120,900 1,136,000 60,256,900
Extensions and discoveries 3,889,000 5,246,000 9,135,000
Production (3,362,600) (181,200) (3,543,800)
Revisions of previous
estimates (1) 8,783,400 374,200 9,157,600
Net proved reserves,
December 31, 1997 68,430,700 6,575,000 75,005,700
Oil (Bbl)
Net proved reserves,
December 31, 1994 3,586,400 - 3,586,400
Extensions and discoveries 1,126,000 - 1,126,000
Production (382,100) - (382,100)
Revision of previous
estimates (300,100) - (300,100)
Net proved reserves,
December 31, 1995 4,030,200 - 4,030,200
Purchases of minerals
in place - 682,500 682,500
Sales of minerals in place (37,700) - (37,700)
Extensions and discoveries 395,000 294,700 689,700
Production (459,300) (120,300) (579,600)
Revision of previous estimates (67,200) - (67,200)
Net proved reserves,
December 31, 1996 3,861,000 856,900 4,717,900
Extensions and discoveries 793,500 82,500 876,000
Production (528,400) (128,600) (657,000)
Revision of previous
estimates 934,400 2,100 936,500
Net proved reserves,
December 31, 1997 5,060,500 812,900 5,873,400
</TABLE>
(1) - Includes approximately 6.0 Bcf associated with deficiencies of
the Remedy Adjustment as discussed in Note 5.
<PAGE>
<TABLE>
United States Canada Total
<S>
Proved developed reserves: <C> <C> <C>
Natural gas (Mcf)
December 31, 1995 55,628,500 - 55,628,500
December 31, 1996 54,981,200 504,000 55,485,200
December 31, 1997 65,324,800 6,489,000 71,813,800
Oil (Bbl)
December 31, 1995 2,993,600 - 2,993,600
December 31, 1996 3,128,400 809,900 3,938,300
December 31, 1997 4,475,600 693,800 5,169,400
</TABLE>
The Company's proved reserves exclude 1.9 Bcf, 8.7 Bcf and 11.9
Bcf of gas reserves at December 31, 1997, 1996 and 1995,
respectively, which were sold under the VPP in December 1992 for
$1.30 per Mcf. The Company is required to deliver these gas
production volumes through July 1998 and thereafter under the terms
of the VPP agreement. The revenue associated with these reserves,
which is deferred, is recognized as production is delivered.
Costs Incurred in Oil and Gas Activities
Costs incurred in oil and gas property acquisition, exploration
and development activities are set forth below:
<TABLE>
United States Canada Total
1995
<S> <C> <C> <C>
Acquisition of properties:
Proved $ 274,000 $ - $ 274,000
Unproved 108,000 - 108,000
Exploration 898,000 - 898,000
Development 4,937,000 - 4,937,000
1996
Acquisition of properties:
Proved $ 442,000 $ 6,667,000 $7,109,000
Unproved - 2,185,000 2,185,000
Exploration 125,000 1,590,000 1,715,000
Development 5,514,000 400,000 5,914,000
1997
Acquisition of properties:
Proved $ 78,000 $ 220,000 $ 298,000
Unproved 17,000 322,000 339,000
Exploration 623,000 733,000 1,356,000
Development 10,323,000 1,792,000 12,115,000
</TABLE>
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Gas Reserves
<TABLE>
United States Canada Total
1995
<S> <C> <C> <C>
Future cash inflows $182,785,400 $ - $182,785,400
Future production and
development costs 66,311,500 - 66,311,500
Future income tax
expenses 22,434,000 - 22,434,000
Future net cash flows
undiscounted 94,039,900 - 94,039,900
10% annual discount
for estimated timing
future net cash flows 42,127,800 - 42,127,800
Standardized measure of
discounted future net
cash flows $51,912,100 $ - $51,912,100
1996
Future cash inflows $309,315,400 $29,589,400 $338,904,800
Future production and
development costs 118,878,800 12,846,900 131,725,700
Future income tax
expenses 50,507,300 3,898,600 54,405,900
Future net cash flows
undiscounted 139,929,300 12,843,900 152,773,200
10% annual discount
for estimated timing
of cash flows 65,201,200 3,758,500 68,959,700
Standardized measure of
discounted future net
cash flows $ 74,728,100 $ 9,085,400 $ 83,813,500
1997
Future cash inflows $239,670,400 $ 21,085,100 $260,755,500
Future production and
development costs 117,082,300 8,470,600 125,552,900
Future income tax expenses 27,908,300 1,527,300 29,435,600
Future net cash flows
undiscounted 94,679,800 11,087,200 105,767,000
10% annual discount
for estimated timing
of cash flows 40,516,200 3,684,700 44,200,900
Standardized measure of
discounted future net
cash flows $ 54,163,600 $ 7,402,500 $ 61,566,100
</TABLE>
<PAGE>
Future net cash flows were computed using year end prices and
costs. For the reserve reports as of December 31, 1997, 1996 and
1995, respectively, the average domestic prices were $16.89, $24.97
and $18.82 for oil and $2.25, $3.60 and $1.76 for gas. For the
reserve reports as of December 31, 1997, and 1996, respectively, the
average foreign prices were $16.31 and $25.41 for oil and $1.12 and
$1.84 for gas. Oil and gas prices at December 31, 1996 were higher
than those realized on average by the Company over the past five
years. Also, prices at the end of the first quarter of 1998 are
below those at the end of 1997. Changes in prices could have a
material effect on reserve estimates and related future net cash flow
amounts.
The standardized measure of discounted future net cash flows at
December 31, 1997, 1996 and 1995, as presented in the table above,
excludes future net cash flows associated with the VPP as described
in Note 5. The discounted future net cash flows related to the
VPP approximates $436,400, $2,960,600 and $11,672,700 which amounts
are net of discounted future production costs of $1,856,000,
$3,831,000, and $1,912,700 at December 31, 1997, 1996 and 1995,
respectively. 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:
<PAGE>
<TABLE>
United States Canada Total
<S> <C> <C> <C>
December 31, 1994 $48,520,400 $ - $48,520,400
Net changes in prices
and costs, exclusive of
properties purchased and
sold 2,736,100 - 2,736,100
Net change in income taxes 174,100 - 171,000
Sales of oil and gas
produced, net of production
costs (6,001,800) - (6,001,800)
Revisions of previous
quantity estimates (1,464,900) - (1,464,900)
Extensions and discoveries,
less related costs 9,241,100 - 9,241,100
Changes in estimated future
development costs (5,899,500) - (5,899,500)
Development costs incurred
previously estimated 740,700 - 740,700
Accretion of discount 4,852,000 - 4,852,000
Timing and other (986,100) - (986,100)
December 31, 1995 51,912,100 - 51,912,100
Purchases of minerals in
place 2,176,600 9,473,800 11,650,400
Sales of minerals in place (595,800) - (595,800)
Net changes in prices
and costs, exclusive of
properties purchased and
sold 46,473,300 - 46,473,300
Net change in income taxes (14,589,000) (2,757,700) (17,346,700)
Sales of oil and gas
produced, net of production
costs (11,479,600) (1,420,500) (12,900,100)
Revisions of previous
quantity estimates 961,900 - 961,900
961,900
Extensions and discoveries,
less related costs 5,719,000 3,789,800 9,508,800
Changes in estimated
future operating costs (13,709,200) - (13,709,200)
Changes in estimated
future development costs (232,400) - (232,400)
Development costs incurred
previously estimated 3,742,000 - 3,742,000
Accretion of discount 5,191,200 - 5,191,200
Timing and other (842,000) - (842,000)
</TABLE>
<PAGE>
<TABLE>
<S> <C> <C> <C>
December 31, 1996 74,728,100 9,085,400 83,813,500
Net changes in prices and
costs, exclusive of properties
purchased and sold (48,688,400) (4,479,500) (53,167,900)
Net change in income taxes 20,847,300 1,612,500 22,459,800
Sales of oil and gas
produced, net of
production costs (11,695,700) (1,612,000) (13,307,700)
Revisions of previous
quantity estimates 9,593,100 420,600 10,013,700
Extensions and discoveries,
less related costs 12,535,200 2,788,800 15,324,000
Changes in estimated future
development costs (2,085,400) (293,300) (2,378,700)
Development costs incurred
previously estimated 3,389,100 572,400 3,961,500
Accretion of discount 7,472,800 908,500 8,381,300
Timing and other (11,932,500) (1,600,900) (13,533,400)
December 31, 1997 $54,163,600 $7,402,500 $61,566,100
</TABLE>
<PAGE>
Results of Operations from Oil and Gas Producing Activities
<TABLE>
United States Canada Total
1995
<S> <C> <C> <C>
Revenues $16,599,000 $ - $16,599,000
Production costs (7,176,000) - (7,176,000)
Exploration expenses (898,000) - (898,000)
Depletion, depreciation
and amortization (4,973,000) - (4,973,000)
3,552,000 - 3,552,000
Income tax expense (1,208,000) - (1,208,000)
Results of operations $ 2,344,000 $ - $2,344,000
1996
Revenues $21,439,000 $ 2,438,000 $ 23,877,000
Production costs (7,591,000) (490,000) (8,081,000)
Exploration expenses (200,000) (393,000) (593,000)
Depletion, depreciation
and amortization (5,321,000) (1,139,000) (6,460,000)
8,327,000 416,000 8,743,000
Income tax (expense) benefit (2,681,000) 280,000 (2,401,000)
Results of operations $ 5,646,000 $ 696,000 $ 6,342,000
1997
Revenues $21,083,000 $ 2,667,000 $ 23,750,000
Production costs (7,912,000) (850,000) (8,762,000)
Exploration expenses (401,000) (733,000) (1,134,000)
Depletion, depreciation
and amortization (5,298,000) (1,484,000) (6,782,000)
7,472,000 (400,000) 7,072,000
Income tax (expense) benefit (2,516,000) 840,000 (1,676,000)
Results of operations $4,956,000 $ 440,000 $ 5,396,000
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
On September 18, 1997, the Company filed Form 8-K pursuant to
changing its independent accountants.
PART III
<PAGE>
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 May 4, 1998, pursuant to Regulation 14A in
connection with its Annual Meeting of Shareholders to be held on May
29, 1998, 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 May
4, 1998, pursuant to Regulation 14A in connection with its Annual
Meeting of Shareholders to be held on May 29, 1998, 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 May 4, 1998, pursuant to Regulation 14A in
connection with its Annual Meeting of Shareholders to be held on May
29, 1998, 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 May 4, 1998,
pursuant to Regulation 14A in connection with its Annual Meeting of
Shareholders to be held on May 29, 1998, which is incorporated herein
by reference.
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 16.
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 44) are filed by reference as part of this Form 10-K.
<PAGE>
B. Reports on Form 8-K
No reports on Form 8-K were filed by the Company during the
quarter ended December 31, 1997.
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 4.3 Certificate of Incorporation of Arch Petroleum Inc.,
incorporated herein by reference to Exhibit 4.1 to
Form S-8 dated December 17, 1997.
Exhibit 4.4 Certificate of Amendment of Certificate of
Incorporation of Arch Petroleum Inc., as filed with
the Delaware Secretary of State on December 22, 1994,
incorporated herein by reference to Exhibit 4.2 to
Form S-8 dated December 17, 1997.
Exhibit 4.5 Certificate of Correction to Certificate of Amendment
of Arch Petroleum Inc., as filed with the Delaware
Secretary of State on May 21, 1992, incorporated
herein by reference to Exhibit 4.3 to Form S-8 dated
December 17, 1997.
Exhibit 4.6 Certificate of Amendment of Certificate of
Incorporation of Arch Petroleum Inc., as filed with
the Delaware Secretary of State on February 8, 1995,
incorporated herein by reference to Exhibit 4.4 to
Form S-8 dated December 17, 1997.
Exhibit 4.7 Certificate of Designation of Preferences and Rights
of Exchangeable Convertible Preferred Stock of Arch
Petroleum Inc., incorporated herein by reference to
Exhibit 4.5 to Form S-8 dated December 17, 1997.
Exhibit 4.8 By-laws of Arch Petroleum Inc., incorporated herein by
reference to Exhibit 4.6 to Form S-8 dated December
17, 1997.
Exhibit 4.9 Arch Petroleum Inc. 1993 Stock Option Plan,
incorporated herein by reference to Exhibit 4.7 to
Form S-8 dated December 17, 1997.
<PAGE>
Exhibit 5.1 Opinion of Weil, Gotshal & Manges LLP, incorporated
herein by reference to Exhibit 5.1 to Form S-8 dated
December 17, 1997.
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.
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.
<PAGE>
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 23.1 Consent of Price Waterhouse LLP.
Exhibit 23.2 Consent of Price Waterhouse LLP, incorporated herein
by reference to Exhibit 23.1 to Form S-8 dated
December 17, 1997.
Exhibit 23.3 Consent of Weil, Gotshal & Manges LLP (included in
Exhibit 5.1), incorporated herein by reference to
Exhibit 23.2 to Form S-8 dated December 17, 1997.
Exhibit 24.1 Power of Attorney (see pages II-8 and II-9 of
Registration Statement on Form S-8), incorporated
herein by reference to Exhibit 24.1 to Form S-8 dated
December 17, 1997.
SIGNATURES
<PAGE>
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, April 15, 1998
Director, President and Chief Executive Officer
(Principal Executive Officer)
By: /s/Fred Cantu
Fred Cantu, April 15, 1998
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 Vinson
Johnny Vinson, April15, 1998
Director
By: /s/Randall W. Scroggins
Randall W. Scroggins, April 15, 1998
Director
By: /s/Richard O. Harris
Richard O. Harris, April 15, 1998
Director
By: /s/C. Randall Hill
C. Randall Hill, April 15, 1998
Director
By: /s/John F. Gilsenan
John F. Gilsenan, April 15, 1998
Director
By: /s/Dale R. Haley
Dale R. Haley, April 15, 1998
Director
<PAGE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 2,160
<SECURITIES> 0
<RECEIVABLES> 4,314
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 7,018
<PP&E> 105,868
<DEPRECIATION> 25,320
<TOTAL-ASSETS> 93,171
<CURRENT-LIABILITIES> 6,550
<BONDS> 0
20,000
0
<COMMON> 173
<OTHER-SE> 9,965
<TOTAL-LIABILITY-AND-EQUITY> 93,171
<SALES> 75,014
<TOTAL-REVENUES> 80,862
<CGS> 57,936
<TOTAL-COSTS> 57,936
<OTHER-EXPENSES> 8,245
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,040
<INCOME-PRETAX> 4,504
<INCOME-TAX> 1,676
<INCOME-CONTINUING> 2,828
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,828
<EPS-PRIMARY> .07
<EPS-DILUTED> .07
</TABLE>
