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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
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ________ TO ________
COMMISSION FILE NUMBER 0-11871
AMERICAN EXPLORATION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 74-2086890
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
1331 LAMAR, SUITE 900
HOUSTON, TEXAS 77010
(Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 756-6000
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, $.05 par value American Stock Exchange
Depositary Shares, each representing American Stock Exchange
a 1/200 interest in a share of $450
Cumulative Convertible Preferred Stock,
Series C, par value $1.00 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
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 ____
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. _______
The aggregate market value of the voting stock held by non-affiliates
of the Company was $203,228,652 based on the closing price on February 28, 1997
as reported on the American Stock Exchange. As of February 28, 1997, there
were outstanding 15,695,008 shares of the Company's Common Stock.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement relating to the 1997 Annual
Meeting of Stockholders of the Company, which will be filed within 120 days of
December 31, 1996, are incorporated by reference into Part III of this Report.
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TABLE OF CONTENTS
Page
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PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . 17
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . 24
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . 25
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . 25
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . 25
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . 26
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PART I
This Report on Form 10-K includes certain statements that may be deemed
to be "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of
the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All
statements, other than statements of historical facts, included in this Report
on Form 10-K that address activities, events or developments that the Company
expects, believes or anticipates will or may occur in the future, including
such matters as future capital, development and exploration expenditures
(including the amount and nature thereof), drilling of wells, reserve estimates
(including estimates of future net revenues associated with such reserves and
the present value of such future net revenues), future production of oil and
gas, repayment of debt, business strategies, expansion and growth of the
Company's operations and other such matters are forward-looking statements.
These statements are based on certain assumptions and analyses made by the
Company in light of its experience and its perception of historical trends,
current conditions, expected future development and other factors it believes
are appropriate in the circumstances. Such statements are subject to a number
of assumptions, risks and uncertainties, (including the risk factors discussed
elsewhere herein including under Items 1 and 2. "Business and Properties -
Certain Risk Factors," "- Regulation," and "- Environmental Matters," and Item
7. "Management's Discussion and Analysis of Financial Condition and Results of
Operations - General" and "- Changing Oil and Gas Prices"), general economic
and business conditions, the business opportunities (or lack thereof) that may
be presented to and pursued by the Company, changes in law or regulations and
other factors, many of which are beyond the control of the Company. Readers
are cautioned that any such statements are not guarantees of future performance
and that actual results or developments may differ materially from those
projected in the forward-looking statements.
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
American Exploration Company ("American" or the "Company") is an
independent company engaged in the exploration, development and production of
oil and natural gas. American's oil and gas operations are conducted in the
United States with exploration, development and acquisition activities
concentrated in the Gulf of Mexico, South Texas, East Texas and southwestern
Arkansas.
American's proved reserves at December 31, 1996 totaled approximately
42.3 million barrels of oil equivalent ("MMBOE"), of which 66% were natural gas
based on a conversion factor of six thousand cubic feet ("Mcf") of gas per
barrel ("Bbl") of oil. Approximately 80% of total proved reserves are
developed, and approximately 58% are attributable to properties operated by the
Company. The Company also holds approximately 300,000 net acres of undeveloped
properties.
American's executive offices are located at 1331 Lamar, Suite 900,
Houston, Texas 77010, telephone 713-756-6000. At February 1, 1997, American
had 158 full-time employees, none of whom is represented by any labor union.
BUSINESS STRATEGY
American's strategy is to increase reserves, production, cash flow and
earnings through exploration, development and selective acquisitions within its
core operating areas. The Company's strategy is designed to capitalize on its
competitive strengths, including the experience and technical expertise of its
operating personnel, a substantial seismic database and a concentration of
developed and undeveloped acreage in its core operating areas. The principal
features of this strategy are set forth below.
GEOGRAPHIC FOCUS. The Company's exploration, development and
acquisition activities are primarily focused in the Gulf of Mexico, South Texas
(with an emphasis on the Wilcox and Frio Trends), the Cotton Valley Pinnacle
Reef Trend in East Texas and the Smackover Trend in southwestern Arkansas. The
Company believes that by focusing its operations, it can achieve cost
efficiencies and enhance its ability to add new reserves. In 1996,
approximately 90% of the Company's exploration and development budget and
substantially all of its acquisition activities were concentrated in its core
operating areas. The Company is also in the process of divesting certain
properties that are not consistent with its geographic focus and may, from time
to time, divest additional non-strategic properties.
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ACTIVE DRILLING PROGRAM. The Company is engaged in an active drilling
program and attempts to maintain a project portfolio consisting of development,
exploitation and exploration projects. The Company's development and
exploitation activities include development drilling, recompletions of existing
wells into new zones and facilities work. During 1996, the Company spent
approximately $15.6 million on development activities and drilled 52 gross (14
net) wells, 92% of which were successfully completed. The Company's
exploration activities are generally concentrated in areas where in-house
geological knowledge and two-dimensional ("2-D") seismic data can be used to
identify prospect leads. The Company then attempts to establish large lease
positions and generally initiates or acquires three-dimensional ("3-D")
seismic data to confirm prospects prior to drilling. The Company typically
shares the risks associated with its exploration prospects with industry
partners. In addition to internally generated exploration prospects, the
Company selectively participates in exploration prospects initiated by other
oil and gas companies. During 1996, the Company spent approximately $26.7
million on exploration and drilled 32 gross (15 net) wells, 50% of which were
successfully completed.
SELECTIVE ACQUISITIONS. The Company's acquisition strategy is to
acquire producing properties within its core operating areas that enhance its
competitive position, offer economies of scale and provide further development
and/or exploration potential. The Company seeks to acquire properties in which
it can obtain a significant ownership percentage and become the operator.
During 1996, the Company invested approximately $67.9 million to acquire
interests in seven blocks in the Gulf of Mexico, four of which are operated by
the Company, and certain other proved property interests, including additional
working interests in several of the Company's largest fields.
ADVANCED TECHNICAL CAPABILITIES. The Company makes extensive use of
advanced technologies, most notably 3-D seismic, computer-aided exploration and
specialized drilling applications such as short radius horizontal wells, to
better delineate or produce oil and gas reserves. The Company's staff of
geologists and geophysicists performs all interpretation and seismic mapping on
in-house 3-D seismic workstations.
FINANCIAL FLEXIBILITY, COST EFFICIENCY. The Company is committed to
maintaining financial flexibility in order to pursue its existing exploration
and development projects and to take advantage of future opportunities. Over
the past four years, the Company has implemented a number of steps to reduce
debt and improve its liquidity and financial flexibility. Largely as a result
of these steps, the Company's ratio of total debt to total capitalization has
decreased from 60% at December 31, 1992 to 32% at December 31, 1996. Through
cost reductions, the addition of higher margin properties and higher oil and
gas prices, the Company's operating margin has increased from $2.72 per BOE for
the year ended December 31, 1992 to $6.71 per BOE for the year ended December
31, 1996.
SIGNIFICANT EVENTS IN 1996
ACQUISITION OF ANCON INTERESTS. In December 1996, the Company acquired
from New York Life Insurance Company ("New York Life") and certain of its
affiliates (collectively, the "Limited Partners") the Limited Partners'
aggregate 80% interest in Ancon Partnership Ltd. ("Ancon") for a purchase price
of approximately $12.9 million (the "Ancon Acquisition"). The Company served
as general partner of Ancon and owned a 20% interest in the partnership. The
acquisition was funded through borrowings under the Company's revolving bank
credit agreement (the "Credit Agreement"). The net assets acquired by the
Company included interests in proved oil and gas reserves totaling an estimated
2.3 MMBOE as of October 1, 1996, the effective date of the transaction, and
$5.2 million of working capital. The acquisition of the Limited Partners'
interests increased the Company's net ownership position in several of its
major properties, including the Bradshaw and Bowdoin fields.
SEPTEMBER 1996 ACQUISITION. In September 1996, the Company acquired
interests in two blocks in the Gulf of Mexico, High Island Block 116 and East
Cameron Block 328, for a purchase price of approximately $39 million, net of
interests that were sold to a third party in November 1996 (the "September 1996
Acquisition"). The acquisition was funded through borrowings under the Credit
Agreement. The acquired properties added estimated proved reserves (as
estimated by the Company as of the date of acquisition) totaling 3.6 MMBbls of
oil and 16.9 Bcf of natural gas. The Company initiated a multi-well
development drilling program on East Cameron Block 328 in December 1996 and
believes that both blocks have additional unproved reserve potential through
higher primary reserve recovery and additional drilling.
MARCH 1996 ACQUISITION. In March 1996, the Company and a subsidiary of
Dominion Resources, Inc. acquired interests in five offshore blocks in the Gulf
of Mexico for a purchase price of approximately $56 million (the "March 1996
Acquisition" and, together with the September 1996 Acquisition, the "Offshore
Acquisitions"). The Company's 25% share of the March 1996 Acquisition was
funded through borrowings of approximately $14 million under the Credit
Agreement.
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The acquired properties added estimated proved reserves (as estimated by the
Company as of the date of acquisition) totaling 600 MBbls of oil and 11.3 Bcf
of natural gas, net to the Company's interest. Three of the acquired
properties, High Island Block 45, South Marsh Island Block 133 and East Cameron
Block 129, which together represent substantially all of the proved reserve
value of the properties acquired in the March 1996 Acquisition, are operated by
the Company. During the third quarter of 1996, the Company completed the
installation of production facilities on East Cameron Block 129 and completed a
development well on South Marsh Island Block 133. The Company believes that
the acquired properties have additional reserve potential through higher
primary reserve recovery and the installation of gas compression.
1996 SALES. In July 1996, the limited partners of the New York Life
Oil and Gas Producing Properties Programs (the "NYLOG Programs"), a series of
publicly registered limited partnerships of which a Company subsidiary is a co-
general partner, approved the liquidation of the partnerships (the "NYLOG
Liquidation"). During the fourth quarter of 1996, the Company closed the sales
of interests in approximately 100 oil and gas properties, including those
properties owned by the NYLOG Programs and certain related properties (the
"1996 Sales"). The Company received net proceeds from the sales of its
property interests aggregating approximately $10.1 million. The Company
believes that the divestiture of numerous minor property interests located
outside of American's core operating areas will provide additional operating
efficiencies.
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PRIMARY OPERATING AREAS
Set forth below is information concerning certain of the Company's
significant fields.
As of December 31, 1996
------------------------------------------------
Present Value
of Estimated
Proved Reserves Future
Average --------------------------------
Working Oil Gas Net Revenues
Operator Interest (MBbls) (MMcf) MBOE (in thousands)
--------- --------- --------- --------- --------- --------------
Gulf of Mexico
High Island Block 116 . . . . . Other 44% 192 13,989 2,523 $ 42,299
East Cameron Block 328 . . . . . AX 100% 3,290 2,209 3,658 40,140
High Island Block 45 . . . . . . AX 21% 24 6,620 1,127 16,433
South Marsh Island Block 133 . . AX 25% 506 325 560 9,341
Brazos Complex . . . . . . . . . AX 52% 12 6,057 1,022 8,448
High Island Block 98-L . . . . . Other 22% 40 4,438 780 7,057
Other . . . . . . . . . . . . . AX/Other Varies 47 3,847 688 10,476
--------- --------- --------- -----------
. . . . . . . . . . . . . . . . . . 4,111 37,485 10,358 134,194
--------- --------- --------- -----------
South Texas
AWP Field . . . . . . . . . . . AX 51% 628 3,876 1,274 10,591
Yoakum Gorge Area . . . . . . . Other 18%-53% 47 4,240 754 10,284
Other . . . . . . . . . . . . . AX/Other Varies 242 3,672 854 9,571
--------- --------- --------- -----------
917 11,788 2,882 30,446
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Smackover Trend
Midway Field . . . . . . . . . . AX 63% 1,340 - 1,340 10,769
Buckner Field . . . . . . . . . AX 100% 1,472 - 1,472 9,706
Other . . . . . . . . . . . . . AX/Other Varies 13 228 51 762
--------- --------- --------- -----------
2,825 228 2,863 21,237
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Other
Bradshaw Field . . . . . . . . . AX 95% - 49,822 8,304 44,229
Bowdoin Field . . . . . . . . . Other 22% - 19,343 3,224 27,140
Henderson Canyon Area . . . . . Other 29% 57 10,834 1,863 16,491
Other . . . . . . . . . . . . . AX/Other Varies 6,474 37,911 12,792 111,805
--------- --------- --------- -----------
6,531 117,910 26,183 199,665
--------- --------- --------- -----------
Total . . . . . . . . . . . . 14,384 167,411 42,286 $ 385,542
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GULF OF MEXICO
The Gulf of Mexico is the Company's most significant area of
exploration, development and acquisition activity and represents approximately
60% of the Company's 1997 budgeted exploration and development expenditures.
Approximately 24% of the Company's total proved reserves as of December 31,
1996 were attributable to properties in the Gulf of Mexico. As of December 31,
1996, the Company held working interests in 43 offshore blocks covering
approximately 82,334 gross (21,141 net) developed acres and approximately
82,339 gross (34,102 net) undeveloped acres.
A description of American's major Gulf of Mexico properties follows:
HIGH ISLAND BLOCK 116. High Island Block 116 is located in shallow
federal waters, offshore Texas. The Company acquired a 44% working interest in
the block in the September 1996 Acquisition. In August 1996, the block was
placed on production from the Lower Miocene sands at an approximate depth of
10,000 feet. The producing well has three additional behind pipe intervals
which are classified as proved.
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EAST CAMERON BLOCK 328. East Cameron Block 328 is located in federal
waters, offshore Louisiana. The block is located in approximately 240 feet of
water on the flank of a large salt feature with multiple sands located in
several fault blocks. The Company acquired a 100% working interest in the
block in the September 1996 Acquisition and is the operator of the property.
Initial production on the block was established in the Trim `A' and `S' sands
in the early 1970s, and in 1995, a subsequent operator re-established
production in the Trim `A' sand and discovered oil and gas in the HB-1 sand.
As of December 31, 1996, two wells were completed on the block, one each in the
Trim `A' and HB-1 sands. In 1997, the Company has completed a subsea discovery
in the HB-1 sand and expects to drill up to five wells to develop proved and
probable reserves identified by offset wells or through 3-D seismic.
HIGH ISLAND BLOCK 45. High Island Block 45 is located in shallow
federal waters, offshore Texas. The Company holds a 21% working interest in
the block and is the operator. The block was placed on production in March
1995 from the Lower Miocene sands at an approximate depth of 11,000 feet. The
majority of the gas production from the block is sold under a two-year, fixed
price contract entered into in April 1996 at an average price of approximately
$2.00 per MMbtu.
SOUTH MARSH ISLAND BLOCK 133. South Marsh Island Block 133 is
located in federal waters, offshore Louisiana. The Company acquired its 25%
working interest in the block in the March 1996 Acquisition and is the
operator. The Company drilled a successful development well in the third
quarter of 1996.
BRAZOS COMPLEX. The Brazos Complex consists of the Brazos Blocks
440-L and 446-L and adjoining undeveloped blocks, located in shallow state
waters, offshore Matagorda County, Texas. The Company is the operator of these
blocks and holds an average working interest of 52% in the Brazos Complex,
including a 75% working interest in several undeveloped blocks. In 1995, the
Company increased its leasehold position in the Brazos Complex area and
participated in a 400 square mile 3-D seismic survey. In 1996, the Company
drilled four wells on its Brazos acreage. The Company made two gas discoveries
on Brazos Blocks 478 and 479 during the fourth quarter of 1996 and plans to
install production facilities in 1997. The Company has identified four
additional potential drilling locations on Blocks 478 and 479.
HIGH ISLAND BLOCK 98-L. High Island Block 98-L is located in shallow
federal waters, offshore Texas. The Company holds a 22% working interest in
the block, where a discovery well was drilled in August 1996. The well logged
153 net feet of productive sand in the Lower Miocene formation at an
approximate depth of 10,000 feet and was placed on production in December 1996.
SOUTH TEXAS
Approximately 20% of the Company's 1997 exploration and development
budget is allocated to its South Texas operating area. South Texas represented
approximately 7% of the Company's total proved reserves at December 31, 1996.
A description of American's major South Texas properties follows:
AWP FIELD. The AWP Field is located in McMullen County, Texas and
produces oil and gas from the Olmos sand at an average depth of 9,700 feet.
The Company operates 106 wells with an average working interest of 51%. The
Company drilled a successful development well that came on production in
January 1997. The Company intends to drill three additional wells in 1997.
YOAKUM GORGE AREA. The Yoakum Gorge Area is located in Lavaca
County, Texas and has been the primary focus of the Company's South Texas
activity since early 1995. The Company has participated in two Lower Wilcox
discoveries, one in late 1995 and one in 1996, and ten Frio discoveries. The
Company's primary focus is its 52.5% working interest in the Yoakum Gorge 3-D
project where the Company controls over 55,000 acres and has recently completed
a 152 square-mile proprietary 3-D survey. The initial phase of the 3-D data
has confirmed numerous prospects in the shallow Frio and Yegua formations as
well as the deeper Wilcox formation. During the fourth quarter of 1996, the
Company drilled ten shallow wells, eight of which resulted in Frio, Miocene or
Yegua discoveries. In 1997, the Company intends to drill approximately 40
shallow wells and four Lower Wilcox wells.
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SMACKOVER TREND
American's operations in the Smackover Trend of southwestern Arkansas
are focused primarily in the Midway and Buckner fields, both of which are
operated by the Company. The Company's ongoing strategy in this area is to
capitalize on the horizontal drilling expertise it has developed in exploiting
the Midway Field by applying this technology to other Smackover fields.
Approximately 7% of the Company's total proved reserves as of December 31, 1996
were located in the Smackover Trend, and approximately 10% of the Company's
1997 exploration and development budget is designated for this area.
MIDWAY FIELD. The Midway Field is located in Lafayette County,
Arkansas and produces oil from the Smackover Formation at an average depth of
6,500 feet. The Company became the operator of the field in 1989 and owns an
average 63% net working interest in 68 wells. The field is a mature waterflood
unit that has produced approximately 80 million barrels of oil since 1942, or
approximately 50% of estimated original oil in place. Since assuming
operations, the Company has been able to increase oil recoveries by drilling
horizontal wells in the uppermost section of the productive formation. Based
on the results of its 1995 horizontal drilling program, the Company intends to
re-enter up to 16 existing vertical wells in 1997 and drill horizontal
extensions.
BUCKNER FIELD. The Buckner Field is located approximately 11 miles
southeast of the Midway Field in Lafayette and Columbia Counties, Arkansas. In
1995, the Company acquired a majority of the leases comprising the field and is
the operator of 28 wells that produce oil from the Travis Peak and Smackover
formations at depths of less than 7,500 feet. The Company holds a 100% working
interest in the acquired leases, which represent approximately 75% of the total
field area. The Buckner Field, which is geologically similar to Midway, has
never been unitized or waterflooded and has cumulatively produced approximately
12 million barrels of oil from the Smackover formation, or approximately 20% of
estimated original oil in place. The Company believes that the Buckner Field
has significant additional reserve potential and is currently working to
unitize the field. American plans to initiate a horizontal drilling program
and waterflood project in 1997.
COTTON VALLEY TREND
In December 1996, the Company entered into an exploration joint
venture with Tom Brown, Inc. in the Cotton Valley Pinnacle Reef Trend ("Cotton
Valley"). The Company invested $3.9 million for acreage and 3-D seismic costs
in exchange for a 40% interest in certain acreage under lease or option in the
trend. A 3-D seismic survey covering a portion of the acreage was completed in
January 1997, and the Company expects to commence drilling in mid-1997.
Numerous prospect leads have been identified on the Company's acreage.
The Company also holds a 78% working interest in approximately 640
acres in the Bear Grass Area of Cotton Valley that offset a 1996 discovery by
another operator. The Company has acquired 3-D seismic data over its lease for
this acreage and is evaluating the potential to drill a well in 1997.
OTHER OPERATING AREAS
In addition to the Company's core operating areas, American owns
producing properties and reserves in other areas. The Company seeks to manage
these properties and reserves in a manner which maximizes cash flow available
for reinvestment in the Company's primary areas.
A description of American's significant properties in other areas
follows:
BRADSHAW FIELD. The Bradshaw Field encompasses approximately 250
square miles and is located approximately ten miles northwest of the Hugoton
Field in Hamilton County, Kansas. The field produces gas from the Winfield,
Fort Riley and Towanda sands of the Chase Group at depths ranging from 2,600
feet to 2,900 feet. The Company operates 132 wells with an average net working
interest of 95%. In late 1995, the Company and a subsidiary of KN Energy,
Inc., the gas gatherer in the field, installed additional compression and
pipeline facilities in the field to increase production capacity. During 1996,
the Company completed 11 gross (8.7 net) development wells in the field and
performed workovers on three wells.
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BOWDOIN FIELD. The Bowdoin Field is located in northern Montana in
Phillips and Valley Counties. The structure was discovered in 1913. Gas is
trapped in over 400 feet of closure in sandstones at depths less than 1,500
feet. The Company owns an average net working interest of 22% in approximately
500 active wells. Over 200 proved undeveloped locations have been identified,
and the Company intends to drill in these locations as necessary to maintain
production capacity at current levels.
Gas produced from the Bowdoin Field is sold under a life of lease
contract to KN Gas Supply Services, Inc., a subsidiary of KN Energy, Inc. The
Company realized an average price of $3.52 per Mcf for gas produced from this
field during 1996. This contract is currently the subject of a lawsuit seeking
to reduce the contract price to market levels. Reference is made to Note 14 to
the Consolidated Financial Statements of the Company, set forth in Item 8, for
information regarding such litigation.
HENDERSON CANYON AREA. The Henderson Canyon Area includes the
Henderson Canyon Field and the Angus Strawn Field in Crockett County, Texas.
The Company has a 29% average working interest in 71 wells. Most of the
production is from a single stratigraphically trapped sand body that has a
maximum sand thickness of 160 feet. A total of 11 proved undeveloped locations
have been identified for drilling in 1997.
RESERVES
The tables below set forth certain information concerning the proved
oil and gas reserves owned by the Company at December 31, 1996. The
information contained in the tables is based upon estimates of the proved oil
and gas reserves of the Company and the rates of production therefrom. In
accordance with the method prescribed by the Securities and Exchange
Commission, the estimated future net cash flows before income taxes from proved
reserves were projected on the basis of year-end prices, except in those
instances where fixed and determinable gas price escalations are covered by
contracts. The average realized prices used in the reserve estimates were
$22.95 per Bbl of oil and $3.42 per Mcf of gas at December 31, 1996. The
Company's estimated future net cash flows from proved oil and gas reserves as
of December 31, 1996 were significantly impacted by higher oil and gas prices
at the end of 1996 than in recent years. The prices used in calculating the
estimated future net revenue attributable to proved reserves do not necessarily
reflect market prices for oil and natural gas production subsequent to December
31, 1996. There can be no assurance that the assumed prices will actually be
realized for such production.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
future net cash flows. The quantities of oil and gas that are ultimately
recovered, production and operating costs, the amount and timing of future
development expenditures and future oil and gas sales prices may all differ
from those assumed in these estimates. Reserve assessment is a subjective
process of estimating recovery from underground accumulations of oil and gas
that cannot be measured precisely, and estimates of other persons might differ
from the data presented herein. Accordingly, reserve estimates may differ
significantly from the quantities of oil and gas that are ultimately recovered.
Moreover, the discounted present value shown below should not be construed as
the current market value of the estimated oil and gas reserves attributable to
the Company's properties. A market value determination would take into account
additional factors including, but not limited to, the recovery of reserves not
presently classified as proved, anticipated future changes in prices and costs
and a discount factor more representative of the time value of money and the
risks inherent in reserve estimates.
Although the Company prepares an annual estimate of proved oil and gas
reserves, no estimate of total proved net oil and gas reserves of the Company
has been filed with or included in reports to any federal authority or agency,
other than estimates previously filed with the Securities and Exchange
Commission. The Company is not aware of any major discovery or the occurrence
of any other favorable or adverse event since December 31, 1996 that would
cause material changes in the quantities of proved reserves owned by the
Company as of such date. The information in this section should be read in
conjunction with the Consolidated Financial Statements of the Company,
including the Notes thereto, set forth in Item 8. Reference is made to Note 14
to the Consolidated Financial Statements for information regarding certain
litigation concerning production from the Bowdoin Field.
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The Company's estimated proved oil and gas reserves at December 31,
1996 are as follows:
Oil Gas
Reserves Reserves
(MBbls) (MMcf)
--------- ----------
Proved developed . . . . . . . . . . . . 10,117 142,261
Proved undeveloped . . . . . . . . . . . 4,267 25,150
--------- ----------
Total proved . . . . . . . . . . . . 14,384 167,411
========= ==========
The Company's estimated future net cash flows from proved and proved
developed oil and gas reserves at December 31, 1996, and the discounted present
value of such cash flows (before income taxes) are as follows (in thousands):
Proved
Proved Developed
--------- ----------
1997 (a) . . . . . . . . . . . . . . . . $ 86,821 $ 90,130
1998 . . . . . . . . . . . . . . . . . 80,392 61,472
1999 . . . . . . . . . . . . . . . . . . 82,257 63,217
Remainder . . . . . . . . . . . . . . . 355,995 278,220
--------- ----------
Total future net cash flows . . . . . $ 605,465 $ 493,039
========= ==========
Present value before income . . . . . .
taxes (discounted at 10%) . . . . . $ 385,542 $ 321,835
========= ==========
_______________
(a) For 1997, estimated pre-tax future net cash flows from
proved reserves are projected to be lower than estimated
pre-tax future net cash flows from proved developed
reserves due to estimated capital expenditures associated
with proved undeveloped reserves during 1997 of
approximately $25.3 million that are primarily for new
development wells.
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DRILLING
The following table sets forth the results of drilling activity by the
Company for the last three years.
Year Ended December 31,
--------------------------------------------
1996 1995 1994
---------- ---------- ----------
(a)
Development Wells
-----------------
Gross:
Productive . . . . . . . . . . . . . . . . . . . 48 40 89
Dry Holes . . . . . . . . . . . . . . . . . . . 4 7 6
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . 52 47 95
========== ========== ==========
Net:
Productive . . . . . . . . . . . . . . . . . . . 13.28 17.22 31.52
Dry Holes . . . . . . . . . . . . . . . . . . . 1.16 2.18 1.48
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . 14.44 19.40 33.00
========== ========== ==========
Exploratory Wells
-----------------
Gross:
Productive . . . . . . . . . . . . . . . . . . . 16 - 3
Dry Holes . . . . . . . . . . . . . . . . . . . 16 3 3
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . 32 3 6
========== ========== ==========
Net:
Productive . . . . . . . . . . . . . . . . . . . 7.54 - 0.14
Dry Holes . . . . . . . . . . . . . . . . . . . 7.69 1.93 1.11
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . 15.23 1.93 1.25
========== ========== ==========
_______________
(a) As of December 31, 1996, the Company was also drilling or evaluating
seven (3.86 net) development wells and five (1.88 net) exploratory
wells.
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PRODUCTION
The following table summarizes the average prices received with respect to
oil and gas produced and sold from, the net volumes of oil and gas produced and
sold from and certain additional information relating to, all properties in
which the Company held an interest during the last three years.
Year Ended December 31,
--------------------------------------------
1996 1995 1994
---------- ---------- ----------
Average Sales Price (a):
-----------------------
Gas ($/Mcf) . . . . . . . . . . . . . . . . . . $ 2.03 $ 1.74 $ 1.90
Oil ($/Bbl) . . . . . . . . . . . . . . . . . . 17.21 16.83 15.39
BOE ($/BOE) . . . . . . . . . . . . . . . . . . 13.82 12.30 12.67
Production Data:
---------------
Gas (MMcf) . . . . . . . . . . . . . . . . . . . 22,369 24,450 16,241
Oil (MBbls) . . . . . . . . . . . . . . . . . . 1,789 1,680 1,241
MBOE . . . . . . . . . . . . . . . . . . . . . . 5,517 5,755 3,948
Average Cost Data ($/BOE):
-------------------------
Production and operating costs (b) . . . . . . . $ 4.65 $ 5.12 $ 6.57
Depreciation, depletion and amortization (c) . . 5.36 5.34 7.50
_______________
(a) Prices include the effect of hedging arrangements.
(b) The reduction in production and operating costs per unit in 1996 was
mainly attributable to the impact of the offshore properties acquired
in 1996 that have higher production rates and, therefore, lower
operating costs per unit relative to the Company's onshore properties.
Operating costs in 1994 included $0.62 per BOE related to site
remediation costs incurred in connection with various environmental
proceedings.
(c) The reduction in the depletion rate since 1994 reflects the impact of
a $25 million impairment charge recorded in the fourth quarter of
1994, which reduced the cost basis of certain oil and gas properties,
and the effect of the purchase, in late 1994 and early 1995, of
investors' interests in certain institutional oil and gas partnerships
formed by the Company in the 1980s (the "APPL Consolidation").
PRODUCTIVE WELLS
The following table sets forth information regarding the number of
productive wells in which the Company held a working interest at December 31,
1996. Productive wells are either producing wells or wells capable of
production although currently shut-in. One or more completions in the same
well bore are counted as one well.
Gross Net
--------- ----------
Oil . . . . . . . . . . . . . . . . . 2,017 316
Gas . . . . . . . . . . . . . . . . . 1,559 397
--------- ----------
Total . . . . . . . . . . . . . . 3,576 713
========= ==========
ACREAGE
The following table sets forth the approximate developed and undeveloped
acreage in which the Company held a leasehold, mineral or other interest at
December 31, 1996.
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned by the
Company. The number of net acres is the sum of the fractional interests owned
in gross acres. A net acre is deemed to exist when the sum of the Company's
fractional ownership interests in gross acres equals one. Included in the
following table are 317,288 gross (17,725 net) developed
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mineral acres and 789,566 gross (101,215 net) undeveloped mineral acres, all
located in the United States. A mineral acre is an acre in which the Company
has a perpetual interest, as contrasted to a leased acre in which the Company's
interest is typically limited to the life of production or otherwise limited in
time.
Developed Undeveloped (a)
-------------------------- ----------------------------
Gross Net Gross Net
----------- ----------- ------------ ------------
United States:
Arkansas . . . . . . . . . . 12,143 3,588 26,619 3,188
Kansas . . . . . . . . . . . 157,647 76,487 24,298 6,315
Louisiana . . . . . . . . . 11,269 1,738 1,649 315
Mississippi . . . . . . . . 18,452 4,467 176,277 57,345
Montana . . . . . . . . . . 252,433 40,749 151,074 52,970
New Mexico . . . . . . . . . 13,730 2,631 294,224 73,429
North Dakota . . . . . . . . 18,564 1,862 6,615 582
Oklahoma . . . . . . . . . . 138,367 23,312 112,335 12,423
Texas . . . . . . . . . . . 262,759 34,057 484,784 64,803
Utah . . . . . . . . . . . . 5,002 1,794 21,160 6,112
Wyoming . . . . . . . . . . 712 163 9,858 2,111
Eleven other states . . . . 6,343 2,269 55,984 11,842
Gulf of Mexico . . . . . . . 82,334 21,141 82,339 34,102
----------- ----------- ------------ ------------
Total United States . . . . . . 979,755 214,258 1,447,216 325,537
----------- ----------- ------------ ------------
International:
Canada (b) . . . . . . . . . 22,240 112 149,055 658
New Zealand (b) . . . . . . - - 725,992 32,307
----------- ----------- ------------ ------------
Total International . . . . . . 22,240 112 875,047 32,965
----------- ----------- ------------ ------------
Total . . . . . . . . . . . . . 1,001,995 214,370 2,322,263 358,502
=========== =========== ============ ============
_______________
(a) Excludes 26,199 gross (12,840 net) acres for which the Company holds
lease options.
(b) Acreage relates to overriding royalty interests.
CERTAIN RISK FACTORS
ADDITION AND REPLACEMENT OF RESERVES. The Company intends to utilize
its cash flow from operations and borrowing capacity under the Credit Agreement
to fund the Company's exploration, development and exploitation activities and
property acquisitions. The decision to explore, develop, exploit or purchase a
property will depend in part on the Company's assessment of recoverable
reserves, future oil and natural gas prices and operating costs, potential
environmental and other liabilities and other factors that are beyond the
control of the Company. Such assessments are necessarily inexact and their
accuracy is inherently uncertain. Even if geophysical and geological analyses
and engineering studies, the results of which are often inconclusive or subject
to varying interpretations, indicate high reserve potential of a prospect or
project, there can be no assurance that the Company's exploration, development,
exploitation or acquisition activities will result in additional reserves or
that the Company will be successful in drilling productive wells.
In general, the volume of production from oil and natural gas
properties declines as reserves are depleted. Except to the extent that the
Company conducts successful exploration, development and exploitation
activities or acquires properties containing proved reserves, or both, the
proved reserves of the Company will decline as reserves are produced. As is
generally the case in the Gulf Coast region, many of the Company's producing
properties are characterized by a high initial production rate followed by a
steep decline in production. As a result, the Company's future oil and natural
gas production is highly dependent upon its level of success in finding,
acquiring, developing and exploiting additional reserves.
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OPERATING HAZARDS AND UNINSURED RISKS. The Company's operations are
subject to all of the risks normally incident to the exploration for and the
development and production of oil and gas including blowouts, cratering,
uncontrollable flows of oil, gas or well fluids, fires, pollution and other
environmental risks. These hazards could result in substantial losses to the
Company due to injury or loss of life, severe damage to or destruction of
property and equipment, pollution and other environmental damage and suspension
of operations. In addition, offshore operations are subject to a variety of
operating risks peculiar to the marine environment, such as hurricanes or other
adverse weather conditions, to more extensive governmental regulation and to
interruption or termination of operations by governmental authorities based on
environmental or other considerations. Although the Company is not fully
insured against certain of these risks, it maintains insurance coverage
considered to be customary in the industry. The occurrence of a significant
event against which the Company is not fully insured could have a material
adverse effect on the Company's financial position.
PROGRAM LIABILITY. The Company and certain of its subsidiaries acted
as general partners of a number of limited partnerships. In such capacity, the
Company and such subsidiaries are generally liable for the obligations of the
partnerships to the extent that partnership assets are insufficient to
discharge liabilities.
TITLE TO PROPERTIES
The Company's properties are subject to customary royalty interests,
liens incident to operating agreements, liens for current taxes and other
burdens, including other mineral encumbrances and restrictions. The Company
does not believe that any of these burdens materially interfere with the use of
such properties in the operation of its business. In addition, substantially
all of the properties in which the Company or its subsidiaries own a direct
interest are subject to mortgages granted to secure borrowings under the Credit
Agreement.
A thorough examination of title has been performed with respect to
substantially all of the Company's producing properties, and the Company
believes that it generally holds satisfactory title to such properties. As is
customary in the oil and gas industry, little or no investigation of title is
made at the time of acquisition of undeveloped properties (other than a
preliminary review of local mineral records). Investigations of title are
generally made before commencement of drilling operations and, in most cases,
include the receipt of a title opinion of local counsel.
OIL AND GAS MARKETING AND COMPETITION
The natural gas produced from the Company's properties is generally
sold at the wellhead under contracts which provide for market-sensitive
pricing. The price of natural gas is influenced by many factors including the
state of the economy, weather and competition from other fuels, including oil
and coal. The Company's revenues, cash flows and the value of its gas reserves
are all affected by the level of gas prices.
The crude oil and condensate produced from the Company's properties
are generally sold to other companies at field prices posted by the principal
purchasers of crude oil in the areas where such properties are located. As is
customary in the industry, this production is generally sold pursuant to
short-term contracts.
In the year ended December 31, 1996, sales to Enron Corp. and certain
subsidiaries of KN Energy, Inc. accounted for approximately 26% and 13%,
respectively, of the Company's oil and gas revenues. Because of the
availability of other customers, management does not believe that the loss of
any single customer would adversely affect the Company's operations. Reference
is made to Note 14 to the Consolidated Financial Statements in Item 8 of this
report for information regarding certain litigation with a subsidiary of KN
Energy, Inc.
The oil and gas industry is highly competitive. Major oil and gas
companies, independent producers, drilling and production purchase programs and
individual producers and operators are active competitors for desirable oil and
gas properties. Many competitors have financial resources, staffs and
facilities substantially larger than those of the Company. The availability of
a ready market for the oil and gas production of the Company depends in part on
the cost and availability of alternative fuels, the level of consumer demand,
the extent of other domestic production of oil and gas, the extent of imports
of foreign oil and gas, the cost of and proximity to pipelines and other
transportation facilities, regulations by state and federal authorities and the
cost of complying with applicable environmental regulations.
12
15
REGULATION
The following discussion of the regulation of the oil and gas industry
is necessarily brief and is not intended to constitute a complete discussion of
the various statutes, rules, regulations or governmental orders that affect the
Company or to which operations of the Company may be subject.
FEDERAL REGULATION. Sales of natural gas by the Company are not
regulated and are generally made at market prices. However, the Federal Energy
Regulatory Commission ("FERC") regulates interstate and certain intrastate
natural gas transportation rates and service conditions, which affects the
marketing of natural gas produced by the Company, as well as the revenues
received by the Company for sales of such production. Since the mid-1980's,
FERC has issued a series of orders, culminating in Order Nos. 636, 636-A, 636-B
and 636-C (collectively, "Order 636"), that have significantly altered the
marketing and transportation of gas. Order 636 mandates a fundamental
restructuring of interstate pipeline sales and transportation services,
including the unbundling by interstate pipelines of the sales, transportation,
storage and other components of the city-gate sales services such pipelines
previously performed. Order 636 and subsequent FERC orders issued in
individual pipeline restructuring proceedings have been the subject of appeals,
the results of which have generally been supportive of the FERC's open-access
policy. In 1996, the United States Court of Appeals for the District of
Columbia Circuit largely upheld Order No. 636. Because the FERC continues to
review and revise its open-access regulations, it is difficult to predict the
ultimate impact of the orders on the Company and its gas marketing efforts.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of natural gas and has substantially
increased competition and volatility in natural gas markets. While significant
regulatory uncertainty remains, Order 636 may ultimately enhance the Company's
ability to market and transport its gas, although it may also subject the
Company to greater competition.
Sales of oil and natural gas liquids by the Company are not regulated
and are made at the wellhead at market prices. The price the Company receives
from the sale of these products is affected by the cost of transporting the
products to market. Effective as of January 1, 1995, FERC implemented
regulations establishing an indexing system for transportation rates for
interstate common carrier oil pipelines, which, generally, would index such
rates to inflation, subject to certain conditions and limitations. These
regulations could increase the cost of transporting oil and natural gas liquids
by interstate pipeline, although the most recent adjustment generally decreased
rates. These regulations have generally been approved on judicial review. The
Company is not able to predict with certainty what effect, if any, these
regulations will have on its business, but, other factors being equal, the
regulations may, over time, tend to increase transportation costs or reduce
wellhead prices for oil and natural liquids.
REGULATION OF DRILLING AND PRODUCTION. Exploration and production
operations of the Company are subject to various types of regulation at the
federal, state and local levels. Such regulation includes requiring drilling
permits, requiring the maintenance of bonds in order to drill or operate wells,
and regulating the location of wells, the method of drilling and casing wells,
the surface use and restoration of properties upon which wells are drilled and
the plugging and abandoning of wells. The operations of the Company are also
subject to various conservation regulations, including regulation of the size
of drilling and spacing units or proration units, the density of wells that may
be drilled and the unitization or pooling of oil and gas properties. In this
regard, some states, including states in which the Company operates, allow the
forced pooling or integration of lands and leases. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain
requirements regarding the ratability of production. The general effect of
these regulations is to limit the amount of crude oil and natural gas the
Company can produce from its wells and the number of wells or the locations at
which the Company can drill.
FUTURE LEGISLATION AND REGULATION. The Company's business is and will
continue to be affected from time to time in varying degrees by political
developments and federal, state and local laws and regulations. The Company is
not able to predict the terms of any future legislation or regulations that
might ultimately be enacted or the effects of any such legislation or
regulations on the Company.
ROYALTY MATTERS
By a letter in May 1993 directed to thousands of producers holding
interests in federal leases, the United States Department of the Interior (the
"Department") announced its interpretation of certain administrative
regulations to require the payment of royalties on natural gas contract
settlements to resolve, among other things, take-or-pay and minimum take
13
16
claims by producers against pipelines and other buyers. The Department's
letter set forth various theories of liability, all founded on the Department's
interpretation of the term "gross proceeds" as used in federal leases and
pertinent federal regulations. In an effort to ascertain the amount of such
potential royalties, the Department sent a letter to producers in 1993
requiring producers to provide data on natural gas contract settlements where
gas produced from federal or Indian leases was involved in the settlement. The
Company received a copy of this information demand letter and responded
appropriately in May 1994. To date, the Company has received one order to pay
additional royalties based on the information supplied to the Department.
In response to the Department's action, various industry associations,
including the Independent Petroleum Association of America, and others filed
suit seeking an injunction to prevent the collection of royalties on natural
gas contract settlement amounts under the Department's theories. At the
federal district court level, the court ruled in favor of the government's
position. However, on appeal to the United States Court of Appeals for the
District of Columbia Circuit, the federal appellate court in August 1996
overturned the lower court's opinion and held that the government's position
was contrary to certain prior court precedents and inconsistent with the
government's prior position in response to those precedents. In October 1996,
the Department filed a Petition for Rehearing and Suggestion for Rehearing in
Banc with the federal appellate court, which was denied on November 21, 1996.
The Department did not exercise its right to petition the United States Supreme
Court for further review of the case, and the appellate court's ruling is now
final. Notwithstanding the recent outcome that was favorable to the industry,
one other case raising similar issues is now pending before another Federal
appellate court, and the Company cannot predict what further action may be
taken by the courts or the Department or what effect, if any, the Department's
claims will have on the Company. Furthermore, even if the Department's claims
are vindicated by further appellate decisions, certain of the Company's natural
gas contract settlements may provide for the buyer to reimburse the Company for
any excess or additional payments to royalty owners required as a result of the
Company's receipt of the settlement amounts.
ENVIRONMENTAL MATTERS
The Company and its operations are subject to a number of federal,
state and local laws and regulations governing the discharge of materials into
the environment or otherwise relating to the protection of the environment. In
general, the Company believes it has acted as a prudent operator and is in
substantial compliance with environmental laws and regulations. The Company
has incurred and will continue to incur costs in its efforts to comply with
these environmental standards. Although the costs incurred by American to date
solely to comply with environmental laws and regulations have not had a
material adverse effect upon capital expenditures, earnings or the competitive
position of the Company, the trend toward stricter environmental laws and
regulations is expected to have an increasingly significant impact on the
conduct of American's business. The cost to comply with evolving regulations
and the related future impact on American's business cannot be predicted at
this time because of the uncertainties regarding future environmental
standards, advances in technology, the timing for expending funds and the
availability of insurance and third-party indemnification. However, American
believes that the evolving environmental standards do not affect the Company in
a materially different manner from other similarly situated companies in the
oil and gas industry.
Environmental regulations can increase the cost of planning,
designing, installing and operating oil and gas facilities. In most instances,
the regulatory requirements impose water and air pollution control measures.
Although the Company believes that compliance with environmental regulations
will not have a material adverse effect on the Company, the risks of
substantial costs and liabilities related to environmental compliance issues
are inherent in oil and gas production operations, and no assurance can be
given that significant costs and liabilities will not be incurred. Moreover,
it is possible that other developments, such as stricter environmental laws and
regulations, and claims for damages to property or persons resulting from oil
and gas production would result in substantial costs and liabilities to the
Company.
SOLID AND HAZARDOUS WASTE. The Company currently owns or leases, and
has in the past owned or leased, numerous properties that have been used for
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other solid wastes may have been disposed or released on
or under the properties owned or leased by the Company. In addition, many of
the properties have been operated by third parties. The Company had no control
over such parties' treatment of hydrocarbons or other solid wastes and the
manner in which such substances may have been disposed or released. State and
federal laws applicable to oil and gas wastes and properties have become
stricter over time. Under these new laws, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed or
released by prior owners or
14
17
other operators) or property contamination (including groundwater contamination
by prior owners or other operators) or to perform remedial plugging operations
to prevent future contamination.
The Company generates some wastes that are subject to the Federal
Resources Conservation and Recovery Act ("RCRA") and comparable State statutes.
The Environmental Protection Agency ("EPA") has limited the disposal options
for certain "hazardous wastes". Furthermore, it is possible that certain
wastes currently exempt from treatment as hazardous wastes may in the future be
designated as hazardous wastes under RCRA or other applicable statutes, and
therefore be subject to more rigorous and costly disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation,
and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the owner and operator
of a site and any party that disposed or arranged for the disposal of the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in
some cases, third parties, to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible parties
the costs of such actions. In the course of the Company's operations, the
Company has generated and will generate wastes that may fall within CERCLA's
definition of hazardous substances. The Company may also be an owner of sites
on which "hazardous substances" have been released. Therefore, the Company may
be responsible under CERCLA for all or part of the costs to clean up sites at
which such wastes have been disposed. As of February 28, 1997, neither the
Company nor its predecessors has been designated as a potentially responsible
party under CERCLA with respect to any such site.
OIL POLLUTION ACT. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose a variety of regulations on "responsible parties"
related to the prevention of oil spills and liability for damages resulting
from such spills in "waters of the United States". The term "waters of the
United States" has been broadly defined to include inland water bodies,
including wetlands and intermittent streams. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages.
AIR EMISSIONS. The operations of the Company are subject to local,
state and federal laws and regulations for the control of emissions from
sources of air pollution. Administrative enforcement actions for failure to
comply strictly with air regulations or permits are generally resolved by
payment of monetary fines and correction of any identified deficiencies.
Alternatively, regulatory agencies could require the Company to cease
construction or operation of certain air emission sources.
Although the Company believes that its operations are in compliance
with applicable environmental regulations, risks of substantial costs and
liabilities are inherent in the operations of companies in the oil and gas
industry, and there can be no assurance that such costs and liabilities will
not be incurred. Moreover, there can be no assurance that future laws and
regulations, including environmental laws and regulations, will not adversely
affect the Company's operations and financial condition.
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EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below is certain information regarding the executive
officers of the Company.
Name Office Age
------------------------- ------------------------------------------------- ----
Mark Andrews Chairman of the Board and 46
Chief Executive Officer
John M. Hogan Senior Vice President and Chief Financial Officer 52
Elliott Pew Senior Vice President - Exploration 42
Cindy L. Gerow Vice President and Controller 32
Harry C. Harper Vice President - Land 58
Robert R. McBride, Jr. Vice President - Gulf of Mexico Region and 41
Chief Engineer
T. Frank Murphy Vice President - Corporate Finance and Secretary 42
MARK ANDREWS, CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE OFFICER,
founded the Company in 1980. Mr. Andrews is also a director of IVAX
Corporation.
JOHN M. HOGAN, SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER, who
had previously served as Senior Vice President -Finance of the Company during
1985 and 1986, rejoined the Company in August 1992. From 1987 until 1992, Mr.
Hogan owned an accounting firm that provided tax, accounting, and management
services.
ELLIOTT PEW, SENIOR VICE PRESIDENT - EXPLORATION, joined the Company
in October 1992 as a senior geophysicist. He was appointed Vice President -
Exploration in July 1993 and was appointed to his current position in March
1997. From 1989 to 1992, he was employed by FINA, Inc. as a division geologist
and then as Exploration Manager - South Texas Division.
CINDY L. GEROW, VICE PRESIDENT AND CONTROLLER, joined the Company in
October 1990. She served in a number of managerial positions with
responsibility for various accounting and finance functions. She was appointed
Controller of the Company in April 1994 and was appointed to her current
position in August 1995.
HARRY C. HARPER, VICE PRESIDENT - LAND, joined the Company in 1990
when American acquired Hershey Oil Corporation. Prior to that time, he had
been Senior Vice President, Secretary and General Counsel of Hershey since
1973.
ROBERT R. MCBRIDE, JR., VICE PRESIDENT - GULF OF MEXICO REGION AND
CHIEF ENGINEER, joined the Company as Vice President - Production Operations in
August 1992. He was appointed to his current position in February 1997. From
1988 to 1992, he served in various capacities with British Gas plc, most
recently as Exploitation Manager.
T. FRANK MURPHY, VICE PRESIDENT - CORPORATE FINANCE AND SECRETARY,
joined the Company in 1989. He served in a variety of financial positions
until December 1991 when he was appointed Vice President - Investor Relations.
He was appointed Vice President - Corporate Finance in March 1993 and was
appointed Secretary in October 1993.
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ITEM 3. LEGAL PROCEEDINGS
Information regarding legal proceedings of the Company is set forth in
Note 14 to the Consolidated Financial Statements in Item 8, which information
is incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock trades on the American Stock Exchange under
the symbol "AX". At February 28, 1997, the Company had 4,299 stockholders of
record.
The following table sets forth the high and low sales prices for the
Company's common stock for the quarters indicated. Prices stated below have
been retroactively restated to reflect the one-for-ten reverse split of the
Company's common stock effected during the second quarter of 1995.
PRICE RANGE OF COMMON STOCK
High Low
----------- -----------
Year Ended December 31, 1995
----------------------------
First Quarter . . . . . . . . . . . . . . $ 10 $ 8 3/4
Second Quarter . . . . . . . . . . . . . . 10 7/8 8 1/8
Third Quarter . . . . . . . . . . . . . . 12 1/8 10 3/8
Fourth Quarter . . . . . . . . . . . . . . 11 7/8 9 5/8
Year Ended December 31, 1996
----------------------------
First Quarter . . . . . . . . . . . . . . $ 12 $ 10 5/8
Second Quarter . . . . . . . . . . . . . . 13 1/2 10 5/8
Third Quarter . . . . . . . . . . . . . . 14 11 7/8
Fourth Quarter . . . . . . . . . . . . . . 16 5/8 11 7/8
The Company has not paid any dividends on its common stock and does
not expect to pay dividends on its common stock for the foreseeable future.
Payment of dividends on the Company's common stock is also currently prohibited
by the terms of various agreements relating to outstanding indebtedness of the
Company.
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ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data for the Company
as of and for each of the years in the five-year period ended December 31,
1996. The financial data was derived from the consolidated financial
statements of the Company and should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations and
the Consolidated Financial Statements and related Notes thereto included in
Item 7 and Item 8, respectively.
American has made several significant acquisitions and dispositions of
oil and gas properties during the periods presented in the table below.
American sold approximately 40% of its interest in the Henderson Canyon Field
in March 1993, sold its Canadian assets in mid-1993 and sold its interest in
the Sawyer Field in July 1995. The Company purchased investors' interests in
the APPL Programs in 1994 and early 1995. Also see "Items 1 and 2 - Business
and Properties - Significant Events in 1996".
Net income (loss) per common share for prior periods has been
retroactively restated to reflect the one-for-ten reverse split of the
Company's common stock effected in June 1995.
Year Ended December 31,
-------------------------------------------------------------
(In thousands, except for per share amounts) 1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
SUMMARY OF OPERATIONS DATA:
Oil and gas sales . . . . . . . . . . . . . . $ 76,228 $ 70,768 $ 50,033 $ 49,589 $ 58,560
Total revenues . . . . . . . . . . . . . . . 77,487 81,967 51,359 58,158 60,008
Income (loss) from operations . . . . . . . . (3,796) 6,846 (51,433) (12,018) (59,679)
Income (loss) before extraordinary item . . . (8,605) 1,477 (60,235) (19,186) (68,899)
Net income (loss) . . . . . . . . . . . . . . (8,605) 3,933 (54,816) (19,186) (65,799)
Net income (loss) per common share:
Primary and fully diluted:
Loss before extraordinary item . . . . . $ (.84) $ (.03) $ (7.70) $ (2.77) $ (10.73)
Net income (loss) . . . . . . . . . . . . (.84) .18 (7.02) (2.77) (10.25)
Cash dividends declared per common share . . - - - - -
SUMMARY OF CASH FLOW DATA:
Cash flow from operations before working
capital changes . . . . . . . . . . . . . $ 39,163 $ 29,314 $ 6,638 $ 26,888 $ 13,136
Net cash provided by operating activities . . 35,371 33,305 7,747 24,717 14,237
December 31,
-------------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
SUMMARY OF BALANCE SHEET DATA:
Property, plant and equipment, net . . . . . . $ 210,539 $ 150,417 $ 195,405 $ 160,885 $ 201,915
Total assets . . . . . . . . . . . . . . . . . 240,628 176,030 223,894 185,598 256,820
Long-term obligations, excluding current obligations 60,000 40,000 100,710 62,848 115,256
Total stockholders' equity . . . . . . . . . . 130,379 94,480 87,710 86,406 85,160
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
The Company accounts for its oil and gas exploration and production
activities using the successful efforts method of accounting. Under this
method, acquisition costs for proved and unproved properties are capitalized
when incurred. Exploration costs other than drilling costs for successful
wells, including geological and geophysical costs and costs of carrying and
retaining unproved properties, are charged to expense as incurred. The costs
of drilling exploratory wells are capitalized pending determination of whether
each well resulted in the discovery of proved reserves. If proved reserves are
not discovered, such drilling costs are charged to expense. Costs incurred to
drill and equip development wells, including unsuccessful development wells,
are capitalized. Internal costs related to the acquisition, development and
exploration of oil and gas properties are expensed as incurred. Interest is
capitalized on qualifying assets, primarily unproved and unevaluated
properties. The Company anticipates that results of operations will continue
to be significantly impacted by the level of exploration expenditures and the
costs of drilling dry exploratory wells that are expensed under the successful
efforts method of accounting.
Depletion of the cost of producing oil and gas properties is computed
on the unit-of-production method. The Company also accrues for platform
abandonment costs related to its offshore platform facilities on the unit-of-
production method. Unproved properties are assessed periodically, and any
impairment in value is recognized currently as impairment expense. As of
December 31, 1996, the Company owned unproved oil and gas properties with a
book value of approximately $33 million. The Company plans to commence
drilling on its most significant prospects in 1997; however, if such drilling
activity does not result in the discovery of proved oil and gas reserves on a
particular property, an impairment charge would be recorded to write off the
value of that property.
RESULTS OF OPERATIONS
1996 COMPARED TO 1995
REVENUES. The Company recorded oil and gas sales totaling $76.2
million in 1996 compared to 1995 sales of $70.8 million. Higher sales revenues
primarily reflected a 17% increase in the Company's average realized gas price
in 1996. The oil and gas industry enjoyed strong commodity prices for most of
1996, although the benefit of higher prices on the Company's revenues was
mitigated by the impact of certain price hedging arrangements in effect during
the year.
The Company's 1996 revenues were favorably impacted by approximately
$7.2 million due to the effect of higher oil and gas prices compared to the
prior year. The Company's gas price averaged $2.03 per Mcf in 1996 compared to
$1.74 per Mcf in 1995, while the average oil price realized rose slightly to
$17.21 per Bbl in 1996 from $16.83 per Bbl a year earlier. During 1996, the
Company had in effect certain commodity price hedging agreements that covered,
on average throughout the year, approximately 47% of its gas production and
approximately 68% of its oil production. As a result of the price hedges, the
Company's oil and gas sales revenues were reduced by approximately $10 million
during 1996 and were increased by approximately $1.5 million during 1995.
Excluding the impact of the hedging arrangements, the Company's average oil and
gas prices for 1996 would have been $20.31 per Bbl and $2.23 per Mcf,
respectively. For 1995, the Company's average prices exclusive of the hedges
would have been $16.79 per Bbl and $1.68 per Mcf.
Oil production increased to 1.8 MMBOE during 1996 reflecting a 6%
increase in the Company's average daily production rate. Production increases
in 1996 were primarily attributable to properties acquired in the Offshore
Acquisitions, which added approximately 200,000 Bbls of oil production in 1996.
The impact of additional volumes from the new properties was partially offset
by the effect of the sales of several oil producing properties in late 1995 and
early 1996. Increased oil production contributed approximately $1.8 million to
1996 revenues.
Gas production in 1996 declined to 22.4 Bcf or approximately 9% below
prior year volumes of 24.5 Bcf. Production declines in 1996 aggregating 6.5
Bcf due to the sale of the Sawyer Field in July 1995 (the "Sawyer Sale") and
production declines in the West McAllen Field were offset by an additional 3.4
Bcf of gas production from the properties acquired in the Offshore
Acquisitions, an increase of 1.1 Bcf resulting from the installation of
additional compression and pipeline facilities at the Bradshaw Field, and an
increase of 0.7 Bcf from the completion of a well at High Island Block 13-L.
The reduction in gas volumes negatively impacted sales by approximately $3.6
million in 1996.
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The Company recognized a net gain of $978,000 on the sales of various
properties during 1996. In 1995, the Company reported a net gain on property
sales, mainly the Sawyer Sale, of approximately $10.2 million. Other revenues
totaling $281,000 in 1996 primarily represented the proceeds from the sales of
seismic data. In 1995, other revenues of $969,000 related to a certain gas
contract settlement and gas balancing income offset by the accrual of a loss
under certain swap agreements then in effect. See "1995 Compared to 1994"
below.
COSTS AND EXPENSES. Production and operating costs totaled $25.7
million, or $4.65 per BOE, in 1996 compared to $29.4 million, or $5.12 per BOE,
in 1995. The decrease in total costs was primarily attributable to the
reduction of approximately $3.4 million related to the Sawyer Field, while the
decline in the Company's operating costs per unit of production was mainly
attributable to the impact of the offshore properties acquired in 1996. Such
properties generally have higher production rates and, therefore, lower
operating costs per unit than the Company's onshore properties.
Depreciation, depletion and amortization ("DD&A") totaled $29.6
million and $30.7 million for 1996 and 1995, respectively. The decline in DD&A
expense was mainly attributable to lower gas production in 1996. The Company's
average DD&A rate was essentially unchanged during 1996 despite generally
higher depletion rates for the offshore properties acquired in 1996, which
rates reflect a provision for platform abandonment costs. As prescribed by
applicable accounting standards, no depreciation or depletion expense was
recorded during the last half of 1996 for certain assets that had been
reclassified to assets held for sale at the end of the second quarter. Those
assets were sold during the fourth quarter of 1996.
General and administrative ("G&A") expense totaling $7.2 million was
13% below the prior year expense of $8.3 million. The decline in G&A expense
was mainly attributable to reduced legal fees in 1996. G&A expense per unit of
production averaged $1.31 per BOE in 1996 compared to $1.44 per BOE in 1995.
Exploration expense totaled $18.8 million in 1996 and $6.6 million in
1995. The Company drilled 32 exploratory wells in 1996, with a 50% success
rate, compared to only three wells in 1995, all of which were unsuccessful.
Accordingly, the Company recorded dry hole expense of $11.4 million in 1996
compared to $4.1 million for the prior year. In addition, 1996 exploration
expense included $5.1 million of geological and geophysical expense primarily
reflecting the costs of 3-D seismic data covering certain areas in the Texas
State Waters and South Texas. Impairment expense for unproved properties upon
which no further exploration activity will be conducted totaled $2.1 million
and $1.8 million in 1996 and 1995, respectively.
Interest expense of $4.2 million in 1996 declined 23% from the prior
year. Interest expense in 1995 reflected higher bank debt carried in the first
half of 1995 following the completion of the APPL Consolidation. The income
tax provision for 1996 primarily represented deferred state income tax expense.
EXTRAORDINARY ITEM. The $2.5 million extraordinary gain recorded in
1995 resulted from the extinguishment of nonrecourse debt in conjunction with
the APPL Consolidation.
NET INCOME (LOSS). The Company reported a net loss of $8.6 million,
or $0.84 per share, in 1996 and net income of $3.9 million, or $0.18 per share,
in 1995. The 1996 loss was mainly attributable to dry hole and seismic data
acquisition costs totaling $16.5 million. Under the successful efforts method
of accounting, costs of unsuccessful exploratory wells and seismic data
expenditures are expensed as incurred. Net income in 1995 reflected the impact
of numerous nonrecurring transactions, most notably a $10.2 million gain on
property sales, primarily the Sawyer Sale, and a $2.5 million extraordinary
gain on debt extinguishment.
1995 COMPARED TO 1994
REVENUES. Oil and gas sales totaled $70.8 million in 1995 or 41%
higher than 1994 sales of $50 million. The increase in 1995 sales revenues
primarily reflected higher production volumes that resulted from the
acquisition of investors' interests in the APPL Programs. Through the APPL
Consolidation, the Company acquired 22.9 MMBOE and 2.3 MMBOE of proved oil and
gas reserves in late 1994 and early 1995, respectively. The APPL
Consolidation, together with successful development activity at the Midway and
West McAllen fields and the West Cameron Block 408, resulted in a net
production increase of 1.8 MMBOE in 1995 compared to 1994. The higher
production levels achieved through the APPL Consolidation were partially offset
by the loss of production due to the Sawyer Sale. The Company's total oil
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and gas production increased to 5.8 MMBOE in 1995 from 3.9 MMBOE in 1994,
contributing $22.3 million to oil and gas sales.
Oil and gas sales reflected the impact of lower gas prices offset by
higher oil prices received in 1995. The Company realized an average price of
$16.83 per Bbl in 1995 compared to $15.39 in 1994, which resulted in a $2.4
million addition to sales revenues. The Company's average gas price
realization declined to $1.74 per Mcf in 1995, or 8% below the prior year
average. The decline in the average gas price negatively impacted sales
revenues by $3.9 million. During 1995 and 1994, the Company had periodically
entered into certain price hedging arrangements, primarily related to a portion
of its natural gas production. The Company realized a $1.5 million gain on its
hedging activities in both 1995 and 1994, which gains were reflected in the oil
and gas sales revenues of each year. Excluding the impact of the hedging
gains, the Company's average price per Mcf of gas would have been $1.68 and
$1.81 in 1995 and 1994, respectively. Oil prices were not significantly
affected by price hedging agreements in either year.
In July 1995, the Company sold its interest in the Sawyer Field to
Louis Dreyfus Natural Gas Corp. for a purchase price of $64 million. American
recorded a gain on the Sawyer Sale of approximately $10.6 million in 1995.
Sales of various other fields in 1995 resulted in a net loss of approximately
$400,000. In 1994, the Company recognized a $1.1 million gain on the
divestiture of minor properties.
Other revenues totaled $969,000 and $216,000 in 1995 and 1994,
respectively. In 1995, the Company recorded gas settlement income of $895,000,
primarily consisting of the proceeds from certain litigation regarding the
terms of a gas purchase contract. American also recognized approximately
$480,000 of gas balancing income during 1995, primarily relating to cash
balancing settlements receivable on various wells that were plugged and
abandoned during 1995. During December 1995, the Company accrued $700,000 as a
reduction of other revenues due to the loss of correlation between actual cash
prices and the prices under the swap agreements at the Henry Hub market
reference price. Other revenues recorded in 1994 primarily included gas
balancing income.
COSTS AND EXPENSES. Production and operating costs increased to $29.4
million in 1995 from $25.9 million in 1994. The increase in 1995 costs was
mainly attributable to higher production levels resulting from the APPL
Consolidation, although that increase was mitigated by a reduction in
environmental expenses in 1995. During 1994, the Company incurred $2.4 million
of site remediation costs in connection with various environmental proceedings.
On a unit cost basis, production and operating costs per BOE decreased to $5.12
per BOE in 1995 from $6.57 per BOE in 1994 reflecting continued operating
efficiencies achieved following the completion of the APPL Consolidation.
DD&A totaled $30.7 million in 1995 or 4% over 1994 DD&A of $29.6
million. The Company's DD&A per BOE rate decreased substantially in 1995;
consequently, American's DD&A expense did not increase proportionately with the
46% production increase in 1995. DD&A per BOE decreased to $5.34 per BOE in
1995 from $7.50 per BOE in 1994. The lower DD&A rate reflected the effect of
the acquisition of interests through the APPL Consolidation and the impact of a
$25 million impairment charge recorded in the fourth quarter of 1994, which
reduced the cost basis of certain oil and gas properties.
G&A expense declined to $8.3 million in 1995 from $11.1 million a year
earlier. The reduction in G&A expense resulted primarily from staff reductions
in the first half of 1994 and a $2 million severance charge recorded in late
1994 in connection with the elimination of certain partnerships managed by
American. These decreases were partially offset by the loss of management and
technical fee reimbursements previously received from the APPL Programs. The
Company's continuing focus on controlling administrative costs resulted in a
49% reduction in G&A expense per unit of production, which averaged $1.44 per
BOE in 1995 compared to $2.82 per BOE in 1994.
Exploration expense totaled $6.6 million and $11.1 million in 1995 and
1994, respectively. American recognized $4.1 million of dry hole expense on
three wells in 1995, including two offshore wells, and recorded $1.8 million of
impairment expense in 1995 related primarily to the fourth quarter write-off of
an unproved offshore property. In 1994, the Company recorded $1.5 million of
dry hole expense related to three unsuccessful wells and $8.6 million of
impairment expense, including a $6.4 million charge to write off American's
remaining leasehold interest in Tunisia. The Company also recorded a $25
million impairment charge in 1994 related to a change in accounting policy.
Interest expense of $5.5 million in 1995 was 17% below 1994 expense of
$6.6 million primarily due to the repayment of $62.5 million of bank debt using
the proceeds of the Sawyer Sale in July 1995. In addition, American
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extinguished certain nonrecourse debt associated with the APPL Programs
totaling $6.6 million and $13.6 million in 1995 and 1994, respectively. Other
expense of $2.6 million in 1994 included $2.1 million of fees paid by American
in connection with a new bank credit agreement and a bridge facility with New
York Life.
EXTRAORDINARY ITEM. American recorded extraordinary gains of $2.5
million in 1995 and $5.4 million in 1994 related to the elimination of
nonrecourse debt in conjunction with the APPL Consolidation. The gain
represented the difference between the outstanding note balances and the actual
purchase price of the notes.
NET INCOME (LOSS). American reported net income of $3.9 million, or
$0.18 per share, in 1995 and a net loss of $54.8 million, or $7.02 per share,
in 1994. Nonrecurring transactions reflected in 1995 net income included a
$10.2 million gain on property sales, primarily the Sawyer Sale, a $2.5 million
extraordinary gain on the extinguishment of debt and $895,000 of gas settlement
income, partially negated by a $1.8 million impairment charge and a $700,000
loss related to certain natural gas hedges. In contrast, 1994 results included
the negative impact of a $33.6 million impairment charge partially offset by a
$5.4 million extraordinary gain and a $1.1 million gain on property sales.
Excluding the effect of these nonrecurring transactions in both years, the
Company would have recorded net losses of $7.2 million and $27.7 million in
1995 and 1994, respectively. The improvement in operating results primarily
reflected a $17.5 million increase in net operating revenues, which resulted
from higher production levels and reduced unit operating costs following the
APPL Consolidation. In addition, reductions in G&A and interest expense in
1995 more than offset higher DD&A and exploration expense recorded in that
year.
CAPITAL RESOURCES AND LIQUIDITY
American's principal sources of capital are net cash provided by
operating activities and proceeds from financing activities. During the last
two years, the Company has also generated substantial cash flows from the sale
of oil and gas properties, most notably the Sawyer Sale in 1995. American's
primary capital requirements are to fund the Company's development and
exploration programs and acquisition activity. American also has financial
obligations related to the Company's convertible preferred stock and its 11%
senior subordinated notes (the "Subordinated Notes").
Net cash provided by operating activities totaled $35.4 million in
1996, $33.3 million in 1995 and $7.7 million in 1994. Cash flow for 1996
reflected improved operating margins due to strong oil and gas prices and the
impact of lower operating costs for the Company's offshore properties, which
represented a greater portion of the property base in 1996. Net cash provided
by operating activities was reduced in 1996 by the effect of a $4.1 million
negative working capital change due to a higher accounts receivable balance at
year-end 1996. In contrast, net cash provided by operating activities in 1995
reflected a $5.8 million positive working capital adjustment due to an increase
in the accounts payable balance at year-end 1995. Excluding the impact of
working capital adjustments, the Company's cash flow from operations increased
by approximately $10 million from 1995 to 1996. The improvement in operating
cash flows in 1995 compared to 1994 reflected the impact of the APPL
Consolidation and successful development activity, which together resulted in a
46% increase in 1995 production relative to 1994. In addition, the Company's
operating margins increased in 1995 as unit costs for production, G&A and
interest expense decreased in 1995 as compared to 1994.
As of December 31, 1996, the borrowing base under the Credit Agreement
was $75 million, and outstanding bank debt totaled $25 million, all of which
was classified as long-term. The borrowing base is scheduled to be
redetermined semiannually every March and September. The March 1997
redetermination is expected to be completed early in the second quarter of
1997.
The Credit Agreement and the Subordinated Notes require the Company to
comply with certain covenants including, but not limited to, restrictions on
indebtedness, investments, payment of dividends and lease commitments and a
requirement to maintain a minimum net worth of $88.5 million. Cash dividends
are restricted on the Company's common stock, and annual preferred dividends
are limited to 10% of the proceeds from the sale of preferred stock that may be
outstanding from time to time, not to exceed $7.5 million. The current annual
limit on preferred dividends is $2 million. In addition, these agreements
contain cross-default provisions. The Company was in compliance with these
covenants at year end 1996.
In November 1996, the Company closed the sale of approximately 3.9
million shares of common stock in a public offering that generated net proceeds
to the Company of approximately $46 million. Proceeds from the stock offering
were used to reduce outstanding bank debt.
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Proceeds from the sales of oil and gas properties totaled
approximately $16.9 million, $63.5 million and $2.6 million in 1996, 1995 and
1994, respectively. In December 1996, the Company received approximately $10.1
million, subject to post-closing adjustments, from the divestiture of certain
properties in connection with the NYLOG Liquidation. Also in 1996, the Company
sold, for approximately $5.8 million, a 10% interest in High Island Block 116,
which American had purchased in the September 1996 Acquisition. Property sales
in 1995 primarily included the Sawyer Sale for gross proceeds of $64 million.
The Sawyer Sale proceeds were applied to substantially reduce the Company's
outstanding bank debt, which had increased as a result of the APPL
Consolidation. Divestitures in 1994 were comprised of non-strategic, low-value
properties.
Cash expenditures for the acquisition of oil and gas properties
totaled approximately $74 million in 1996, $16 million in 1995 and $28 million
in 1994. Acquisition expenditures in 1996 included approximately $14 million
for the March 1996 Acquisition, $45 million for the September 1996 Acquisition
and approximately $7.7 million for the Ancon Acquisition. The remainder of the
1996 acquisition expenditures primarily related to the purchase of leasehold
interests including acreage in the Cotton Valley area of East Texas and in the
Yoakum Gorge area of South Texas. In 1995, the Company expended approximately
$9 million related to the APPL Consolidation and $2.4 million for certain
interests in the Buckner Field in Arkansas and also purchased several offshore
blocks in the Gulf of Mexico. Property acquisitions in 1994 mainly related to
the APPL Consolidation.
Cash expenditures for development totaled approximately $15.6 million,
$23.3 million and $15.3 million in 1996, 1995 and 1994, respectively. American
participated in drilling 52 development wells (14 net) in 1996, of which 48 (13
net) were successfully completed. Development activity in 1996 was focused in
the Company's offshore operating area including High Island Block 98-L, the
Brazos Complex and the properties acquired in the Offshore Acquisitions. The
Company also completed eleven (8.7 net) wells at the Bradshaw Field in Kansas.
Cash expenditures for exploration activities totaled approximately
$26.1 million in 1996 compared to approximately $4.2 million and $5.6 million
in 1995 and 1994, respectively. The Company participated in 32 exploratory
wells (15 net) in 1996 with a 50% success rate. Exploration efforts were
concentrated in the Gulf of Mexico and in the Wilcox and Frio trends of South
Texas. There can be no assurances regarding the success of any wells drilled,
and exploratory wells involve greater risks than development wells. Under
successful efforts accounting, the costs incurred for the drilling of
unsuccessful exploratory wells and for the acquisition of seismic data are
recorded as exploration expense and negatively impact net income in the period
in which incurred.
The Company expects its 1997 capital expenditures for development and
exploration activities to total approximately $80 million. The actual amount
of such expenditures will depend on various factors, including, among other
factors, oil and gas prices, the level of exploration success and subsequent
development activity. The Company intends to fund its planned capital
expenditures, commitments and working capital requirements through cash flows
from operations and borrowings under the Credit Agreement. However, if there
are changes in oil and gas prices, which correspondingly affect cash flows and
bank borrowings, or if additional development and exploration opportunities
arise, the Company may adjust its capital budget accordingly. Other potential
sources of capital for the Company include property sales and financings
through the issuance of debt or equity securities. Management believes that
the Company will have sufficient capital resources and liquidity to fund its
capital expenditures and meet its financial obligations as they are due.
The Company is subject to various federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to the protection of the environment, which laws and
regulations have become increasingly stringent. The Company has conducted a
review of its operations with particular attention to environmental compliance.
The Company believes it has acted as a prudent operator and is in substantial
compliance with environmental laws and regulations. The Company has recorded
site remediation costs of $494,000, $541,000 and $2.4 million in 1996, 1995 and
1994, respectively. The site remediation costs incurred in 1994 primarily
related to certain lawsuits. American cannot predict what impact environmental
laws and regulations will have on its future performance, but does not
currently anticipate the incurrence of material environmental expenditures.
However, the Company believes that such laws do not affect American in a
materially different manner from other similarly situated companies in the oil
and gas industry.
The Company's ratio of current assets to current liabilities was
0.59:1 at the end of 1996 compared to 0.67:1 at year-end 1995. The Company
historically has operated with a working capital deficit primarily due to
timing differences between the receipt of reimbursements from other working
interest owners in the properties operated by the Company and the payment of
expenses with respect to such properties.
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CHANGING OIL AND GAS PRICES
The Company's revenues, cash flow, profitability and future rate of
growth, as well as the carrying value of its oil and natural gas properties,
are substantially dependent upon the prices of oil and natural gas, which
historically have been volatile and are likely to continue to be volatile.
Various factors beyond the control of the Company affect prices of oil and
natural gas, including worldwide and domestic supplies of and demand for oil
and gas; political and economic conditions; weather conditions; the ability of
the members of the Organization of Petroleum Exporting Countries to agree on
and maintain price and production controls; political instability or armed
conflict in oil-producing regions; the price of foreign imports; the level of
consumer demand; the price and availability of alternative fuels; and changes
in existing federal and state regulations. Any significant decline in oil or
gas prices could have a material adverse effect on the Company's operations,
financial condition and level of development and exploration expenditures and
could result in a reduction of the Company's borrowing base under the Credit
Agreement, thereby reducing the amount of credit available to the Company to
fund its exploration, development and acquisition activities.
Part of the Company's business strategy is to reduce its exposure to
the volatility of oil and natural gas prices by entering into financial
arrangements designed to provide some protection against price declines,
including swaps and futures agreements. The Company's objective is to reduce
the risk that a sharp drop in oil or natural gas prices will cause the Company
to defer various capital spending projects. In certain circumstances,
significant reductions in production, due to unforeseen events, could require
the Company to make payments under the hedge agreements even though such
payments are not offset by production. To reduce this risk, the Company
strives to hedge less than its expected production. Hedging will also prevent
the Company from receiving the full advantage of increases in oil or natural
gas prices above the amount specified in the hedge. As of December 31, 1996,
the Company had hedges in place that covered approximately 79% of its oil
production and approximately 35% of its gas production, based on average daily
production during December 1996. For a discussion of hedging arrangements
related to 1997 production, reference is made to Note 13 to the Consolidated
Financial Statements in Item 8.
POTENTIAL DILUTION OF EQUITY OWNERSHIP
As of December 31, 1996, the Company had approximately 15.7 million
shares of common stock outstanding. In addition, (i) up to approximately 1.8
million shares of common stock are issuable upon conversion of the Company's
convertible preferred stock, at a conversion price of $15.00 per share, subject
to adjustment in certain circumstances, (ii) approximately 1.2 million shares
are issuable upon exercise of stock options outstanding at December 31, 1996 at
prices ranging from $11.50 to $40.00 per share, with a weighted average
exercise price of $13.53 per share, and (iii) approximately 1.6 million shares
are issuable upon exercise of warrants outstanding at December 31, 1996 at a
weighted average exercise price of $16.16 per share.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is set forth in a separate
section of this Report on Form 10-K and is incorporated herein by reference.
See the accompanying "Index of Financial Statements" at Page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors
The information set forth under the caption "Election of Directors" in
the Company's Proxy Statement for its 1997 Annual Meeting of Stockholders (the
"Proxy Statement"), which is to be filed with the Securities and Exchange
Commission (the "Commission") within 120 days of December 31, 1996 pursuant to
Regulation 14A under the Exchange Act, is incorporated herein by reference.
(b) Executive Officers
Information concerning executive officers is set forth under Items 1
and 2 of Part I hereof.
ITEM 11. EXECUTIVE COMPENSATION
The information set forth under the caption "Executive Compensation"
in the Company's Proxy Statement, which is to be filed with the Commission
within 120 days of December 31, 1996 pursuant to Regulation 14A under the
Exchange Act, is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information set forth under the captions "Principal Security
Holders" and "Security Ownership of Management" in the Company's Proxy
Statement, which is to be filed with the Commission within 120 days of December
31, 1996 pursuant to Regulation 14A under the Exchange Act, is incorporated
herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information set forth under the caption "Certain Relationships and
Related Transactions" in the Company's Proxy Statement, which is to be filed
with the Commission within 120 days of December 31, 1996 pursuant to Regulation
14A under the Exchange Act, is incorporated herein by reference.
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28
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements
See the accompanying "Index of Financial Statements" at Page F-1.
3. Exhibits
See the accompanying "Index of Exhibits" at Page X-2.
(b) Reports on Form 8-K
1. Report on Form 8-K, dated December 20, 1996, reporting the
Company's acquisition of the limited partners' interests in Ancon
Partnership Ltd.
26
29
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized on the 26th day of
March, 1997.
AMERICAN EXPLORATION COMPANY
(Registrant)
By: /s/MARK ANDREWS
-------------------------------
Mark Andrews
Chairman of the Board
and Chief Executive 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 indicated, on the 26th day of March, 1997.
Signature Title
--------- -----
/s/MARK ANDREWS Chairman of the Board
- ------------------------------------------------ and Chief Executive Officer
Mark Andrews (Principal Executive Officer)
/s/JOHN M. HOGAN Senior Vice President
- ------------------------------------------------ and Chief Financial Officer
John M. Hogan (Principal Financial Officer and
Principal Accounting Officer)
/s/HARRY W. COLMERY, JR. Director
- ------------------------------------------------
Harry W. Colmery, Jr.
/s/IRVIN K. CULPEPPER, JR. Director
- ------------------------------------------------
Irvin K. Culpepper, Jr.
/s/WALTER J. P. CURLEY Director
- ------------------------------------------------
Walter J. P. Curley
/s/ROBERT M. DANOS Director
- ------------------------------------------------
Robert M. Danos
27
30
/s/PHILLIP FROST, M.D. Director
- ------------------------------------------------
Phillip Frost, M.D.
/s/PETER G. GERRY Director
- ------------------------------------------------
Peter G. Gerry
/s/H. PHIPPS HOFFSTOT, III Director
- ------------------------------------------------
H. Phipps Hoffstot, III
/s/JOHN H. MOORE Director
- ------------------------------------------------
John H. Moore
/s/PETER P. NITZE Director
- ------------------------------------------------
Peter P. Nitze
28
31
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
INDEX OF FINANCIAL STATEMENTS
Page
-----
Financial Statements:
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . F-2
Consolidated Balance Sheets as of December 31, 1996 and 1995 . . . . . . . . . . . . . . . . . F-3
Consolidated Statements of Operations for the Three Years in the Period Ended
December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-4
Consolidated Statements of Cash Flows for the Three Years in the Period Ended
December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Stockholders' Equity for the Three Years in the Period Ended
December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . F-7
Supplemental Information on Oil and Gas Producing Activities . . . . . . . . . . . . . . . . . F-25
F-1
32
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors,
American Exploration Company:
We have audited the accompanying consolidated balance sheets of American
Exploration Company (a Delaware corporation) and subsidiaries as of December
31, 1996 and 1995, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1996. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of American
Exploration Company and subsidiaries as of December 31, 1996 and 1995, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1996, in conformity with generally accepted
accounting principles.
As explained in Note 1 to the consolidated financial statements, in 1994,
the Company changed its method of accounting for impairments of proved oil and
gas properties.
ARTHUR ANDERSEN LLP
Houston, Texas
February 25, 1997
F-2
33
CONSOLIDATED BALANCE SHEETS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT FOR SHARE AMOUNTS)
December 31,
-------------------------------
1996 1995
----------- ------------
ASSETS
Current assets:
Cash and temporary cash investments . . . . . . . . . . . . . . . . . . $ 8,358 $ 7,496
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . 18,449 14,520
Receivable from partnerships . . . . . . . . . . . . . . . . . . . . . . - 429
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . 1,335 966
----------- ------------
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . 28,142 23,411
----------- ------------
Property, plant and equipment:
Oil and gas properties, based on successful efforts accounting . . . . . 356,626 292,027
Other property and equipment . . . . . . . . . . . . . . . . . . . . . . 13,420 13,036
----------- ------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 370,046 305,063
Less: Accumulated depreciation, depletion and amortization . . . . . . 159,507 154,646
----------- ------------
Property, plant and equipment, net . . . . . . . . . . . . . . . . . 210,539 150,417
----------- ------------
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,947 2,202
----------- ------------
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 240,628 $ 176,030
=========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,647 $ 18,149
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . 25,049 16,953
Payable to partnerships . . . . . . . . . . . . . . . . . . . . . . . . 608 -
----------- ------------
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . 47,304 35,102
----------- ------------
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,000 40,000
----------- ------------
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,945 6,448
----------- ------------
Commitments and contingencies (Note 14) . . . . . . . . . . . . . . . . . .
Stockholders' equity:
Convertible preferred stock, $1.00 par value;
authorized: 100,000 shares (1996 and 1995);
issued and outstanding: 4,000 shares (1996 and 1995) . . . . . . . . 4 4
Common stock, $.05 par value;
authorized: 50,000,000 shares (1996 and 1995);
issued and outstanding: 15,694,430 shares (1996) and
11,812,483 shares (1995) . . . . . . . . . . . . . . . . . . . . . . 785 591
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . 322,598 276,713
Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . (192,948) (182,543)
Unearned compensation . . . . . . . . . . . . . . . . . . . . . . . . . (60) (219)
Notes receivable from officers . . . . . . . . . . . . . . . . . . . . . - (66)
----------- ------------
Total stockholders' equity . . . . . . . . . . . . . . . . . . . . . 130,379 94,480
----------- ------------
Total liabilities and stockholders' equity . . . . . . . . . . . . $ 240,628 $ 176,030
=========== ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
34
CONSOLIDATED STATEMENTS OF OPERATIONS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)
Year Ended December 31,
---------------------------------------------
1996 1995 1994
----------- ----------- ------------
REVENUES:
Oil and gas sales . . . . . . . . . . . . . . . . . . . . $ 76,228 $ 70,768 $ 50,033
Gain on sales of oil and gas properties . . . . . . . . . 978 10,230 1,110
Other revenues, net . . . . . . . . . . . . . . . . . . . 281 969 216
----------- ----------- ------------
Total revenues . . . . . . . . . . . . . . . . . . . . 77,487 81,967 51,359
----------- ----------- ------------
COSTS AND EXPENSES:
Production and operating . . . . . . . . . . . . . . . . . 25,681 29,443 25,932
Depreciation, depletion and amortization . . . . . . . . . 29,563 30,726 29,616
General and administrative . . . . . . . . . . . . . . . . 7,205 8,304 11,115
Exploration, including impairments . . . . . . . . . . . . 18,834 6,648 11,129
Writedown of oil and gas properties . . . . . . . . . . . - - 25,000
----------- ----------- ------------
Total costs and expenses . . . . . . . . . . . . . . . 81,283 75,121 102,792
----------- ----------- ------------
INCOME (LOSS) FROM OPERATIONS . . . . . . . . . . . . . . . . (3,796) 6,846 (51,433)
----------- ----------- ------------
OTHER INCOME (EXPENSE):
Interest expense . . . . . . . . . . . . . . . . . . . . . (4,239) (5,481) (6,638)
Other, net . . . . . . . . . . . . . . . . . . . . . . . . (289) (9) (2,619)
----------- ----------- ------------
Total other expense . . . . . . . . . . . . . . . . . . (4,528) (5,490) (9,257)
----------- ----------- ------------
INCOME (LOSS) BEFORE INCOME TAXES
AND EXTRAORDINARY ITEM . . . . . . . . . . . . . . . . . . (8,324) 1,356 (60,690)
Income tax benefit (provision) . . . . . . . . . . . . . . . (281) 121 455
----------- ----------- ------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM . . . . . . . . . . . (8,605) 1,477 (60,235)
Extraordinary gain on extinguishment of debt . . . . . . . . - 2,456 5,419
----------- ----------- ------------
NET INCOME (LOSS) . . . . . . . . . . . . . . . . . . . . . . (8,605) 3,933 (54,816)
Preferred stock dividends . . . . . . . . . . . . . . . . . . (1,800) (1,800) (1,800)
----------- ----------- ------------
NET INCOME (LOSS) TO COMMON STOCK . . . . . . . . . . . . . . $ (10,405) $ 2,133 $ (56,616)
=========== =========== ============
NET INCOME (LOSS) PER COMMON SHARE:
Primary and fully diluted:
Loss before extraordinary item . . . . . . . . . . . . $ (0.84) $ (0.03) $ (7.70)
Extraordinary item. . . . . . . . . . . . . . . . . . . - 0.21 0.68
----------- ----------- ------------
NET INCOME (LOSS) PER COMMON SHARE . . . . . . . . . $ (0.84) $ 0.18 $ (7.02)
=========== =========== ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
35
CONSOLIDATED STATEMENTS OF CASH FLOWS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS)
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) . . . . . . . . . . . . . . . . . . . . $ (8,605) $ 3,933 $ (54,816)
Adjustments to arrive at net cash provided by
operating activities:
Depreciation, depletion and amortization . . . . . . . 29,563 30,726 29,616
Gain on sales of oil and gas properties . . . . . . . . (978) (10,230) (1,110)
Exploration, including impairments . . . . . . . . . . 18,834 6,582 10,458
Writedown of oil and gas properties . . . . . . . . . . - - 25,000
Extraordinary gain . . . . . . . . . . . . . . . . . . - (2,456) (5,419)
Other, net . . . . . . . . . . . . . . . . . . . . . . 349 759 2,909
Changes in operating working capital:
Accounts receivable . . . . . . . . . . . . . . . . . . (4,143) (574) (2,899)
Other current assets . . . . . . . . . . . . . . . . . (115) (144) (320)
Accounts payable and accrued liabilities . . . . . . . 1,367 5,760 1,874
Other operating . . . . . . . . . . . . . . . . . . . . . (901) (1,051) 2,454
----------- ----------- ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES . . . . . 35,371 33,305 7,747
----------- ----------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties . . . . . . . . . . (73,879) (15,972) (28,387)
Development expenditures . . . . . . . . . . . . . . . . . (15,595) (23,320) (15,341)
Exploration expenditures . . . . . . . . . . . . . . . . . (26,069) (4,160) (5,603)
Proceeds from sales of oil and gas properties . . . . . . 16,896 63,488 2,638
Other investing . . . . . . . . . . . . . . . . . . . . . (499) 1,545 (4,241)
----------- ----------- ------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (99,146) 21,581 (50,934)
----------- ----------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings . . . . . . . . . . . . . . . . . . . 96,000 50,500 23,000
Bank debt repayments . . . . . . . . . . . . . . . . . . . (76,000) (73,500) (1,500)
Borrowings under bridge credit facility . . . . . . . . . - - 32,078
Repayments under bridge credit facility . . . . . . . . . - (31,128) (950)
Repayments of other debt . . . . . . . . . . . . . . . . . - (1,141) (8,622)
Issuance of equity securities . . . . . . . . . . . . . . 47,200 - 2,100
Preferred stock dividends . . . . . . . . . . . . . . . . (1,800) (1,800) (1,800)
Debt and equity issuance costs and other . . . . . . . . . (763) (294) (3,382)
----------- ----------- ------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 64,637 (57,363) 40,924
----------- ----------- ------------
NET INCREASE (DECREASE) IN CASH AND
TEMPORARY CASH INVESTMENTS . . . . . . . . . . . . . . . . 862 (2,477) (2,263)
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR . . 7,496 9,973 12,236
----------- ----------- ------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR . . . . . $ 8,358 $ 7,496 $ 9,973
=========== =========== ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
36
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS)
Notes
Convertible Additional Receivable
Preferred Common Paid-In Accumulated Treasury Unearned from
Stock Stock Capital Deficit Stock Compensation Officers
---------- -------- ----------- ----------- --------- ------------- ---------
BALANCE, DECEMBER 31, 1993 . . . . . . . . $ 4 $ 353 $ 215,597 $ (128,060) $ (342) $ (916) $ (230)
Issuance of shares in APPL Consolidation - 213 56,017 - - - -
Sale of common stock . . . . . . . . . . - 8 2,092 - - - -
Stock issuance costs . . . . . . . . . . - - (889) - - - -
Dividends on preferred stock ($450.00
per share). . . . . . . . . . . . . . - - - (1,800) - - -
Amortization of unearned compensation . - - - - - 391 -
Repayments of notes receivable from
officers. . . . . . . . . . . . . . . - - - - - - 88
Net loss . . . . . . . . . . . . . . . . - - - (54,816) - - -
---------- -------- ----------- ----------- --------- ------------ ----------
BALANCE, DECEMBER 31, 1994 . . . . . . . . 4 574 272,817 (184,676) (342) (525) (142)
Issuance of shares in APPL Consolidation - 17 4,309 - - - -
Reverse stock split costs . . . . . . . - - (71) - - - -
Cancellation of treasury shares . . . . - - (342) - 342 - -
Dividends on preferred stock ($450.00
per share) . . . . . . . . . . . . . . - - - (1,800) - - -
Amortization of unearned compensation . - - - - - 306 -
Repayments of notes receivable from
officers . . . . . . . . . . . . . . . - - - - - - 76
Net income . . . . . . . . . . . . . . . - - - 3,933 - - -
---------- -------- ----------- ----------- --------- ------------ ----------
BALANCE, DECEMBER 31, 1995 . . . . . . . . 4 591 276,713 (182,543) - (219) (66)
Sale of common stock . . . . . . . . . . - 194 47,006 - - - -
Stock issuance costs . . . . . . . . . . - - (1,125) - - - -
Other stock transactions . . . . . . . . - - 4 - - - -
Dividends on preferred stock ($450.00
per share) . . . . . . . . . . . . . . - - - (1,800) - - -
Amortization of unearned compensation . - - - - - 159 -
Repayments of notes receivable from
officers . . . . . . . . . . . . . . . - - - - - - 66
Net loss . . . . . . . . . . . . . . . . - - - (8,605) - - -
---------- -------- ----------- ----------- --------- ------------ ----------
BALANCE, DECEMBER 31, 1996 . . . . . . . . $ 4 $ 785 $ 322,598 $ (192,948) $ - $ (60) $ -
========== ======== =========== =========== ========= ============ ==========
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
American Exploration Company and its majority-owned subsidiaries (collectively
referred to as "American" or the "Company"). American is an independent
company engaged in exploration, development and production of oil and natural
gas. American's oil and gas operations are conducted in the United States with
exploration and development activities concentrated in the Gulf of Mexico,
South Texas, East Texas and southwestern Arkansas. In addition to conducting
oil and gas operating activities on its own behalf, the Company managed certain
producing oil and gas properties through various limited partnerships. (See
Note 4.)
The Company's investments in associated oil and gas programs were accounted
for using the proportionate consolidation method, whereby the Company's
proportionate share of each program's assets, liabilities, revenues and
expenses was included in the appropriate accounts in the consolidated financial
statements. All significant intercompany balances and transactions have been
eliminated in consolidation. Certain amounts in prior years' consolidated
financial statements have been reclassified to conform with current
classifications.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results may differ from those
estimates.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents. The Company's cash
balance at December 31, 1996 included approximately $3.7 million that
represented American's proportionate share of property sales proceeds received
during the fourth quarter by certain investment programs that are in the
process of liquidation. (See Note 4.) Outstanding checks totaling
approximately $1.1 million and $5.1 million at December 31, 1996 and 1995,
respectively, were included in accounts payable.
PROPERTY, PLANT AND EQUIPMENT
The Company accounts for its oil and gas exploration and production
activities using the successful efforts method of accounting. Under this
method, acquisition costs for proved and unproved properties are capitalized
when incurred. Exploration costs, including geological and geophysical costs
and costs of carrying and retaining unproved properties, are charged to expense
as incurred. The costs of drilling exploratory wells are capitalized pending
determination of whether each well has resulted in the discovery of proved
reserves. If proved reserves are not discovered, such drilling costs are
charged to expense. Costs incurred to drill and equip development wells,
including unsuccessful development wells, are capitalized. Internal costs
related to the acquisition, development and exploration of oil and gas
properties are expensed as incurred. Interest is capitalized on qualifying
assets, primarily unproved and unevaluated properties.
Depletion of the cost of producing oil and gas properties is computed on the
unit-of-production method. The Company also accrues for platform abandonment
costs related to its offshore platform facilities on the unit-of-production
method. The Company anticipates total abandonment costs to be approximately
$11.9 million. As of December 31, 1996, the Company had accrued $5.4 million,
which is included in accumulated depreciation, depletion and amortization
("DD&A").
Unproved properties are assessed periodically, and any impairment in value
is recognized currently in exploration expense. The Company recorded
impairment charges of $2.1 million, $1.8 million and $8.6 million in 1996, 1995
and 1994, respectively, related to unproved properties on which no further
exploration was planned. As of December 31, 1996,
F-7
38
the Company owned unproved oil and gas properties with a book value of
approximately $33 million. The Company plans to commence drilling on its most
significant prospects in 1997; however, if such drilling activity does not
result in the discovery of proved oil and gas reserves on a particular
property, an impairment charge would be recorded to write off the value of that
property.
Effective March 1995, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of". Under the provisions of that
statement, if the net book value of an individual proved oil or gas field is
greater than its undiscounted future net cash flow from proved reserves, then
an impairment is recognized for the difference between the net book value and
the fair value. The fair value used to calculate the impairment for an
individual field is equal to the present value of its future net cash flows.
In 1994, American recorded a noncash impairment charge of $25 million to write
down the value of certain proved properties when the Company changed its
impairment policy to one consistent with that required by SFAS No. 121.
Previously, the Company's impairment policy was to recognize an impairment of
proved oil and gas property costs if, on a company-wide basis, those costs
exceeded the undiscounted after-tax future net cash flows from proved reserves.
Property, plant and equipment other than oil and gas properties are
depreciated by the straight-line method at rates based on the estimated useful
lives of the assets. Repairs and maintenance are charged to expense as
incurred; renewals and betterments are capitalized.
INVESTMENT PROGRAMS
The Company managed various investment programs that were formed to acquire
interests in producing oil and gas properties. The Company charges each
investment program fees for reimbursement of expenses incurred in managing the
program's operations and certain fees for services provided by technical
employees of the Company. Such fees are recorded as reductions to general and
administrative expense. (See Notes 4 and 11.)
FINANCIAL INSTRUMENTS
The Company periodically enters into commodity price swap agreements, collar
transactions and floor transactions, in order to hedge against volatility in
oil and gas prices. Gains or losses on these transactions are reported as a
component of oil and gas sales in the period during which the related
production occurs. The cost to purchase put options in connection with floor
transactions is recognized ratably over the term of the agreement as a
reduction of oil and gas revenues. (See Note 13.)
GAS BALANCING
The Company utilizes the sales method of accounting for natural gas revenues
whereby revenues are recognized based on the amount of gas sold to purchasers.
The amount of gas sold may differ from the amount to which the Company is
entitled based on its working interests in the properties. At December 31,
1996 and 1995, the Company had recorded a liability of $1.4 million and $3.6
million, respectively, for properties having insufficient reserves from which
to recover the gas imbalance.
INCOME TAXES
The income tax provision (benefit) reflects income taxes currently payable
and income taxes deferred due to temporary differences between the financial
statement and tax bases of assets and liabilities. Deferred tax assets and
liabilities are determined using enacted tax rates in effect for the year in
which the temporary differences are expected to reverse. (See Note 12.)
STOCK COMPENSATION PLANS
The Company accounts for its stock compensation plans by applying the
provisions of Accounting Principles Board ("APB") Opinion No. 25, "Accounting
for Stock Issued to Employees"; accordingly, no compensation expense has been
recognized for awards granted under these plans. (See Note 10.)
F-8
39
NET INCOME (LOSS) PER COMMON SHARE
Net income (loss) per common share has been computed by dividing net income
or loss, after reductions for preferred stock dividends, by the weighted
average number of common shares outstanding during each year. Common share
equivalents were not included in the calculation of earnings per share since
any assumed exercises of stock options or warrants were antidilutive for all
years presented. Any assumed conversion of convertible preferred stock also
was antidilutive for all three years. The weighted average shares used in the
primary earnings per share calculations were 12,395,400 in 1996, 11,811,500 in
1995 and 8,060,800 in 1994. Weighted average shares for prior periods have
been retroactively restated to reflect the one-for-ten reverse split of the
Company's common stock. (See Note 2.)
In November 1996, the Company issued common stock in a public offering and
applied the net proceeds from the sale to reduce outstanding bank debt that had
been incurred to fund a property acquisition in September 1996. Had the stock
offering occurred on the same date as the acquisition, the Company's net loss
per common share would have been reduced to $0.78 per share assuming that no
interest expense would have been incurred in conjunction with the acquisition.
(2) REVERSE STOCK SPLIT
In June 1995, American's stockholders approved an amendment to the Company's
Restated Certificate of Incorporation that effected a one-for-ten reverse split
of its common stock (the "Reverse Stock Split") and also reduced the number of
authorized shares of common stock from 200,000,000 to 50,000,000. As a result
of the Reverse Stock Split, the number of outstanding shares of common stock
was reduced to approximately 11.8 million shares outstanding from approximately
118.1 million shares outstanding immediately prior to the Reverse Stock Split.
In addition, approximately $5.3 million was reclassified on the consolidated
balance sheet from common stock to additional paid-in capital. The remaining
shares of treasury stock held by American prior to the Reverse Stock Split were
cancelled. The stockholders' equity accounts on the accompanying balance
sheets have been restated to give retroactive recognition to the Reverse Stock
Split for all periods presented. In addition, all references to number of
shares of common stock and per share amounts have been restated throughout this
report.
(3) ACQUISITIONS OF OIL AND GAS PROPERTIES
In December 1996, the Company acquired from New York Life Insurance Company
("New York Life") and certain of its affiliates (collectively, the "Limited
Partners") the Limited Partners' aggregate 80% interest in Ancon Partnership
Ltd. ("Ancon") for a purchase price of approximately $12.9 million (the "Ancon
Acquisition"). The Company served as general partner of Ancon and owned a 20%
interest in the partnership. The acquisition was funded through borrowings
under the Company's revolving bank credit agreement (the "Credit Agreement").
The net assets acquired by the Company included interests in oil and gas
properties valued at approximately $7.7 million, after considering certain
purchase price adjustments, and the remaining purchase price was attributable
to acquired working capital. The Ancon Acquisition was accounted for using the
purchase method of accounting, and the assets acquired were valued based upon
the cash consideration paid by the Company. The Company's 1996 results of
operations do not include any results related to the interests acquired in the
Ancon Acquisition.
In December 1996, the Company acquired a 40% working interest in certain
undeveloped acreage in the Cotton Valley Pinnacle Reef Trend in East Texas
("Cotton Valley"). The Company invested $3.9 million for acreage and seismic
costs. For a description of certain drilling commitments related to this
property, see Note 14.
In September 1996, the Company acquired interests in two blocks in the Gulf
of Mexico, High Island Block 116 and East Cameron Block 328, for a purchase
price of approximately $39 million, net of interests that were sold to a third
party in November 1996 (the "September 1996 Acquisition"). The acquisition was
funded through borrowings under the Credit Agreement. The September 1996
Acquisition was accounted for using the purchase method, and the acquired
properties were valued based upon the cash consideration paid. The Company's
1996 results of operations include the results of the properties acquired in
the September 1996 Acquisition beginning on September 27, 1996.
In March 1996, the Company and a subsidiary of Dominion Resources, Inc.
acquired interests in five offshore blocks in the Gulf of Mexico for a purchase
price of approximately $56 million (the "March 1996 Acquisition" and, together
with the September 1996 Acquisition, the "Offshore Acquisitions"). The
Company's 25% share of the March
F-9
40
1996 Acquisition was funded through borrowings of approximately $14 million
under the Credit Agreement. The March 1996 Acquisition was accounted for using
the purchase method, and the acquired properties were valued based upon the
cash consideration paid. The Company's 1996 results of operations include the
results from the properties acquired in the March 1996 Acquisition effective
March 1, 1996.
During the period 1983-1990, American obtained long-term funding for many of
its oil and gas property acquisitions through a series of investment programs
formed primarily with institutional investors ("APPL Programs"). During 1994
and 1995, the Company, which served as the general partner, purchased limited
partners' interests, net profits interests and debt interests in the APPL
Programs (the "APPL Consolidation"). The consideration paid for the
acquisition of the APPL interests in 1994 was a combination of $31.1 million in
cash and 4.3 million shares of the Company's common stock. In connection with
the transaction, $13.6 million in nonrecourse debt was eliminated, resulting in
an extraordinary gain totaling $5.4 million. In 1995, the Company repurchased
the remaining investors' interests in the APPL Programs for a combination of
$9 million in cash and the issuance of 346,000 shares of the Company's common
stock, thereby eliminating the remaining $6.6 million of nonrecourse debt that
had been outstanding at year-end 1994. The elimination of the APPL debt in
1995 resulted in an extraordinary gain of $2.5 million. No income tax expense
was recognized on the extraordinary gains.
(4) LIQUIDATION OF NYLOG PROGRAMS
From 1985 until early 1992, subsidiaries of the Company and New York Life
formed a series of publicly registered limited partnerships, the New York Life
Oil & Gas Producing Properties Programs ("NYLOG Programs"). The NYLOG Programs
invested in the acquisition and further development of producing oil and gas
properties acquired by the Company. A total of $229.1 million has been
invested by the limited partners in these programs since inception. (See Note
11.)
In July 1996, the limited partners of the NYLOG Programs approved the
liquidation of the partnerships (the "NYLOG Liquidation"). During the fourth
quarter of 1996, the Company closed the sales of substantially all of the
property interests owned by the NYLOG Programs. The Company expects to
complete the liquidation and dissolution of the NYLOG Programs in the second
quarter of 1997.
Prior to February 1, 1996, New York Life and the Company, in their capacity
as co-general partners, each paid 5% of property acquisition costs of the NYLOG
Programs, and each received 7.5% of net revenues until payout. Payout occurred
when the limited partners had received distributions equal to their initial
investment. After payout, the Company's and New York Life's interests in
capital costs and net revenues each increased to 12.5%. Two of the NYLOG
Programs had reached payout prior to the sale of the oil and gas properties of
the NYLOG Programs.
In February 1996, a subsidiary of New York Life agreed to enter into an
indemnity agreement with the Company and a subsidiary related to certain
litigation regarding the NYLOG Programs. Pursuant to the terms of the
indemnity agreement, American will be allocated 5% (which represents the
Company subsidiary's initial capital contribution percentage) of revenues from
the NYLOG Programs and net proceeds from the sale of the NYLOG properties
effective from and after February 1, 1996. For further discussion of certain
litigation against the co-general partners of the NYLOG Programs and the terms
of the indemnity agreement, see Note 14.
(5) DIVESTITURES OF OIL AND GAS PROPERTIES
The Company received cash proceeds, net of post-closing adjustments, of
$16.9 million, $63.5 million and $2.6 million from the sales of oil and gas
properties in 1996, 1995 and 1994, respectively. Property sales in 1996
primarily related to the divestiture of certain properties in conjunction with
the NYLOG Liquidation for a purchase price of approximately $10.1 million. The
Company sold interests in approximately 100 oil and gas properties, including
those properties owned by the NYLOG Programs and certain related property
interests (the "1996 Sales"). In addition, the Company sold a 10% interest in
High Island Block 116 for a purchase price of approximately $5.8 million.
Sales of various other fields in 1996 resulted in a net gain of $978,000. (See
Notes 3 and 4.)
In July 1995, the Company sold its interest in the Sawyer Field to Louis
Dreyfus Natural Gas Corp. for a purchase price of $64 million (the "Sawyer
Sale"). As part of the Sawyer Sale, the Company also sold its interest in the
field that
F-10
41
was acquired through the APPL Consolidation in early 1995. (See Note 3.)
American's share of the net proceeds from the sale was applied to eliminate
$62.5 million of the Company's outstanding bank debt. The Company recorded a
gain on the Sawyer Sale of approximately $10.6 million in 1995. Sales of
various other fields in 1995 resulted in a net loss of approximately $400,000.
Sales in 1994 related to the divestiture of low-value properties and resulted
in a net gain of $1.1 million.
(6) PRO FORMA INFORMATION (UNAUDITED)
The following pro forma summary of consolidated results of operations for
the years ended December 31, 1996 and 1995 gives effect to (i) that portion of
the APPL Consolidation that was completed in the first half of 1995 for a
purchase price of approximately $9 million, (ii) the Sawyer Sale in July 1995
for proceeds of $64 million, (iii) the 1995 sales of interests in several other
fields for aggregate proceeds of approximately $2.5 million (the "1995 Sales"),
(iv) the Offshore Acquisitions, (v) the 1996 Sales and (vi) the Ancon
Acquisition.
The pro forma results have been prepared assuming that each of the
transactions described above was consummated as of January 1, 1995. The pro
forma data for the year ended December 31, 1995 does not include results from
the High Island 116 well acquired in the September 1996 Acquisition because the
well did not produce during the period. Similarly, the pro forma data for the
year ended December 31, 1996 includes only five months of results from the High
Island 116 well, which results reflect the Company's acquired interest net of
interests sold to a third party in November 1996. The well commenced
production in August 1996 at a net production rate of 300 Bbls of oil per day
and 17,100 Mcf of natural gas per day. The pro forma data does not reflect the
nonrecurring gain of approximately $10.6 million on the Sawyer Sale.
(In thousands except per share amounts) Year Ended December 31,
-------------------------------
1996 1995
------------ ------------
Pro forma revenues . . . . . . . . . . . . . . . . . . . . $ 82,656 $ 70,839
Pro forma loss before extraordinary item . . . . . . . . . (8,952) (7,614)
Pro forma net loss to common stock . . . . . . . . . . . . (10,752) (6,958)
Pro forma net loss per common share:
Primary and fully diluted:
Loss before extraordinary item . . . . . . . . . . . $ (0.87) $ (0.80)
Net loss . . . . . . . . . . . . . . . . . . . . . . (0.87) (0.59)
Weighted average shares outstanding:
Primary and fully diluted . . . . . . . . . . . . . . . 12,395 11,812
The pro forma amounts do not purport to be indicative of the results of
operations of American that may be reported in the future or that would have
been reported had these transactions occurred as of January 1, 1995.
F-11
42
(7) DEBT
The following table details the components of the Company's debt (in
thousands):
December 31,
-------------------------------
1996 1995
------------ ------------
Credit Agreement . . . . . . . . . . . . . . . . . . . . . $ 25,000 $ 5,000
Subordinated Notes . . . . . . . . . . . . . . . . . . . . 35,000 35,000
------------ ------------
Total long-term debt . . . . . . . . . . . . . . . . . . $ 60,000 $ 40,000
============ ============
BANK DEBT
As of December 31, 1996, the borrowing base, or amount available, under the
Credit Agreement was $75 million. The increase in the borrowing base from $40
million at year-end 1995 reflects the increase in the value of the Company's
oil and gas properties primarily due to the Offshore Acquisitions. Outstanding
borrowings of $25 million under the Credit Agreement at December 31, 1996 were
classified as long-term debt. The Company also had approximately $652,000 in
letters of credit outstanding at December 31, 1996 that are collateralized by
the Company's borrowing base. The borrowing base under the Credit Agreement is
scheduled to be redetermined semiannually every March and September.
The borrowings under the Credit Agreement during 1996 were used to fund the
Offshore Acquisitions, the Ancon Acquisition and various capital projects. In
November 1996, the Company applied the proceeds from the sale of common stock
to reduce bank debt by approximately $46 million. (See Note 9.)
Borrowings under the Credit Agreement are secured by substantially all of
the assets of the Company. At the option of the Company, borrowings bear
interest at (i) LIBOR plus 1.50%, 1.75% or 2.00% or (ii) the higher of (a) the
prime rate plus 0.50%, 0.75% or 1.00% or (b) the federal funds rate plus 1.00%,
1.25% or 1.50%. The applicable margin is added to the respective interest rate
based on the ratio of the total amount of bank debt outstanding to the amount
available under the Credit Agreement. The lowest, median or highest margin is
applied if such ratio is less than or equal to 50%, is greater than 50% but
less than or equal to 80%, or is greater than 80%, respectively. The weighted
average interest on the Company's bank debt outstanding at December 31, 1996
was 7.6%. During 1996, the Company paid an annual commitment fee of 0.50% of
the difference between the amount available under the Credit Agreement and the
average amount outstanding, including letters of credit. Under the terms of an
amendment to the Credit Agreement in October 1996, principal on the remaining
long-term portion of the facility is scheduled to be repaid in ten quarterly
installments commencing September 30, 1999. Interest is payable quarterly or
upon maturity of the borrowing, if shorter, in the case of Eurodollar loans and
monthly in the case of prime rate or federal funds rate loans.
11% SENIOR SUBORDINATED NOTES
In December 1991, the Company privately placed $35 million in senior
subordinated notes (the "Subordinated Notes") and immediately exercisable
detachable warrants with three institutional investors. The notes bear
interest at 11% payable semiannually every June and December. The warrants
grant the holders the right to purchase approximately 1.2 million shares of the
Company's common stock. In addition, each holder of the warrants has the
option to tender the notes in lieu of cash as consideration for the exercise
price.
In September 1996, holders of the Subordinated Notes agreed to an extension
of the principal payment dates of the notes, which were scheduled to begin in
December 1997, in exchange for a reduction in the exercise price of the
warrants, from $21.65 per share to $15.53 per share (as of the amendment date).
As a result of this extension, annual principal payments of approximately $11.7
million on the notes will begin in December 2002.
FEES RELATED TO DEBT INSTRUMENTS
The Company incurs fees related to its credit facilities that are reported
as other expense. During 1996, 1995 and 1994, these fees totaled $696,000,
$951,000 and $2.3 million, respectively. Fees paid in 1994 included $2.1
million
F-12
43
incurred in connection with a new bank credit agreement and a bridge facility
provided by New York Life in connection with the APPL Consolidation.
DEBT COVENANTS
The Credit Agreement and the Subordinated Notes require the Company to
comply with certain covenants including, but not limited to, restrictions on
indebtedness, investments, payment of dividends and lease commitments. Cash
dividends are prohibited on the Company's common stock, and annual preferred
dividends are limited to 10% of the proceeds from the sale of preferred stock
that may be outstanding from time to time, not to exceed $7.5 million. The
current annual limit on preferred dividends is $2 million. These agreements
also include a requirement to maintain a minimum net worth of $88.5 million.
In addition, these agreements contain cross-default provisions. The Company
was in compliance with these covenants at year end 1996.
ANNUAL MATURITIES
Based on the amounts outstanding at December 31, 1996, the aggregate
maturities of debt for the next five years are as follows (in thousands):
1997 . . . . . . . . . . . $ -
1998 . . . . . . . . . . . -
1999 . . . . . . . . . . . 5,000
2000 . . . . . . . . . . . 10,000
2001 . . . . . . . . . . . 10,000
Thereafter . . . . . . . . 35,000
----------
$60,000
==========
(8) PREFERRED STOCK
The Company has authorized 100,000 shares of preferred stock, par value
$1.00 per share. The Board of Directors has authority to divide such preferred
stock into one or more series and has authority to fix and determine the
relative rights and preferences of each such series. At December 31, 1996,
American had 4,000 shares of convertible preferred stock outstanding and an
additional 85,000 shares of preferred stock reserved under the Company's
Stockholder Rights Plan.
CONVERTIBLE PREFERRED STOCK
In December 1993, the Company privately placed 800,000 depositary shares,
each representing a 1/200 interest in a share of $450 Cumulative Convertible
Preferred Stock, Series C (the "Convertible Preferred Stock"). The Convertible
Preferred Stock has a stated value of $5,000 per share, with dividends payable
quarterly at the annual rate of $450 per share. The Convertible Preferred
Stock is convertible at any time at the option of the holders into shares of
the Company's common stock at a conversion price of $15.00 per share, subject
to adjustment in certain circumstances. Beginning December 31, 1997, the
Convertible Preferred Stock will be redeemable at the option of the Company, in
whole or in part, at any time. The initial redemption price is $5,270 per
share, declining ratably on December 31 of each year to a redemption price of
$5,000 per share on and after December 31, 2003, plus accrued and unpaid
dividends.
The Convertible Preferred Stock has a special conversion right that becomes
effective upon the occurrence of certain types of significant transactions
affecting ownership or control of the Company. If the special conversion right
becomes effective, the then-prevailing conversion price would be reduced to the
market value of the common stock, not to be reduced below a minimum conversion
price of $11.25 per share of common stock.
STOCKHOLDER RIGHTS PLAN
In September 1993, the Board of Directors of the Company declared a
distribution of one right ("Right") for each outstanding share of common stock
to stockholders of record at the close of business on October 8, 1993 and for
each share of common stock issued by the Company thereafter and prior to the
"Distribution Date", as defined. Each Right entitles
F-13
44
the registered holder to purchase one one-thousandth of a share (a "Unit") of
Series B Preferred Stock at a price of $7.50 per Unit, subject to adjustment.
The Rights are exercisable only upon the occurrence of certain triggering
events, including the acquisition by a person or group of 15% or more of the
Company's outstanding common stock, other than those persons that acquired
common stock through the APPL Consolidation. If a triggering event occurs,
holders of each Right would be entitled to receive, upon exercise, the Units of
Series B Preferred Stock (or stock of the acquiring entity, as the case may be)
having a value equal to two times the exercise price of the Right. Such Rights
do not extend to any holder whose action triggered the Right.
The Rights may be redeemed in whole by American at $0.10 per Right any time
until the tenth business day following public announcement that a person or
group, other than those persons that acquired common stock through the APPL
Consolidation, has acquired, obtained the right to acquire or otherwise
obtained beneficial ownership of 15% or more of the Company's outstanding
common stock.
(9) COMMON STOCK
The Company has authorized 50,000,000 shares of common stock, of which
15,694,430 shares were issued and outstanding at December 31, 1996. A schedule
of the changes in the Company's common stock is provided below:
Year Ended December 31,
--------------------------------------------------
1996 1995 1994
------------- ------------ -------------
Outstanding shares at beginning of year . . . . . . . . 11,812,483 11,468,313 7,051,350
Issuance of shares in public offering . . . . . . . . . 3,880,000 - -
Issuance of shares in APPL Consolidation . . . . . . . - 346,094 4,266,963
Issuance of shares in private offering . . . . . . . . - - 150,000
Other issuances (retirements) . . . . . . . . . . . . . 1,947 (1,924) -
------------- ------------ -------------
Outstanding shares at end of year . . . . . . . . . 15,694,430 11,812,483 11,468,313
============= ============ ============
In November 1996, the Company completed a public offering of approximately
3.9 million shares of common stock priced at $12 7/8 per share, resulting in
net proceeds of approximately $46 million. American used the proceeds to
reduce outstanding bank debt.
As of December 31, 1996, the Company had warrants outstanding to purchase an
aggregate of up to approximately 1.6 million shares of common stock. In
December 1991, the Company issued warrants to certain institutional investors
in conjunction with the issuance of its Subordinated Notes (the "Institutional
Warrants"). As of December 31, 1996, the Institutional Warrants grant the
right to purchase approximately 1.2 million shares (as adjusted for subsequent
events) of common stock at an exercise price of $15.01 per share, subject to
adjustment, on or before December 30, 2004. In connection with an acquisition
of common stock in September 1992, Prudential Insurance acquired warrants to
purchase common stock (the "Prudential Warrants" and, collectively with the
Institutional Warrants, the "Warrants"). At the end of 1996, the Prudential
Warrants grant the right to purchase approximately 356,000 shares (as adjusted)
of common stock at an exercise price of $20.20 per share, subject to
adjustment, on or before April 30, 1999.
The Warrants contain certain provisions for adjustment of exercise prices in
certain events, including sales of common stock at less than the exercise price
or fair market value thereof, stock dividends, stock splits, reorganizations,
reclassifications and mergers. Holders of the Warrants are also entitled to
certain registration rights with respect to common stock issued upon the
exercise thereof.
The Company may at its option redeem (i) any or all of the outstanding
Institutional Warrants for cash on or after December 30, 1996 at $10.35 per
share of common stock issuable upon the exercise of such warrants, subject to
adjustment, and (ii) all of the outstanding Prudential Warrants at any time
after October 1, 1994 at the exercise price in
F-14
45
effect on the date of redemption, provided in each case that the common stock
has traded at specified prices above the then current exercise price for a
specified period.
Shares of common stock reserved for future issuance as of December 31, 1996
were as follows:
Exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . 1,453,807
Exercise of Institutional Warrants . . . . . . . . . . . . . . . . . . . 1,247,837
Exercise of Prudential Warrants . . . . . . . . . . . . . . . . . . . . 356,489
Conversion of Convertible Preferred Stock . . . . . . . . . . . . . . . 1,333,333
Special conversion rights of Convertible Preferred Stock . . . . . . . . 444,444
--------------
Total shares reserved . . . . . . . . . . . . . . . . . . . . . . . . 4,835,910
==============
(10) EMPLOYEE BENEFIT PLANS
STOCK COMPENSATION PLANS
The American Exploration Company Stock Compensation Plan established in 1983
(the "1983 Plan") provides for the issuance of up to 500,000 shares of the
Company's common stock. The 1983 Plan also authorizes the issuance of stock
appreciation rights in conjunction with stock options and the granting of
restricted common stock and performance shares. In 1996, 1995 and 1994, the
Company recognized $159,000, $306,000 and $391,000, respectively, of
compensation expense related to certain restricted stock purchased by the
executive officers in 1993. The difference between the aggregate fair market
value of the restricted shares purchased and the purchase price was considered
unearned compensation at the time of grant, and compensation was earned ratably
over the vesting period at 33 1/3% per year commencing with the first
anniversary of grant. During the three-year reporting period, no other
restricted common stock was issued nor were any stock appreciation rights or
performance shares granted under the 1983 Plan.
In November 1994, the Board of Directors adopted the 1994 American
Exploration Company Stock Compensation Plan (the "1994 Plan"), which was
approved by American's stockholders in June 1995. Under the 1994 Plan, 900,000
shares of the Company's common stock are available for the granting of stock
options, restricted common stock and performance shares. In addition,
performance units may be awarded and stock appreciation rights may be issued in
conjunction with the stock options.
The exercise price, term and other conditions applicable to each option
granted under the 1983 Plan and the 1994 Plan are determined at the time of the
grant of each option and may vary with each option granted. No option may be
granted at a price less than the fair market value of the stock on the date of
grant. Options granted generally vest ratably over a four-year period and have
a maximum term of ten years.
The Company adopted the disclosure provisions of SFAS No. 123, "Accounting
for Stock-Based Compensation", effective January 1, 1996. In accordance with
the provisions of SFAS No. 123, the Company applies APB Opinion 25 and related
interpretations in accounting for its stock compensation plans. Accordingly,
no compensation cost has been recognized for the Company's stock option awards.
If the Company had elected to recognize compensation cost based on the fair
value of the options granted at the grant date as prescribed by SFAS No. 123,
net income and earnings per share would not have been materially impacted in
1996 or 1995. Because the method of accounting under SFAS No. 123 has not been
applied to options granted prior to January 1, 1995, the resulting pro forma
compensation cost may not be representative of that to be expected in future
years.
F-15
46
Detailed information regarding stock option transactions during the last
three years is provided below:
Year Ended December 31,
--------------------------------------------------------------------
1996 1995 1994
--------------------- -------------------- --------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
--------- -------- -------- --------- -------- --------
Options outstanding at beginning of year. . 783,846 $ 16.09 879,653 $ 16.94 374,258 $ 26.75
Options granted . . . . . . . . . . . . . . 662,550 12.63 3,320 12.01 590,000 12.83
Options forfeited . . . . . . . . . . . . . (224,724) 19.93 (87,997) 22.66 (73,426) 29.77
Options expired . . . . . . . . . . . . . . (200) 20.00 (11,110) 29.60 (11,179) 44.76
Options exercised . . . . . . . . . . . . . (33,838) 12.73 (20) 8.75 - -
--------- -------- --------
Options outstanding at end of year . . . . 1,187,634 13.53 783,846 16.09 879,653 16.94
========= ======== ========
Options exercisable at end of year . . . . 346,051 15.58 361,633 19.47 242,466 25.96
========= ======== ========
The following table summarizes certain information regarding stock options
outstanding at December 31, 1996:
As of December 31, 1996
----------------------------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------------------------------------------- ----------------------------------
Weighted Average Weighted Weighted
Range of Number Remaining Average Number Average
Exercise Prices Outstanding Contractual Life Exercise Price Exercisable Exercise Price
- --------------- ------------ ---------------- --------------- -------------- --------------
$11.50 - $15.38 1,122,926 8.6 years $ 12.66 281,343 $ 12.69
$18.13 - $26.38 40,222 2.5 years 23.33 40,222 23.33
$27.50 - $40.00 24,486 3.8 years 33.39 24,486 33.39
------------ --------------
1,187,634 8.3 years 13.53 346,051 15.58
============ ==============
The weighted average fair value of stock options granted in 1996 and 1995
was $5.52 per share and $4.82 per share, respectively. The fair value of each
option grant was estimated on the date of grant using the Black-Scholes option
pricing model with the following weighted-average assumptions used for grants
in 1996 and 1995, respectively: risk-free interest rate of 5.3% and 6.3%;
expected life of four years in each case; expected volatility of 49% and 53%;
and no dividend yield.
PHANTOM STOCK PLAN
In September 1993, the Board of Directors of the Company adopted the Phantom
Stock Plan, which provides key employees of the Company with rewards for past
performance and incentives for future service. These rewards had previously
included restricted units and option units; however, in 1995, all participants
exercised their right to convert outstanding option units to stock options
under the 1994 Plan.
No awards were granted under the Phantom Stock Plan in 1996. Key employees
were granted 650 restricted units and 1,300 option units in 1995 and 5,650
restricted units and 11,300 option units in 1994. In each case, the price for
the option units equaled the fair market value of the Company's common stock on
the date of the awards. The grant price for the restricted units was below
market value.
The restricted units awarded vest at 33 1/3% per year commencing with the
first anniversary of grant. Upon vesting, a participant receives a cash
payment for the difference between the grant price for the restricted units and
the market value of the common stock on the vesting date. Participants do not
receive shares of the Company's common stock under the Phantom Stock Plan. The
Company recognizes compensation expense ratably over the vesting period of the
F-16
47
restricted units for the difference between the grant price and the then-market
value of the common stock. The amounts of cash paid to participants and
compensation expense recognized were immaterial in all three reporting periods.
(11) RELATED-PARTY TRANSACTIONS
NOTES RECEIVABLE FROM OFFICERS
At December 31, 1995, the Company held $66,000 of notes receivable from
executive officers of the Company. The Company provided loans to the executive
officers to purchase a portion of certain restricted common stock issued in
1993. The notes bore interest at 3.9% and were repaid in October 1996.
NEW YORK LIFE
Until the fourth quarter of 1996, New York Life had been a major stockholder
of the Company, owning almost 10% of American's voting stock. As of December
31, 1996, New York Life owned approximately 4.5% of American's voting stock.
Since 1983, New York Life had been a substantial investor in each of the
Company's APPL Programs, providing 35% of the amount committed by co-investors.
In conjunction with the APPL Consolidation, New York Life sold certain of its
APPL Program interests to the Company and transferred its remaining interests
to Ancon. See Note 3 for information regarding American's acquisition of New
York Life's interests in Ancon during December 1996.
New York Life contributed net assets to Ancon totaling $56.7 million in
1995, consisting primarily of its remaining APPL Program interests. American
acquired a 20% interest in these net assets for cash consideration of $6.7
million. No properties were contributed to the partnership in 1996 or 1994.
Capital contributions by New York Life to Ancon for development activity
totaled $813,000 in 1994. No capital contributions were made for development
activity in 1996 or 1995.
During the period 1985-1992, the Company and a subsidiary of New York Life,
as co-general partners, formed the NYLOG Programs, which were sold to the
public by New York Life agents and independent broker-dealers. See Note 4 for
a discussion of the liquidation of the NYLOG Programs.
In April 1994, New York Life extended to the Company a $40 million bridge
facility in connection with the APPL Consolidation. American paid interest,
commitment fees and financing fees on this facility totaling $1.6 million in
1994. In February 1995, the Company refinanced the $31.1 million outstanding
balance under this facility using excess borrowing capacity under the Credit
Agreement.
INVESTMENT PROGRAMS
The Company was the operator of certain properties owned by the NYLOG
Programs, the APPL Programs and Ancon and, accordingly, charged technical fees
to these entities. The Company was also reimbursed for costs incurred in
managing the operations of these entities. Administrative and technical fees
charged by the Company to the investment programs and Ancon totaled $3.4
million, $3.9 million and $7.6 million for 1996, 1995 and 1994, respectively.
Such fees included fees charged to the APPL Programs, which were consolidated
into American's operations during 1994 and early 1995.
OTHER TRANSACTIONS
Legal fees incurred for services provided by a law firm in which a partner
was a director of the Company until June 1995 totaled $285,000 and $377,000 in
1995 and 1994, respectively.
F-17
48
(12) INCOME TAXES
The Company reported a loss before income taxes totaling $8.3 million in
1996, which related entirely to domestic operations. The Company's income tax
provision (benefit) for the years ended December 31, 1996, 1995 and 1994 is
detailed below (in thousands):
Year Ended December 31,
--------------------------------------------
1996 1995 1994
---------- ---------- ----------
Current:
Federal . . . . . . . . . . . . . . . . . . . . $ - $ 58 $ -
State . . . . . . . . . . . . . . . . . . . . . 9 (18) 39
---------- ---------- ----------
9 40 39
- ---------- ----------
Deferred:
Federal . . . . . . . . . . . . . . . . . . . . - - -
State . . . . . . . . . . . . . . . . . . . . . 272 (161) (494)
---------- ---------- ----------
272 (161) (494)
----------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . $ 281 $ (121) $ (455)
========== ========== ==========
The difference between the provision (benefit) for income taxes and the
amount that would be determined by applying the statutory federal income tax
rate to income (loss) before income taxes and extraordinary items for the years
ended December 31, 1996, 1995 and 1994 is analyzed below (in thousands):
Year Ended December 31,
--------------------------------------------
1996 1995 1994
---------- ---------- ----------
Income (loss) before income taxes
and extraordinary item . . . . . . . . . . . . . $ (8,324) $ 1,356 $ (60,690)
========== ========== ==========
Income tax provision (benefit)
at the statutory rate . . . . . . . . . . . . . $ (2,913) $ 475 $ (21,242)
Change in valuation allowance . . . . . . . . . . . (30) (75) 22,203
Federal alternative minimum tax . . . . . . . . . . - 58 -
State income tax . . . . . . . . . . . . . . . . . 9 (18) 39
Revision of prior estimated tax basis of
properties sold . . . . . . . . . . . . . . . . 4,424 - -
Other . . . . . . . . . . . . . . . . . . . . . . . (1,209) (561) (1,455)
---------- ---------- ----------
Income tax provision (benefit) . . . . . . . $ 281 $ (121) $ (455)
========== ========== ==========
F-18
49
The Company's deferred income tax liability at December 31, 1996 and 1995 is
comprised of the tax benefit (cost) associated with the following items (in
thousands):
December 31,
---------------------------
1996 1995
---------- ----------
Deferred tax asset:
Net operating loss carryforwards . . . . . . . . . . . . . . . . $ 98,553 $ 95,869
State income tax . . . . . . . . . . . . . . . . . . . . . . . . 2,701 2,790
Investment tax credit carryforwards . . . . . . . . . . . . . . 1,857 1,873
Minimum tax carryforwards . . . . . . . . . . . . . . . . . . . 479 559
---------- ----------
Gross deferred tax asset . . . . . . . . . . . . . . . . . . 103,590 101,091
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . (93,116) (93,146)
---------- ----------
10,474 7,945
---------- ----------
Deferred tax liability:
Acquisition, exploration and development costs . . . . . . . . . (10,474) (7,945)
State income tax . . . . . . . . . . . . . . . . . . . . . . . . (447) (175)
---------- ----------
Gross deferred tax liability . . . . . . . . . . . . . . . . (10,921) (8,120)
---------- ----------
Net deferred tax liability . . . . . . . . . . . . . . . . . . . . $ (447) $ (175)
========== ==========
As of December 31, 1996, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately $281
million. Unless utilized, approximately 73% of this amount will expire in the
next five years. Included in the total NOLs are approximately $71.5 million
that arose through an acquisition completed in 1987, and $143.7 million that
arose through the acquisition of Conquest Exploration Company in 1991. These
acquired NOLs may be used to offset the respective subsidiaries' taxable income
subject to individual annual and cumulative limits. In addition to the
individual limitations, changes in the Company's ownership in 1996 have
resulted in an overall limitation on the amount of benefit to be realized from
the NOL in the amount of approximately $9.6 million annually. Any unused
portion of the benefit is carried forward. The Company's $2.7 million state
tax deferred asset is primarily the result of separate company NOLs in
individual states. The Company also has investment tax credit carryforwards of
approximately $1.9 million, which expire in the amount of approximately $11,000
annually through 1998 and will be fully expired by 2001. The Company has an
alternative minimum tax credit carryforward of approximately $479,000 that does
not expire and is available to offset regular income taxes in future years, but
only to the extent that regular income taxes exceed the alternative minimum tax
in such years.
The deferred tax asset valuation allowance of $93.1 million reflects the
amounts for which utilization of the asset is not assured due to the expiration
of NOLs and the effects of future drilling costs.
(13) FINANCIAL INSTRUMENTS
DERIVATIVES
The Company uses derivative financial instruments solely to manage the risk
associated with fluctuations in oil and gas prices. The following table
details the commodity price swap agreements in effect at December 31, 1996.
Average
Product Contract Period Daily Production Fixed Price Market Price Reference
- ------- ---------------------------------- ----------------- ------------ ------------------------
Gas June 1996 - May 1997 20,000 MMBtu $ 1.86 Houston Ship Channel
Gas May 1996 - April 1997 2,000 MMBtu 2.13 Henry Hub
Oil January 1996 - December 1996 1,000 barrels 17.00 NYMEX WTI
Oil April 1996 - March 1997 400 barrels 18.22 NYMEX WTI
Oil July 1996 - December 1996 2,000 barrels 17.80 NYMEX WTI
Oil January 1997 - December 1997 3,000 barrels 19.48 NYMEX WTI
F-19
50
With regard to the production hedged under the commodity price swap
agreements, if the market price is above the fixed price, the Company will pay
to the counterparty the difference between the fixed price and the market
price; and if the market price is below the fixed price, the Company will
receive that difference from the counterparty.
Also, the Company purchased put options for 2,000 MMBtu per day of gas with
an average floor price of $1.90 per MMbtu (based on the Tennessee Gas Pipeline
Co., Louisiana and Offshore reference prices) for the period from April 1996
through April 1997.
Additionally, the Company has entered into a commodity price collar
transaction for 10,000 MMBtu per day of gas for the period from January through
December 1997. With regard to the production hedged under the commodity price
collar, if the market price is above the cap strike price of $2.65 per MMBtu,
the Company will pay to the counterparty the difference between the cap strike
price and the market price; and if the market price is below the floor strike
price of $2.00 per MMBtu, the Company will receive that difference from the
counterparty. The market price reference for this transaction is based on the
NYMEX natural gas futures contract.
The Company is exposed to credit loss in the event of nonperformance by the
other party to each hedging agreement. However, the Company anticipates that
each counterparty will be able to fully satisfy its obligation under each
agreement.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying values and estimated fair values
of the Company's financial instruments at December 31, 1996 (in thousands):
Carrying Fair
Value Value
---------- ----------
Long-term debt (a) . . . . . . . . . . . . . . . . . $ (60,000) $ (60,000)
Commodity price hedging agreements (b) . . . . . . . (1,389) (7,600)
_______________
(a) Fair value equals carrying value for the Company's long-term debt.
(b) The carrying value primarily represents an accrued liability of
approximately $1.4 million related to the Company's loss on commodity
price swap agreements in effect for December production. The fair
value of the hedging agreements represents the estimated amount the
Company would pay to terminate all of the agreements at December 31,
1996, based on the closing prices for NYMEX futures contracts on the
last trading date in December. Such prices ranged from $20.81 to
$26.57 per barrel of oil and from $2.06 to $4.00 per MMBtu of gas, with
the highest prices indicated for January 1997 production. Management
believes that the Company's risk of loss on the hedging agreements due
to inflated market reference prices in 1997 will be mitigated by the
receipt of actual cash prices in excess of the fixed price under the
hedging agreements.
The carrying amounts of cash and cash equivalents, trade receivables and
trade payables approximate fair value because of the short maturity of these
instruments.
F-20
51
(14) COMMITMENTS AND CONTINGENCIES
OPERATING LEASES
The Company has entered into operating leases, primarily for office space,
which expire over the next five years. These operating leases frequently
include renewal options at the then-fair rental value and require that the
Company pay a pro rata share of executory costs (including taxes, maintenance
and utility expenses) incurred by the landlord. Future minimum payments under
all noncancelable operating lease obligations, including an estimated pro rata
share of operating expenses, as of December 31, 1996 are as follows (in
thousands):
1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,549
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,737
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,737
2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,737
2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,597
----------
Total minimum lease payments . . . . . . . . . . . . . . . . . . 12,357
Total minimum sublease rentals . . . . . . . . . . . . . . . . . (1,473)
----------
Net minimum lease payments . . . . . . . . . . . . . . . . . . . $ 10,884
==========
Rent expense totaled $2.6 million, $2.7 million and $3.9 million in 1996,
1995 and 1994, respectively, which includes the Company's share of executory
costs associated with its office leases. Sublease rentals received during the
past three years were not material.
DRILLING COMMITMENTS
In December 1996, the Company entered into a joint venture with Tom Brown
Inc. to explore for oil and gas on certain acreage in the Cotton Valley. Under
the terms of the exploration agreement, the Company is committed to expend a
minimum of $1.6 million for the drilling of two exploratory wells that are
expected to be drilled in the third and fourth quarters of 1997.
CONCENTRATION OF RISKS
American's revenues are derived principally from uncollateralized sales of
the Company's oil and gas production to customers in the oil and gas industry.
Market prices for oil and gas may fluctuate; accordingly, decreases in market
prices could adversely affect American's net operating revenues and cash flows
from operating activities. In addition, the concentration of credit risk in a
single industry affects the Company's overall exposure to credit risk because
customers may be similarly affected by changes in economic and other
conditions. The Company has not experienced significant credit losses on such
receivables.
In the year ended December 31, 1996, sales to Enron Corp. and certain
subsidiaries of KN Energy, Inc. accounted for approximately 26% and 13%,
respectively, of the Company's oil and gas revenues. Because of the
availability of other customers, management does not believe that the loss of
any single customer would adversely affect the Company's operations.
LEGAL PROCEEDINGS
The Company is a party to certain legal proceedings arising in the ordinary
course of its oil and gas business. Although the Company cannot predict the
outcome of such proceedings with certainty, the Company does not expect the
outcome of these proceedings, either individually or in the aggregate, to have
a material adverse impact on its financial position. In addition, the Company
is involved in the following matters:
BOWDOIN FIELD, PHILLIPS AND VALLEY COUNTIES, MONTANA. In February 1995,
two Company affiliates were served with a lawsuit styled KN Gas Supply
Services, Inc. v. American Production Partnership-V, Ltd. and Ninian Oil
Finance
F-21
52
Corp., filed in United States District Court in Denver, Colorado, requesting
declaratory judgment that KN Gas Supply Services, Inc. ("KNGSS") had the right
to reduce the contract price for gas produced from the Bowdoin Field to market
levels from October 1, 1993 forward. KNGSS also requested declaratory judgment
that it has a right to relief from the contract price due to regulatory
changes, which it alleges renders the contract commercially impracticable, and
that Federal Energy Regulatory Commission Order No. 636 is a condition
subsequent which excuses performance under the contract. In April 1995, the
Company filed counterclaims against KNGSS relating to the failure of KNGSS to
take and pay for certain minimum volumes of gas, among other contractual
matters. The Company has dismissed all of its counterclaims, and KNGSS has
dismissed its commercially impracticable and condition subsequent claims.
KNGSS alleges that it has overpaid the Company's affiliates and seeks a refund
of approximately $7.7 million for the period through September 1996. A Motion
for Summary Judgment was filed by the Company in July 1996 and was argued
before the court on February 14, 1997. Although the Company cannot predict the
outcome of this proceeding, American will vigorously defend its interests in
this case and does not expect the outcome of the case to have a material
adverse impact on its financial position or results of operations.
PUBLIC PARTNERSHIP LITIGATION. The Company and its subsidiary, American
Exploration Production Company ("AEPCO" and, together with the Company, the
"American Parties"), along with New York Life and several of its subsidiaries,
were named as defendants in a class action complaint filed in the United States
District Court for the Southern District of Florida on March 18, 1996, styled
Shea et al. v. New York Life Insurance Co., et al. (Civil Action No. 96-0746),
alleging generally that the defendants engaged in fraudulent activities in
connection with the marketing and sale of interests in, and the subsequent
operation of, various limited partnerships, breached implied covenants and
fiduciary duties and violated various federal securities and state laws and
rules. A subsidiary of New York Life ("NYLIFE") agreed to indemnify the
American Parties from and against any and all judgments or settlements entered
or reached in this litigation and certain related litigation, or any subsequent
lawsuits by investors in the NYLOG Programs based on substantially similar
claims and factual allegations. The defendants expressly denied any wrongdoing
alleged in the complaints and conceded no liability or wrongdoing.
Nevertheless, to reduce the burden of protracted litigation, the defendants
entered into a Stipulation of Settlement (the "Settlement Agreement") with the
approval of the Florida court, providing for the liquidation of the NYLOG
Programs and the release and discharge of the defendants and various other
related parties. Because the time for any appeal of the settlement has
elapsed, the judgment approving the settlement is final. Pursuant to the
Settlement Agreement, each limited partner of a limited partnership who
participated in the settlement received from an affiliate of New York Life a
cash payment that, together with prior distributions to such settling limited
partner from such limited partnership, resulted in the settling limited partner
receiving in the aggregate an amount at least equal to his total investment in
such partnership. In July 1996, the limited partners of the NYLOG Programs
approved the liquidation of the partnerships, and the liquidating sales of
substantially all of the properties held by the NYLOG Programs were completed
during the fourth quarter of 1996. The Company expects to complete the
liquidation and dissolution of the NYLOG Programs in the second quarter of
1997. (See Note 4.)
New York Life and certain of its subsidiaries and AEPCO were also named as
defendants in a lawsuit relating to the NYLOG Programs styled Billy H. Mancil
and Mary M. Mancil v. New York Life Insurance Company, et al., Civil Action No.
CV-95-2595 GR, Circuit Court of Montgomery County, Alabama (the "Mancil
Litigation"). The complaint in the Mancil Litigation alleged various causes of
action arising out of Mancil's purchase of interests in certain NYLOG Programs
including, among other things, fraud, reckless and negligent
misrepresentations, and negligence in hiring, training and/or supervising a
sales agent involved in the sale of the NYLOG interests. Plaintiffs sought an
unspecified amount of compensatory and punitive damages and costs. By letter
dated January 21, 1997, the plaintiffs advised the court that the Mancil
Litigation had been settled with all defendants. The Mancil Litigation is
covered by the indemnification agreement described in the foregoing paragraph.
F-22
53
(15) CASH FLOW INFORMATION
Supplemental cash flow information is presented below (in thousands):
Year Ended December 31,
-----------------------------------------
1996 1995 1994
--------- ---------- ----------
Cash Payments:
- -------------
Interest, net of amounts capitalized (a) . . . . . . . . . $ 4,196 $ 5,638 $ 6,528
Income taxes . . . . . . . . . . . . . . . . . . . . . . . 9 40 39
Noncash Investing and Financing Activities:
- ------------------------------------------
APPL Consolidation:
Acquisition of oil and gas properties . . . . . . . . . $ - $ 1,198 $ 52,222
Other assets acquired . . . . . . . . . . . . . . . . . - - 2,287
Liabilities assumed . . . . . . . . . . . . . . . . . . - - 535
Debt retired . . . . . . . . . . . . . . . . . . . . . - 4,680 1,612
American common stock issued . . . . . . . . . . . . . - (4,326) (56,230)
Gain on extinguishment of debt . . . . . . . . . . . . - (1,552) (426)
_______________
(a) The Company capitalized interest totaling $1.9 million in 1996 and $1.5
million in each of the years 1995 and 1994, based on the Company's
weighted average bank borrowing rate for the period.
(16) INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
The Company's only industry segment is oil and gas exploration and
production. The Company has not conducted any foreign operations since 1993;
however, the Company recorded a $6.4 million impairment charge in 1994 to write
off its remaining leasehold interests in Tunisia which were sold during that
year. In 1994, the Company also reported an impairment charge of $25 million
related to a change in accounting policy for impairment of proved oil and gas
properties. (See Note 1.) Information regarding the Company's operations by
geographic area for 1994 is presented below (in thousands):
United States Foreign Consolidated
--------------- ------------- -------------
Year Ended December 31, 1994
- ----------------------------
Sales to unaffiliated customers . . . . . . . . . . $ 50,033 $ - $ 50,033
Loss from operations . . . . . . . . . . . . . . . . (44,727) (6,706) (51,433)
Identifiable assets . . . . . . . . . . . . . . . . 223,894 - 223,894
F-23
54
(17) QUARTERLY RESULTS - (UNAUDITED)
(In thousands, except for per share data) First Second Third Fourth
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
Year Ended December 31, 1996 (a)
- --------------------------------
Oil and gas sales . . . . . . . . . . . . . . . . $ 15,913 $ 17,260 $ 19,090 $ 23,965
Income (loss) from operations . . . . . . . . . . 592 (3,355) (51) (982)
Net loss . . . . . . . . . . . . . . . . . . . . . (215) (4,312) (1,244) (2,834)
Net loss per common share . . . . . . . . . . . . $ (.06) $ (.40) $ (.14) $ (.23)
Year Ended December 31, 1995 (b)
- --------------------------------
Oil and gas sales . . . . . . . . . . . . . . . . $ 17,832 $ 20,327 $ 16,890 $ 15,719
Income (loss) from operations . . . . . . . . . . 1,308 2,897 7,263 (4,655)
Income (loss) before extraordinary item . . . . . (495) 990 6,015 (5,033)
Net income (loss) . . . . . . . . . . . . . . . . 1,961 990 6,015 (5,033)
Net income (loss) per common share:
Income (loss) before extraordinary item . . . . $ (.08) $ .05 $ .47 $ (.46)
Extraordinary gain on extinguishment of debt. . .21 - - -
---------- ---------- ---------- ----------
Net income (loss) per common share . . . . . . $ .13 $ .05 $ .47 $ (.46)
========== ========== ========== ==========
_______________
(a) The Company conducted an active exploration program during 1996.
Quarterly net losses of varying amounts in 1996 were primarily
attributable to the varying number of unsuccessful exploratory wells
for which dry hole expense had been recorded during the quarter.
(b) In the first quarter of 1995, the Company recorded an extraordinary
gain of $2.5 million resulting from the elimination of debt through
the APPL Consolidation. In the third quarter of 1995, the Company
recorded a gain on the Sawyer Sale of approximately $10.6 million,
offset in part by recognition of $2.8 million of dry hole expense on
two wells. In the fourth quarter of 1995, the Company recorded an
impairment charge of $1.8 million related to the impairment of an
unproved property and recorded additional dry hole expense of $1.3
million primarily related to one offshore well.
Quarterly earnings per common share are based on the weighted average
number of shares outstanding during the quarter, and the sum of the quarters
may not equal annual earnings per common share. Earnings per common share have
been retroactively restated to reflect the Reverse Stock Split. (See Note 2.)
F-24
55
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
CAPITALIZED COSTS
(In thousands) December 31,
--------------------------
1996 1995
---------- ----------
Proved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 323,266 $ 265,953
Unproved oil and gas interests . . . . . . . . . . . . . . . . . . . . . . . . 33,360 26,074
---------- ----------
Total capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . 356,626 292,027
Less: Accumulated depreciation, depletion and amortization . . . . . . . 149,428 146,188
---------- ----------
Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 207,198 $ 145,839
========== ==========
COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
(In thousands) Year Ended December 31,
-----------------------------------------
1996 1995 1994
---------- ---------- ----------
Property acquisition costs:
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . $ 67,872 $ 14,491 $ 81,385
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . 9,903 2,642 -
Exploration costs . . . . . . . . . . . . . . . . . . . . . . 26,745 2,449 2,583
Development costs . . . . . . . . . . . . . . . . . . . . . . 15,648 23,089 15,804
Capitalized interest . . . . . . . . . . . . . . . . . . . . . 1,939 1,468 1,496
---------- ---------- ----------
Total costs incurred . . . . . . . . . . . . . . . . . . . $ 122,107 $ 44,139 $ 101,268
========== ========== ==========
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
(In thousands) Year Ended December 31,
-----------------------------------------
1996 1995 1994
---------- ---------- ----------
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 76,228 $ 70,768 $ 50,033
Production and operating costs . . . . . . . . . . . . . . . . . . 25,681 29,443 25,932
Exploration expense, including impairments (a) . . . . . . . . . . 18,834 6,648 11,129
Depreciation, depletion and amortization . . . . . . . . . . . . . 27,879 29,100 28,062
Writedown of oil and gas properties . . . . . . . . . . . . . . . - - 25,000
Income tax provision (benefit) . . . . . . . . . . . . . . . . . . 281 (121) (455)
---------- ---------- ----------
Results of operations for oil and gas producing activities. . . $ 3,553 $ 5,698 $ (39,635)
========== ========== ==========
_______________
(a) Exploration expense for 1994 included a $6.4 million impairment charge
to write off the Company's remaining leasehold interests in Tunisia.
No foreign operations have been conducted by the Company since 1993.
F-25
56
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (CONTINUED)
OIL AND GAS RESERVE INFORMATION - (UNAUDITED)
The following information summarizes the policies used by the Company
in preparing the accompanying oil and gas reserve disclosures, standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves and the reconciliation of such standardized measure from period to
period.
Proved reserves are estimated quantities of crude oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic
and operating conditions. Proved developed reserves are proved reserves that
can reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
The standardized measure of discounted future net cash flows from
production of proved reserves was developed by first estimating the quantities
of proved reserves and the future periods during which they are expected to be
produced based on year-end economic conditions. The estimated future cash
flows from proved reserves were then determined based on year-end prices,
except in those instances where fixed and determinable price escalations are
included in existing contracts. The effect of derivative transactions on oil
and gas prices as of December 31, 1996 was not material. Finally, future cash
flows were reduced by estimated production costs, costs to develop and produce
the proved reserves, and certain abandonment costs, all based on year-end
economic conditions and the estimated effect of future income taxes based on
the current tax law.
The Company's estimated future net cash flows from proved oil and gas
reserves as of December 31, 1996 were significantly impacted by higher oil and
gas prices at the end of 1996 than in recent years. The prices used in
calculating the estimated future net revenue attributable to proved reserves do
not necessarily reflect market prices for oil and natural gas production
subsequent to December 31, 1996. There can be no assurance that the assumed
prices will actually be realized for such production.
The standardized measure of discounted future net cash flows does not
purport to present, nor should it be interpreted to present, the fair value of
the Company's oil and gas reserves. An estimate of fair value would also take
into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
Reference is made to Note 14 to the Consolidated Financial Statements
for information regarding certain litigation concerning the Bowdoin Field.
RESERVE QUANTITY INFORMATION
(UNAUDITED)
December 31,
---------------------------------------------------------------------------
1996 1995 1994
--------------------- ---------------------- ---------------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
-------- -------- -------- --------- -------- ---------
PROVED RESERVES
- ---------------
Balance at beginning of year . . . . 10,464 126,014 9,660 186,680 5,895 104,723
Purchases of minerals in place 4,555 45,333 1,225 18,846 5,153 108,075
Extensions, discoveries and
other additions . . . . . . . . 885 21,231 1,435 17,318 128 12,825
Revisions of previous estimates. . 1,853 9,085 616 1,270 (197) (22,467)
Sales of minerals in place . . . . (1,584) (11,883) (792) (73,650) (78) (235)
Production . . . . . . . . . . . . (1,789) (22,369) (1,680) (24,450) (1,241) (16,241)
-------- -------- -------- --------- -------- ---------
Balance at end of year . . . . . . . 14,384 167,411 10,464 126,014 9,660 186,680
======== ======== ======== ========= ======== =========
PROVED DEVELOPED RESERVES
- -------------------------
Balance at end of year . . . . . . . 10,117 142,261 9,474 98,590 8,697 127,838
======== ======== ======== ========= ======== =========
F-26
57
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
(UNAUDITED)
(In thousands) Year Ended December 31,
---------------------------------------------
1996 1995 1994
----------- ----------- ------------
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . $ 930,456 $ 454,508 $ 502,989
Future production and development costs . . . . . . . . . . . . . (324,991) (209,094) (258,711)
----------- ----------- ------------
Future net cash flows before income taxes . . . . . . . . . . . . 605,465 245,414 244,278
Future income taxes . . . . . . . . . . . . . . . . . . . . . . . (51,178) (2,892) (2,109)
----------- ----------- ------------
Future net cash flows after income taxes . . . . . . . . . . . . 554,287 242,522 242,169
Discount at 10% annual rate . . . . . . . . . . . . . . . . . . . (188,458) (98,628) (101,463)
----------- ----------- ------------
Standardized measure of discounted future net cash flows . . . . $ 365,829 $ 143,894 $ 140,706
=========== =========== ============
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(UNAUDITED)
(In thousands) Year Ended December 31,
---------------------------------------------
1996 1995 1994
----------- ----------- ------------
Balance, beginning of year . . . . . . . . . . . . . . . . . . . $ 143,894 $ 140,706 $ 103,270
Sales and transfers of oil and gas produced, net of . .
production costs . . . . . . . . . . . . . . . . . . . . . . . (50,547) (41,325) (24,101)
Net changes in prices and production costs . . . . . . . . . . . 80,346 9,959 (67,753)
Extensions, discoveries and improved recoveries, net of future. .
production and development costs . . . . . . . . . . . . . . . 39,072 22,867 3,822
Purchases of minerals in place . . . . . . . . . . . . . . . . . 156,746 15,162 115,379
Sales of minerals in place . . . . . . . . . . . . . . . . . . . (21,612) (33,672) (451)
Changes in estimated future development costs . . . . . . . . . . (997) 3,222 4,997
Development costs incurred during the year . . . . . . . . . . . 3,588 11,592 11,518
Revisions of previous quantity estimates . . . . . . . . . . . . 28,914 3,857 (7,826)
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . 14,616 14,230 10,476
Net change in future income taxes . . . . . . . . . . . . . . . . (17,896) (444) 117
Changes in production rates (timing) and other . . . . . . . . . (10,295) (2,260) (8,742)
----------- ------------ ------------
Balance, end of year . . . . . . . . . . . . . . . . . . . . . . $ 365,829 $ 143,894 $ 140,706
=========== =========== ============
F-27
58
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
American Exploration Company Stock Compensation Plan, effective December 9,
1988 (Form S-8, September 21, 1989, Registration No. 31-31202, Exhibit 4(c)).
American Exploration Company Amended and Restated 1978 Hershey Oil Corporation
Non-Qualified Equity Participation Plan (Form S-4, August 8, 1990, Registration
No. 33-36268, Exhibit 10(ccc)).
American Exploration Company Amended and Restated 1983 Stock Option Plan of
Hershey Oil Corporation (Form S-4, August 8, 1990, Registration No. 33-36268,
Exhibit 10(ddd)).
American Exploration Company Amended and Restated 1988 Stock Option Plan of
Hershey Oil Corporation (Form S-4, August 8, 1990, Registration No. 33-36268,
Exhibit 10(eee)).
Phantom Stock Plan of American Exploration Company, effective September 21,
1993 (Form 10-Q, September 30, 1993, Exhibit 10(b)).
American Exploration Stock Compensation Plan, effective June 13, 1995 (Proxy
Statement, May 10, 1995, Appendix A).
Employment Agreement between American Exploration Company and Mark Andrews,
effective November 30, 1995. (Form 10-K, December 31, 1995, Exhibit 10(dd)).
Severance Agreements between American Exploration Company and the executive
officers of American Exploration Company, effective November 30, 1995.
(Form 10-K, December 31, 1995, Exhibit 10(ee)).
Incentive Bonus Plan (1997).
Amendment to the American Exploration Company Stock Compensation Plan
(Effective as of November 1, 1996).
Amendment to the 1994 American Exploration Company Stock Compensation Plan
(Effective as of November 1, 1996).
X-1
59
INDEX OF EXHIBITS
*3(a) - Restated Certificate of Incorporation of American
Exploration Company, as supplemented by Certificate of
Amendment to Restated Certificate of Incorporation of
American Exploration Company, effective June 13, 1995
(Form 10-K, December 31, 1995, Exhibit 3(a)).
*3(b) - Amended and Restated Bylaws of American Exploration
Company (Form 10-K, December 31, 1995, Exhibit 3(b)).
*4(a) - Rights Agreement, dated as of September 28, 1993, between
American Exploration Company and Society National Bank
(Form 8-K, September 28, 1993, Exhibit 4), as
supplemented by Amendment to Rights Agreement, dated as
of August 3, 1994, between American Exploration Company
and Society National Bank (Form 8-K, August 31, 1994,
Exhibit 4).
*4(b) - Certificate of Designation of the $450 Cumulative
Convertible Preferred Stock, Series C, dated December 14,
1993 (Form S-3, January 4, 1994, Registration No.
33-51795, Exhibit 4.3), as supplemented by Certificate of
Correction to the Certificate of Designation of the $450
Cumulative Convertible Preferred Stock, Series C, dated
December 29, 1993 (Form S-3, January 4, 1994,
Registration No. 33-51795, Exhibit 4.4).
*4(c) - Deposit Agreement, dated as of December 10, 1993, by and
among American Exploration Company, Harris Trust and
Savings Bank and the holders from time to time of
Depositary Receipts (Form S-3, January 4, 1994,
Registration No. 33-51795, Exhibit 4.5).
*4(d) - Purchase Agreement, dated as of December 10, 1993, by and
among American Exploration Company and each of the
purchasers referred to therein (Form S-3, January 4,
1994, Registration No. 33-51795, Exhibit 4.6).
*4(e) - Registration Rights Agreement, dated as of December 17,
1993, by and among American Exploration Company and each
of the purchasers referred to therein (Form S-3, January
4, 1994, Registration No. 33-51795, Exhibit 4.7).
*4(f) - Form of Stock Certificate representing shares of
Convertible Preferred Stock (Form 8-A, March 23, 1994,
Exhibit 8).
*4(g) - Form of Depositary Receipt representing Depositary Shares
(Form 8-A, March 23, 1994, Exhibit 9).
*10(a) - Forms of New York Life Oil & Gas Production Partnership
Agreements (Amendment No. 4 to Form S-2, January 21,
1988, Registration No. 33-18512, Exhibit 10(gg)).
*10(b) - American Exploration Company Stock Compensation Plan,
effective December 9, 1988 (Form S-8, September 21,
1989, Registration No. 31-31202, Exhibit 4(c)).
*10(c) - American Exploration Company Amended and Restated 1978
Hershey Oil Corporation Non-Qualified Equity
Participation Plan (Form S-4, August 8, 1990,
Registration No. 33-36268, Exhibit 10(ccc)).
*10(d) - American Exploration Company Amended and Restated 1983
Stock Option Plan of Hershey Oil Corporation (Form S-4,
August 8, 1990, Registration No. 33-36268, Exhibit
10(ddd)).
X-2
60
INDEX OF EXHIBITS - (CONTINUED)
*10(e) - American Exploration Company Amended and Restated 1988
Stock Option Plan of Hershey Oil Corporation (Form S-4,
August 8, 1990, Registration No. 33-36268, Exhibit
10(eee)).
*10(f) - Office Lease, dated December 12, 1990, between
JMB/Houston Center Partners Limited Partnership and
American Exploration Company (Form S-4, January 9, 1991,
Registration No. 33-38546, Exhibit 10(kkk)).
*10(g) - Master Exchange Agreement, dated as of February 1, 1991,
between American Exploration Company and Morgan Guaranty
Trust Company of New York (Form 10-Q, March 31, 1991,
Exhibit 10(a)).
*10(h) - Note Purchase Agreement, dated as of December 27, 1991,
re: $35,000,000 11% Senior Subordinated Notes due
December 30, 2001 (Form 8-K, January 10, 1992, Exhibit
10(a)), as supplemented by the Amendment to Note Purchase
Agreement, dated as of February 16, 1993, by and among
American Exploration Company (the "Company") and the
parties named therein (Form 8-K, February 16, 1993,
Exhibit 10(a)), as supplemented by letter agreement,
dated March 22, 1993, by and among the Company and the
parties named therein (Form 10-K, December 31, 1992,
Exhibit 10(zz)), as supplemented by Second Amendment to
Note Purchase Agreement, dated as of September 30, 1993,
by and among the Company and the parties named therein
(Form 10-Q, September 30, 1993, Exhibit 10(c)), as
supplemented by Third Amendment to Note Purchase
Agreement, dated as of March 18, 1994, by and among the
Company and the parties named therein (Form 10-K,
December 31, 1993, Exhibit 10(tt)), as supplemented by
Fourth Amendment to Note Purchase Agreement, dated as of
April 28, 1994, by and among the Company and the parties
named therein (Form 10-Q, March 31, 1994, Exhibit 10(c)),
as supplemented by Fifth Amendment to Note Purchase
Agreement, dated as of July 26, 1994, by and among the
Company and the parties named therein (Form 10-Q,
September 30, 1994, Exhibit 10(c)), as supplemented by
Sixth Amendment to Note Purchase Agreement, dated as of
September 12, 1996, by and among the Company and the
parties named therein (Form 8-K, September 18, 1996,
Exhibit 10(b)).
*10(i) - Warrant Purchase Agreement and Form of Warrants, dated as
of December 27, 1991 (Form 8-K, January 10, 1992,
Exhibit 10(b)), as supplemented by Amendment No. 1 to
Warrant Purchase Agreement, dated as of February 16,
1993, by and among American Exploration Company and the
parties named therein (Form 8-K, February 16, 1993,
Exhibit 10(b)), as supplemented by Amendment No. 2 to
Warrant Purchase Agreement, dated as of September 12,
1996 (Form 8-K, September 18, 1996, Exhibit 10(c)).
*10(j) - Stock Purchase Agreement, dated as of September 3, 1992,
between American Exploration Company and The Prudential
Insurance Company of America (Form 8-K, September 3,
1992, Exhibit 10(a)).
*10(k) - Stock Purchase Warrant, dated as of September 3, 1992,
between American Exploration Company and The Prudential
Insurance Company of America (Form 8-K, September 3,
1992, Exhibit 10(b)).
*10(l) - Registration Rights Agreement, dated as of September 3,
1992, between American Exploration Company and The
Prudential Insurance Company of America (Form 8-K,
September 3, 1992, Exhibit 10(c)).
X-3
61
INDEX OF EXHIBITS - (CONTINUED)
*10(m) - Phantom Stock Plan of American Exploration Company,
effective September 21, 1993 (Form 10-Q, September 30,
1993, Exhibit 10(b)).
*10(n) - Agreement of Limited Partnership of Ancon Partnership
Ltd., dated December 10, 1993, by and between American
Exploration Company and NYLIFE Resources, Inc. (Form
10-K, December 31, 1993, Exhibit 10(rr)).
*10(o) - Letter Agreement, dated as of April 1, 1994, re:
$40,000,000 Secured Credit Facility between American
Exploration Company and New York Life Insurance Company
(Form 10-Q, March 31, 1994, Exhibit 10(b)).
*10(p) - Stockholder and Registration Rights Agreements, dated as
of August 1994, between American Exploration Company and
the parties identified on the signature pages thereto
(Form S-1, as amended, October 28, 1996, Registration No.
333-13017, Exhibit 10(ee)).
*10(q) - Stockholder and Registration Rights Agreements, dated as
of November 1994, between American Exploration Company
and the parties identified on the signature pages thereto
(Form S-1, as amended, October 28, 1996, Registration No.
333-13017, Exhibit 10(ff)).
*10(r) - Amended and Restated Credit Agreement, dated as of
December 21, 1994, among American Exploration Company,
the banks listed herein and Morgan Guaranty Trust Company
of New York, as agent, and Bank of Montreal, as co-agent
(Form 10-K, December 31, 1994, Exhibit 10(pp)), as
supplemented by Amendment No. 1 to Amended and Restated
Credit Agreement, dated as of February 16, 1995 (Form 10-
K, December 31, 1994, Exhibit 10(qq)), as supplemented by
Amendment No. 2 to Amended and Restated Credit Agreement,
dated as of May 2, 1995, (Form 10-K, dated December 31,
1995, Exhibit 10(bb)), as supplemented by Amendment No. 3
to Amended and Restated Credit Agreement, dated as of
January 19, 1996, (Form 10-K, dated December 31, 1995,
Exhibit 10(ff)), as supplemented by Amendment No. 4 to
Amended and Restated Credit Agreement, dated as of June
5, 1996, (Form 10-Q, dated June 30, 1996, Exhibit 10(a)),
as supplemented by Amendment No. 5 to Amended and
Restated Credit Agreement, dated as of September 26,
1996, (Form 8-K, dated September 18, 1996, Exhibit
10(d)), as supplemented by Amendment No. 6 to Amended and
Restated Credit Agreement, dated as of October 15, 1996
(Form 10-Q, September 30, 1996, Exhibit 10(a)).
*10(s) - American Exploration Stock Compensation Plan, effective
June 13, 1995 (Proxy Statement, May 10, 1995, Appendix
A).
*10(t) - Purchase and Sale Agreement, dated June 12, 1995, by and
among American Exploration Company and the partnerships
identified on the signature pages hereof, collectively as
Sellers, and Louis Dreyfus Natural Gas Corp., as
Purchaser (Form 10-Q, June 30, 1995, Exhibit 10(a)).
*10(u) - Employment Agreement between American Exploration Company
and Mark Andrews, effective November 30, 1995 (Form 10-K,
December 31, 1995, Exhibit 10(dd)).
*10(v) - Severance Agreements between American Exploration Company
and the executive officers of American Exploration
Company, effective November 30, 1995 (Form 10-K, December
31, 1995, Exhibit 10(ee)).
*10(w) - Agreement dated as of February 15, 1996 by and among
American Exploration Company, American Exploration
Production Company, NYLIFE Inc., and NYLIFE Securities
Inc. (Form S-1, as amended, October 28, 1996,
Registration No. 333-13017, Exhibit 10(dd)).
X-4
62
INDEX OF EXHIBITS - (CONTINUED)
*10(x) - Purchase and Sale Agreement, dated March 15, 1996, by and
among American Exploration Company and Dominion
Resources, Inc., collectively as buyers, and a private
company, as Seller (Form 8-K, March 15, 1996, Exhibit
10(a)).
*10(y) - Purchase and Sale Agreement, dated September 27, 1996,
between American Exploration Company, as Purchaser, and
Zilkha Energy Company, as Seller (Form 8-K, September 18,
1996, Exhibit 10(a)).
*10(z) - Letter Agreement, dated as of October 10, 1996 between
American Exploration Company and the parties identified
on the signature pages thereto (Form S-1, as amended,
October 28, 1996, Registration No. 333-13017, Exhibit
10(gg)).
*10(aa) - Purchase and Sale Agreement, dated December 16, 1996, by
and among American Exploration Company, NYLIFE Resources
Inc., New York Life Insurance Company and New York Life
Insurance and Annuity Corporation (Form 8-K, December 20,
1996, Exhibit 10(a)).
10(bb) - Amendment No. 7 to Amended and Restated Credit Agreement,
dated as of October 15, 1996.
10(cc) - Amendment No. 8 to Amended and Restated Credit Agreement,
dated as of March 13, 1997.
10(dd) - Incentive Bonus Plan (1997).
10(ee) - Amendment to the American Exploration Company Stock
Compensation Plan (Effective as of November 1, 1996).
10(ff) - Amendment to the 1994 American Exploration Company Stock
Compensation Plan (Effective as of November 1, 1996).
21 - Subsidiaries of American Exploration Company.
23 - Consent of Independent Public Accountants.
27 - Financial Data Schedule.
______________________
* Incorporated herein by reference.
Note: Copies of Exhibits may be obtained for 30 cents per page, prepaid, by
writing to the Investor Relations Department.
X-5