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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
Commission file number 0-28608
PETSEC ENERGY INC.*
(Exact name of Registrant as specified in its charter)
Nevada
(Jurisdiction of incorporation or organization)
143 Ridgeway Drive, Suite 113 Lafayette, Louisiana
(Address of principal executive offices)
Securities registered or to be registered pursuant to Section
12(b) of the Act.
Title of each Name of each exchange
class on which registered
None None
Securities registered or to be registered pursuant to Section
12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section
15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer's
classes of capital or common stock as of the close of the
period covered by the annual report.
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. _X_
All of the registrant's voting stock is held by affiliates of the registrant.
As of March 25, 1998, there was outstanding 1 share of Common Stock, par value
$1.00 per share, of the registrant.
*Petsec Energy Inc. is a wholly owned operating subsidiary of Petsec Energy Ltd,
a listed Australian public company registered with the Commission as a result of
its public offering of American Depositary Receipts ("ADRs") listed on The
Nasdaq Stock MarketSM (symbol: PSALY). Shareholders and holders of American
Depositary Shares are advised to refer to the filings of Petsec Energy Ltd for
the consolidated results.
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TABLE OF CONTENTS
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Page
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Glossary of Certain Industry Terms.................................................... 3
PART I
Item 1. Description of Business..................................................... 5
Item 2. Description of Properties................................................... 21
Item 3. Legal Proceedings........................................................... 22
Item 4. Submission of Matters to a Vote of Security Holders ........................ 22
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....... 22
Item 6. Selected Financial Data..................................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations..................................................... 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.................. 30
Item 8. Financial Statements and Supplementary Data................................. 30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................ 30
PART III
Item 10. Directors and Executive Officers of the Registrant.......................... 31
Item 11. Executive Compensation...................................................... 33
Item 12. Security Ownership of Certain Beneficial Owners and Management.............. 35
Item 13. Certain Relationships and Related Transactions.............................. 36
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............ 37
Signatures............................................................................ 53
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GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below apply to the indicated terms as used in
this Form 10-K. All volumes of natural gas referred to herein are stated at the
legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and, in most instances, are rounded to the nearest major
multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet
Bcfe. Billion cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production
of oil or natural gas, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Developed acreage. The number of acres that are allocated or assignable
to producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry hole or well. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Gross acreage or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.
Liquids. Crude oil, condensate and natural gas liquids.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
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Mcfe. One thousand cubic feet of gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.
MMS. Minerals Management Service of the United States Department of
the Interior.
MMbtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.
Net acres or net wells. The sum of the fractional working interests
owned in gross acres or gross wells.
OCS. Outer Continental Shelf.
Oil. Crude oil and condensate.
Present value or PV10. When used with respect to oil and natural gas
reserves, the estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future development costs,
using prices and costs in effect as of the date indicated, without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expenses or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore
in another formation from that in which the well has been previously completed.
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Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of costs of
production.
Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.
Working interest or W.I. The operating interest which gives the owner
the right to drill, produce and conduct operating activities on the property and
a share of production.
PART I
ITEM 1 - BUSINESS
GENERAL
The Company is an independent exploration and production company
operating in the shallow waters of the central and western Gulf of Mexico. The
Company is the principal operating subsidiary of Petsec Energy Ltd, "Parent
Company," an Australian public company with ADRs listed on The Nasdaq Stock
MarketSM (symbol: PSALY). Since establishing its Gulf of Mexico operations in
1990, the Company has employed a focused, integrated strategy of exploration and
development to generate substantial increases in reserves, production and cash
flow.
As of December 31, 1997, the Company's estimated net proved reserves were
186.0 Bcfe (approximately 66% of which were attributable to natural gas), with a
PV10 of approximately $256 million.
The Company has a significant base of operations consisting of 100% working
interests in 33 lease blocks and a 43.33% working interest in another lease
block covering a total of 111,334 acres. Currently producing from only 18 of its
lease blocks, the Company has in excess of 40 prospects on its existing acreage
that it intends to drill in the next three to four years. At the March 18, 1998
OCS Louisiana offshore sale the Company was high bidder on seven lease blocks,
five of which are in close proximity to the Company's existing producing leases.
COMPANY STRENGTHS AND BUSINESS STRATEGY
The Company believes that it is well positioned to continue to grow its
reserves, production and cash flow by capitalizing on strengths developed since
inception. These strengths include the experience of its personnel, its large
inventory of drilling prospects defined by 3-D seismic data and the operating
flexibility achieved through 100% ownership of leases. The Company's team of
geologists, geophysicists and engineers has developed an extensive base of
knowledge regarding geophysical processing and interpretation of data, as well
as field operating practices in the Gulf of Mexico, and the Company believes it
is well positioned to evaluate, explore and develop properties in this area.
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The Company has developed a focused, integrated business strategy, which it
believes capitalizes on its strengths and which incorporates the following
elements:
FOCUS ON THE SHALLOW WATERS OF THE GULF OF MEXICO. Each year from the start
of its operations in the Gulf of Mexico, the Company has achieved significant
growth in production and reserves by concentrating its exploration and
development efforts in the shallow federal and state waters (400 feet or less)
in the region. The Company believes that focusing its drilling activities on
properties in a relatively concentrated area in the Gulf of Mexico permits it to
utilize its base of geological, engineering, and production experience in the
region to enhance its drilling results and to minimize finding and development
costs.
CONTROL OF OPERATIONS AND COSTS. Through a strict control over operations
and costs the Company has consistently been able to lower lease operating
expenses and general and administrative expense per unit of production,
concurrent with increases in production. The Company holds 100% working
interests in all but one of its Gulf of Mexico properties, unlike many other
independent energy companies that conduct business through fractional working
interests and non-operated joint ventures. Ownership of large working interests
enables the Company to effectively control expenses, capital allocation, and the
timing and method of exploration and development of its properties. The
geographic focus of the Company allows it to manage a large asset base with a
relatively small number of employees
APPLICATION OF ADVANCED TECHNOLOGIES. The Company relies significantly on
advanced exploration technologies, such as 3-D seismic and time depth migration,
in its lease acquisition assessment and its exploration and development
activities. The Company's geotechnical staff has substantial experience in
analyzing 3-D seismic data, which has enabled the Company to identify multiple
exploration and development prospects in both mature producing fields where
advanced technology has not previously been applied and in unexplored areas.
EXPANSION OF EXPLORATION AND DEVELOPMENT PROSPECTS. The Company intends to
continue to expand its inventory of exploration and development prospects
through an active lease acquisition and exploitation program. The Company
actively participates in OCS and state lease sales to build its inventory of
lease blocks. While the Company intends that competitive lease sales will
continue to be its primary method of building its inventory of lease blocks, it
will also evaluate other opportunities to acquire properties that will
complement the Company's existing reserve base and meet its economic and
investment criteria.
OIL AND GAS RESERVES
The following table sets forth estimated net proved oil and gas reserves of
the Company, the estimated future net revenues before income taxes and the
present value of estimated future net revenues before income taxes related to
such reserves as of June 30, 1994, and 1995 and December 31, 1995, 1996 and
1997. In 1996, the Company changed its fiscal year end from June 30 to December
31, and consequently, the reserves presented below reflect the periods for which
the Company has reserve reports. All information in this Annual Report relating
to estimated net proved oil and gas reserves and the estimated future net cash
flows attributable thereto is based upon reports by Ryder Scott Company,
Petroleum Engineers. All calculations of estimated net proved reserves have been
made in accordance with the rules and regulations of the Securities and Exchange
Commission, and, except as otherwise indicated, give no effect to federal or
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state income taxes otherwise attributable to estimated future net revenues from
the sale of oil and gas. The present value of estimated future net revenues has
been calculated using a discount factor of 10% per annum.
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AS OF JUNE 30, AS OF DECEMBER 31,
--------------------- ------------------------------------
1994 1995 1995 1996 1997
---- ---- ---- ---- ----
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TOTAL NET PROVED:
Gas (MMcf) 12,830 20,327 49,747 73,291 122,149
Oil (MBbls) 2,650 6,881 7,172 8,318 10,641
Total (MMcfe) 28,730 61,613 92,779 123,199 185,995
NET PROVED DEVELOPED:
Gas (MMcf) 12,830 12,003 25,852 43,133 88,199
Oil (MBbls) 2,650 4,076 6,962 6,670 8,430
Total (MMcfe) 28,730 36,459 67,624 83,153 138,779
Estimated future net revenues before
income taxes (in thousands) $44,480 $102,517 $190,703 $372,980 $316,855
Present value of estimated future net
revenues before income taxes (in $34,990 $76,632 $153,648 $308,226 $255,839
thousands)(1)(2)
Standardized measure of discounted
future net cash flows (in $30,122 $65,136 $131,488 $223,381 $204,114
thousands)(3)
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(1) The present value of estimated future net revenues attributable to the
Company's reserves was prepared using constant prices as of the calculation
date, discounted at 10% per annum on a pre-tax basis.
(2) The December 31, 1997 amount was calculated using an average oil price of
$17.00 per barrel and an average gas price of $2.39 per Mcf, which include
adjustments to reflect the effect of hedging. Prices received subsequent to
year end are lower than those used in the calculation.
(3) The standardized measure of discounted future net cash flows represents the
present value of estimated future net revenues after income tax discounted
at 10% per annum.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, future rates of production and the timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner, and the accuracy of any reserve estimate
is a function of the quality of available data, engineering and geological
interpretation and judgment and the existence of development plans. As a result,
estimates of reserves made by different engineers for the same property will
often vary. Results of drilling, testing and production subsequent to the date
of an estimate may justify a revision of such estimates. Accordingly, reserve
estimates generally differ from the quantities of oil and gas ultimately
produced. Further, the estimated future net revenues from proved reserves and
the present value thereof are based upon certain assumptions, including
geological success, prices, future production levels and costs that may not
prove to be correct. Predictions about prices and future production levels are
subject to great uncertainty, and the meaningfulness of such estimates depends
on the accuracy of the assumptions upon which they are based.
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ACQUISITION,PRODUCTION AND DRILLING ACTIVITY
Acquisition and Development Costs. The following table sets forth certain
information regarding the costs incurred by the Company in its acquisition,
exploration and development activities:
Years Ended December 31
---------------------------------
1995 1996 1997
---- ---- ----
(In thousands)
Acquisition costs $ 2,930 $ 6,699 $ 8,437
Exploration costs 34,786 71,490 115,523
Development costs 12,925 14,187 31,327
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Total costs incurred $50,641 $92,376 $155,287
======= ======= ========
Productive Well and Acreage Data. The following table sets forth certain
statistics for the Company regarding the number of productive wells and
developed and undeveloped acreage in the Gulf of Mexico as of December 31, 1997:
Gross Net
---------- -----------
Productive Wells(1):
Oil(2) 16 16.0
Gas(3) 30 28.7
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Total 46 44.7
========== ============
Developed Acreage(1) 46,654 43,804
Undeveloped Acreage(1)(4) 64,680 64,680
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Total 111,334 108,484
========== ============
(1) Productive wells consist of producing wells and wells capable of
production, including gas wells waiting on pipeline connections. Wells that
are completed in more than one producing horizon are counted as one well.
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. A net acre is deemed to exist when the sum of fractional
ownership interests in gross acres equals one. The number of net acres is
the sum of the fractional interests owned in gross acres expressed as whole
numbers and fractions thereof.
(2) Two gross wells each have dual completions.
(3) Nine gross wells each have dual completions
(4) Leases covering 15% of the Company's undeveloped acreage will expire in
1998, approximately 8% in 1999, 23% in 2000, 37% in 2001, and 17% in 2002.
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Drilling Activity. The following table sets forth the Company's drilling
activity for the periods indicated.
Years Ended December 31,
------------------------------------------------
1995 1996 1997
---- ---- ----
Gross Net Gross Net Gross Net
Gulf of Mexico
Exploratory wells 4 4 1 1 13 13.0
Development wells 3 3 7 7 4 4.0
Dry holes 0 0 0 0 3 2.4
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Total 7 7 8 8 20 19.4
=== === === === === ====
OIL AND GAS MARKETING
All of the Company's natural gas, oil and condensate production was sold at
market prices under short-term contracts providing for variable or market
sensitive prices. The Company has not experienced any difficulties in marketing
its oil or gas.
There are a variety of factors which affect the market for oil and gas,
including the extent of domestic production and imports of oil and gas, the
proximity and capacity of natural gas pipelines and other transportation
facilities, demand for oil and gas, the marketing of competitive fuels and the
effects of state and federal regulations of oil and gas production and sales.
The oil and gas industry also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual customers.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve more predictable
cash flows, as well as to reduce its exposure to fluctuations in oil and gas
prices. The Company restricts the time and quantity of the aggregate oil and gas
production covered by such transactions. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations --Hedging
Transactions."
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for oil and natural gas sold
in the spot market due primarily to seasonality of demand and other factors
beyond the Company's control. Domestic oil prices generally follow worldwide oil
prices, which are subject to price fluctuations resulting from changes in world
supply and demand. The Company continues to evaluate the potential for reducing
these risks, and expects to enter into additional hedge transactions in future
years. In addition, the Company also may close out any portion of the existing,
or yet to be entered into, hedges as determined to be appropriate by management.
PRODUCTION SALES CONTRACTS
The Company markets all of the oil and gas production from its properties. All
of the Company's crude oil and gas production is sold to a variety of purchasers
under short-term (less than twelve months) contracts or thirty-day spot purchase
contracts. Natural gas and crude oil sales contracts are based upon field posted
prices plus negotiated bonuses. During calendar 1997, Duke Energy Trading &
Marketing , L.L.C. (formerly Pan Energy Trading and Market Services, L.L.C.), P
G & E Energy Trading Corporation, and Natural Gas Clearinghouse each purchased
in excess of 10% of the gas sold by the Company and Vision Resources, Inc.
purchased in excess of 10% of the oil sold by the Company. Based upon current
demand for oil and gas, the Company does not believe the loss of any of these
purchasers would have a material adverse effect on the Company.
Most of the Company's oil and all of the Company's gas is transported
through gathering systems and pipelines that are not owned by the Company.
Transportation space on such gathering systems and pipelines is occasionally
limited, and at times unavailable, due to repairs or improvements being made to
such facilities or due to such space being utilized by other oil or gas shippers
with priority transportation agreements. While the Company has not experienced
any inability to market its natural gas and oil, if transportation space is
restricted or unavailable, the Company's cash flow could be adversely impacted.
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COMPETITION
The oil and gas industry is highly competitive. The Company competes for
the acquisition of oil and gas properties with numerous other entities,
including major oil companies, other independent oil and gas concerns and
individual producers and operators. Many of these competitors have financial,
technical and other resources substantially greater than those of the Company.
Such companies may be able to pay more for productive oil and gas properties and
exploratory prospects and to define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company's financial or human
resources permit. The Company's ability to acquire additional properties and to
discover reserves in the future will be dependent upon its ability to evaluate
and select suitable properties and to consummate transactions in a highly
competitive environment.
REGULATION
The oil and gas industry is regulated extensively by federal, state and
local authorities. In particular, oil and gas production operations and
economics are affected by price controls, environmental protection statutes and
regulations, tax statutes and other laws relating to the petroleum industry, as
well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. In October
1992, comprehensive national energy legislation was enacted which focuses on
electric power, renewable energy sources and conservation. This legislation,
among other things, guarantees equal treatment of domestic and imported natural
gas supplies, mandates expanded use of natural gas and other alternative fuel
vehicles, funds natural gas research and development, permits continued offshore
drilling and use of natural gas for electric generation and adopts various
conservation measures designed to reduce consumption of imported oil. The
legislation may be viewed as generally intended to encourage the development and
use of natural gas. Oil and gas industry legislation and agency regulation is
under constant review for amendment and expansion for a variety of political,
economic and other reasons.
Regulation of Natural Gas and Oil Exploration and Production. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements 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, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in, and the unitization or pooling of oil and gas properties. In this
regard, some states (such as Oklahoma) allow the forced pooling or integration
of tracts to facilitate exploration while other states (such as Texas) rely on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units and, therefore, more difficult to develop a
project if the operator owns less than 100% of the leasehold. 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 effect of these regulations may
limit the amount of oil and gas the Company can produce from its wells and may
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limit the number of wells or the locations at which the Company can drill. The
regulatory burden on the oil and gas industry increases the Company's costs of
doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations.
The Company has operations located on federal oil and gas leases, which are
administered by the MMS. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency (the "EPA")), lessees must
obtain a permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering and construction specifications. The MMS
proposed additional safety-related regulations concerning the design and
operating procedures for OCS production platforms and pipelines. These proposed
regulations were withdrawn pending further discussions among interested federal
agencies. The MMS also has regulations restricting the flaring or venting of
natural gas, liquid hydrocarbons and oil without prior authorization. Similarly,
the MMS has promulgated other regulations governing the plugging and abandonment
of wells located offshore and the removal of all production facilities. To cover
the various obligations of lessees on the OCS, the MMS generally requires that
lessees post substantial bonds or other acceptable assurances that such
obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases. Under certain circumstances, the MMS may require Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations.
The MMS issued a notice of proposed rulemaking in which it proposed to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. The proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on posted prices and assign a value to crude
oil that better reflects market value, establish a new MMS form for collecting
value differential data, and amend the valuation procedure for the sale of
federal royalty oil. The Company cannot predict at this stage of the rulemaking
proceeding how it might be affected by this amendment to the MMS' regulations.
In April 1997, after two years of study, the MMS withdrew proposed changes
to the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts.
Natural Gas and Oil Marketing and Transportation. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the
Federal Energy Regulatory Commission (the "FERC"). In the past, the federal
government has regulated the prices at which oil and gas could be sold.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was
enacted. This act amended the NGPA to remove both price and non-price controls
from natural gas sold in "first sales" as of January 1, 1993. While sales by
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producers of natural gas and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the gas industry. The ultimate
impact of these complex and overlapping rules and regulations, many of which are
repeatedly subjected to judicial challenge and interpretation, cannot be
predicted.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (collectively, "Order No. 636"), which, among other things, require
interstate pipelines to "restructure" to provide transportation separate, or
"unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires
pipelines to provide open-access transportation on a basis that is equal for all
gas supplies. Order No. 636 has been implemented as a result of FERC orders in
individual pipeline service restructuring proceedings. In many instances, the
result of the Order No. 636 and related initiatives have been to substantially
reduce or bring to an end the interstate pipelines' traditional roles as
wholesalers of natural gas in favor of providing only storage and transportation
services. The FERC has issued final orders in virtually all pipeline
restructuring proceedings, and has completed a series of one year reviews to
determine whether refinements are required regarding individual pipeline
implementations of Order No. 636.
Although Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. The United States Court of Appeals for the District of
Columbia Circuit (the "Court") recently issued its decision in the appeals of
Order No. 636. The Court largely upheld the basic tenets of Order No. 636,
including the requirements that interstate pipelines "unbundle" their sales of
gas from transportation and that pipelines provide open-access transportation on
a basis that is equal for all gas suppliers. The Court remanded several
relatively narrow issues for further explanation by the FERC. In doing so, the
Court made it clear that the FERC's existing rules on the remanded issues would
remain in effect pending further consideration. The Company believes that the
issues remanded for further action do not appear to materially affect it. The
United States Supreme Court has decided not to review the Court's decision
regarding Order No. 636. In February 1997, the FERC issued Order No. 636-C, its
order on remand from the Court. Order 636-C is currently pending on rehearing
before the FERC. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violations of those
tolerances. The Company does not believe, however, that it will be affected by
any action taken with respect to Order No. 636 materially differently than other
natural gas producers and marketers with which it competes.
The FERC has issued a statement of policy and a request for comments
concerning alternatives to its traditional cost-of-service rate making
methodology. This policy statement articulates the criteria that the FERC will
use to evaluate proposals to charge market-based rates for the transportation of
natural gas. The policy statement also provides that the FERC will consider
proposals for negotiated rates for individual shippers of natural gas, so long
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as a cost-of-service-based rate is available as a recourse rate. The FERC also
has requested comments on whether it should allow gas pipelines the flexibility
to negotiate the terms and conditions of transportation service with prospective
shippers. The Company cannot predict what further action the FERC will take on
these matters, however, the Company does not believe that it will be affected by
any action taken materially differently than other natural gas producers and
marketers with which it competes.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market. While any resulting FERC action would affect
the Company only indirectly, the FERC's current rules and policies may have the
effect of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.
The FERC has issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While the FERC's
policy statement on new construction cost recovery affects the Company only
indirectly, in its present form, the new policy should enhance competition in
natural gas markets and facilitate construction of gas supply laterals. The FERC
has denied requests for rehearing of this policy statement. The FERC has issued
numerous orders approving the spin-down or spin-off by interstate pipelines of
their gathering facilities. A "spin-off" is a FERC-approved sale of gathering
facilities to a non-affiliate. A "spin-down" is a transfer of gathering
facilities to an affiliate. These approvals were given despite the strong
protests of a number of producers concerned that any diminution in FERC's
oversight of interstate pipeline-related gathering services might result in a
denial of open access or otherwise enhance the pipeline's monopoly power. While
the FERC has stated that it will retain limited jurisdiction over such gathering
facilities and will hear complaints concerning any denial of access, it is
unclear what effect the FERC's gathering policy will have on producers such as
the Company and the Company cannot predict what further action the FERC will
take on these matters.
Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows or may require pipelines to make rate changes
to track changes in the Producer Price Index for Finished Goods, minus one
percent, became effective January 1, 1995. The FERC's decision in this matter
was recently affirmed by the Court. The Company is not able at this time to
predict the effects of Order Nos. 561 and 561-A, if any, on the transportation
costs associated with oil production from the Company's oil producing
operations.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company does not anticipate that compliance
with existing federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon the capital expenditures, earnings
or competitive position of the Company.
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Environmental Regulation. Activities of the Company with respect to the
exploration, development and production of oil and natural gas are subject to
stringent environmental regulation by state and federal authorities including
the EPA. Such regulation has increased the cost of planning, designing,
drilling, operating and in some instances, abandoning wells. In most instances,
the regulatory requirements relate to the handling and disposal of drilling and
production waste products and waste created by water and air pollution control
procedures. Although the Company believes that compliance with environmental
regulations will not have a material adverse effect on operations or earnings,
the risks of substantial costs and liabilities are inherent in oil and gas
operations, and there can be no assurance that significant costs and
liabilities, including criminal penalties, 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 person resulting from the
Company's operations could result in substantial costs and liabilities.
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 the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
the hazardous substances found at such site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the disposal
options for certain hazardous and nonhazardous wastes. Furthermore, certain
wastes generated by the Company's oil and natural gas operations that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes," and therefore be subject to more rigorous and
costly operating and disposal requirements.
The Company currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and gas. Although the Company has utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other wastes may have been disposed of or released on or under the properties
owned or leased by the Company or on or under other locations where such wastes
have been taken for disposal. In addition, many of these properties have been
operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under the Company's control. These
properties and the wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
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 United States
waters. A "responsible party" includes the owner or operator of an onshore
facility, vessel or pipeline, or the lessee or permittee of the area in which an
offshore facility is located. The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages. While
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liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or cooperate fully in
the cleanup, liability limits likewise do not apply. Few defenses exist to the
liability imposed by the OPA.
The OPA also imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10 million depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. For offshore facilities that have a
worst case oil spill potential of more than 1,000 barrels (which includes many
of the Company's offshore producing facilities), certain amendments to the OPA
that were enacted in 1996 provide that the amount of financial responsibility
that must be demonstrated by most facilities range from $10 million in specified
state waters to $35 million in federal OCS waters, with higher amounts, up to
$150 million in certain limited circumstances where the MMS believes such a
level is justified by the risks posed by the quantity or quality of oil that is
handled by the facility. On March 25, 1997, the MMS promulgated a proposed rule
implementing these OPA financial responsibility requirements. Under the proposed
rule, the amount of financial responsibility required for a facility would
depend on the "worst case" oil spill discharge volume calculated for the
facility. For oil and gas producers such as the Company operating offshore
facilities in OCS waters, worst case discharge volumes of up to 35,000 barrels
will require a financial responsibility demonstration of $35 million, while
worst case discharge volumes in excess of 35,000 barrels will require
demonstrations ranging from $70 million to $150 million.
The Company believes that it currently has established adequate proof of
financial responsibility for its offshore facilities at no significant increase
in expense over recent prior years. However, the Company cannot predict whether
these financial responsibility requirements under the OPA amendments or proposed
rule will result in the imposition of substantial additional annual costs to the
Company in the future or otherwise materially adversely affect the Company. The
impact, however, should not be any more adverse to the Company than it will be
to other similarly situated or less capitalized owners or operators in the Gulf
of Mexico. OPA also imposes other requirements on facility operators, such as
the preparation of an oil spill contingency plan. The Company has such plans in
place. The failure to comply with ongoing requirements or inadequate cooperation
in a spill event may subject a responsible party to civil or even criminal
liability.
OPERATING HAZARDS AND INSURANCE
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled as a result
of title problems, weather conditions, compliance with governmental
requirements, mechanical difficulties or shortages or delays in the delivery of
equipment and that the availability or capacity of gathering systems, pipelines
or processing facilities may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs.
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In addition, the Company's properties may be susceptible to hydrocarbon
drainage from production by other operators on adjacent properties. Industry
operating risks include the risk of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which
could result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. Additionally, the
Company's oil and gas operations are located in an area that is subject to
tropical weather disturbances, some of which can be severe enough to cause
substantial damage to facilities and possibly interrupt production.
The MMS requires lessees of OCS properties to post performance bonds in
connection with the plugging and abandonment of wells located offshore and the
removal of all production facilities. The Company has posted an area wide bond
meeting MMS requirements and has obtained additional supplemental bonding on its
offshore leases as required by the MMS.
The Company maintains customary oil and gas related third party liability
coverage, which it must renew annually, that insures the Company against certain
sudden and accidental risks associated with drilling, completing and operating
its wells. There can be no assurance that this insurance will be adequate to
cover any losses or exposure to liability or that the Company will be able to
renew its coverage annually. The Company carries workers' compensation insurance
in all states in which it operates. While the Company believes this coverage is
customary in the industry, it does not provide complete coverage against all
operating risks.
EMPLOYEES
The Company presently has 53 full-time employees, primarily professionals,
including geologists, geophysicists and engineers. The Company also relies on
the services of certain consultants for technical and operational guidance. The
Company believes that its relationships with its employees and consultants are
satisfactory and has entered into employment and consulting contracts with its
executives and agreements with certain technical personnel and consultants whom
it considers particularly important to the operations of the Company. There can
be no assurance that such individuals will remain with the Company for the
immediate or foreseeable future. None of the Company's employees are covered by
a collective bargaining agreement. From time to time, the Company also utilizes
the services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as maintenance, dispatching, inspection and
testing, are generally provided by independent contractors supervised by Company
employees.
FORWARD-LOOKING STATEMENTS
This Annual Report includes "forward-looking statements" within the meaning
of Section 27A of 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 Annual Report, including without
limitation statements under "Item 7- Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Item 1- Business" regarding
the planned capital expenditures, increases in oil and gas production, the
number of anticipated wells to be drilled in 1998 and thereafter, the Company's
financial position, business strategy and other plans and objectives for future
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operations, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to have been correct.
There are numerous risks and uncertainties that can affect the outcome of
certain events including many factors beyond the control of the Company. These
factors include but are not limited to the matters that are described below. All
subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
SUBSTANTIAL LEVERAGE
As of December 31, 1997, the Company's long-term debt was $136.9 million,
of which $99.6 million was senior subordinated notes and $37.3 million was a
subordinated shareholder loan. As of December 31, 1997, the Company had $50
million committed but undrawn under the Company's Bank credit facility.
The Company's level of indebtedness will have several important effects on
its operations, including (i) a substantial portion of the Company's cash flow
from operations will be dedicated to the payment of interest on its indebtedness
and will not be available for other purposes, (ii) the covenants contained in
the indenture governing the Senior Subordinated Notes limit its ability to
borrow additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in business conditions and
(iii) the Company's ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general corporate purposes
or other purposes may be impaired. Moreover, future acquisition or development
activities may require the Company to alter its capitalization significantly.
These changes in capitalization may significantly alter the leverage of the
Company. The Company's ability to meet its debt service obligations and to
reduce its total indebtedness will be dependent upon the Company's future
performance, which will be subject to general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors. See "Item 7- Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources."
VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION
The Company's revenue, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
natural gas. Prices for oil and natural gas are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond the control of the Company. These factors include the level of consumer
product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of oil and gas imports and overall economic conditions. From time to time,
oil and gas prices have been depressed by excess domestic and imported supplies.
There can be no assurance that current price levels will be sustained. It is
impossible to predict future oil and natural gas price movements with any
certainty. Declines in oil and natural gas prices may adversely affect the
Company's financial condition, liquidity and results of operations and may
reduce the amount of the Company's oil and natural gas that can be produced
economically. Additionally, substantially all of the Company's sales of oil and
natural gas are made in the spot market or pursuant to contracts based on spot
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market prices and not pursuant to long-term fixed price contracts. With the
objective of reducing price risk, the Company enters into hedging transactions
with respect to a portion of its expected future production. There can be no
assurance, however, that such hedging transactions will reduce risk or mitigate
the effect of any substantial or extended decline in oil or natural gas prices.
Any substantial or extended decline in the prices of oil or natural gas would
have a material adverse effect on the Company's financial condition and results
of operations.
In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk. See "Item 7- Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Overview" and "Item 1- Business
- -- Oil and Gas Marketing."
UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES
This Annual Report contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based upon the Ryder
Scott Reports that rely upon various assumptions, including assumptions required
by the Commission as to oil and gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. The process of estimating
oil and gas reserves is complex, requiring significant decisions and assumptions
in the evaluation of available geological, geophysical, engineering and economic
data for each reservoir. As a result, such estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves may vary substantially from those estimated in the Ryder Scott Reports.
Any significant variance in these assumptions could materially affect the
estimated quantity and value of reserves set forth in this Annual Report. In
addition, the Company's proved reserves may be subject to downward or upward
revision based upon production history, results of future exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond the Company's control. Actual production, revenues, taxes, development
expenditures and operating expenses with respect to the Company's reserves will
likely vary from the estimates used, and such variances may be material.
Approximately 25% of the Company's total proved reserves at December 31,
1997 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. The reserve data set forth in the Ryder Scott Report assumes that
substantial capital expenditures by the Company will be required to develop such
reserves. Although cost and reserve estimates attributable to the Company's oil
and gas reserves have been prepared in accordance with industry standards, no
assurance can be given that the estimated costs are accurate, that development
will occur as scheduled or that the results will be as estimated. See "Item 1-
Business -- Oil and Gas Reserves."
The present value of future net revenues referred to in this Annual Report
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Securities and Exchange Commission, the estimated discounted
future net cash flows from proved reserves are generally based on prices and
costs as of the date of the estimate, whereas actual future prices and costs may
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be materially higher or lower. Actual future net cash flows also will be
affected by changes in consumption by gas purchasers and changes in governmental
regulations or taxation. The timing of actual future net cash flows from proved
reserves, and thus their actual present value, will be affected by the timing of
both the production and the incurrence of expenses in connection with
development and production of oil and gas properties. In addition, the 10%
discount factor, which is required by the Securities and Exchange Commission to
be used in calculating discounted future net cash flows for reporting purposes,
is not necessarily the most appropriate discount factor based on interest rates
in effect from time to time and risks associated with the Company or the oil and
gas industry in general.
REPLACEMENT OF RESERVES
As is customary in the oil and gas exploration and production industry, the
Company's future success depends upon its ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless the
Company replaces its estimated proved reserves (through development, exploration
or acquisition), the Company's proved reserves will generally decline as they
are produced.
The Company's current strategy includes increasing its reserve base through
acquisitions of lease blocks with drilling potential and by continuing to
exploit its existing properties. There can be no assurance, however, that the
Company's exploration and development projects will result in significant
additional reserves or that the Company will have continuing success drilling
productive wells at economically viable costs. Furthermore, while the Company's
revenues may increase if prevailing oil and gas prices increase significantly,
the Company's finding costs for additional reserves could also increase. For a
discussion of the Company's reserves, see "Item 1- Business -- Oil and Gas
Reserves."
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial expenditures for
the development, exploration, acquisition and production of oil and natural gas
reserves. The Company made capital expenditures, including exploration expense,
of $92 million during 1996 and $155 million during 1997. Management believes
that the Company will have sufficient cash provided by operating activities and
borrowings under the Bank credit facility to fund future capital expenditures.
However, if revenues or cash flows from operations decrease as a result of lower
oil and natural gas prices or operating difficulties, the Company may be limited
in its ability to expend the capital necessary to undertake or complete its
drilling program, or it may be forced to raise additional debt or equity
proceeds to fund such expenditures. There can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet these requirements. See "Item 7- Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
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INDUSTRY RISKS
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled and that
title problems, weather conditions, compliance with governmental requirements,
mechanical difficulties or shortages or delays in the delivery of drilling rigs,
work boats and other equipment may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells but also from wells that are productive but do not
produce sufficient net revenues to return a profit after drilling, operating and
other costs. In addition, the Company's properties may be susceptible to
hydrocarbon drainage from production by other operators on adjacent properties.
Industry operating risks include the risk of fire, explosions, blow-outs,
pipe failure, abnormally pressured formations and environmental hazards such as
oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of
any of which could result in substantial losses to the Company due to injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, the Company's oil and gas operations are located in an area that
is subject to tropical weather disturbances, some of which can be severe enough
to cause substantial damage to facilities and possibly interrupt production. In
accordance with customary industry practice, the Company maintains insurance
against some, but not all, of the risks described above. There can be no
assurance that any insurance will be adequate to cover losses or liabilities.
The Company cannot predict the continued availability of insurance at premium
levels that justify its purchase.
GOVERNMENTAL REGULATION
Oil and gas operations are subject to various United States federal, state
and local governmental regulations that change from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling and abandonment bonds,
reports concerning operations, the spacing of wells, and unitization and pooling
of properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. In addition, the production, handling, storage, transportation
and disposal of oil and gas, by-products thereof and other substances and
materials produced or used in connection with oil and gas operations are subject
to regulation under federal, state and local laws and regulations primarily
relating to protection of human health and the environment. To date,
expenditures related to complying with these laws and for remediation of
existing environmental contamination have not been significant in relation to
the results of operations of the Company. Although the Company believes it is in
substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
See "Item 1- Business -- Regulation."
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RELIANCE ON KEY PERSONNEL
The Company's operations are dependent upon a relatively small group of key
management and technical personnel. There can be no assurance that such
individuals will remain with the Company for the immediate or foreseeable
future. The unexpected loss of the services of one or more of these individuals
could have a detrimental effect on the Company. See "Item 10- Directors and
Executive Officers of the Registrant."
COMPETITION
The Company operates in a highly competitive environment. The Company
competes with major and independent oil and gas companies for the acquisition of
desirable oil and gas properties, as well as for the equipment and labor
required to develop and operate such properties. Many of these competitors have
financial and other resources substantially greater than those of the Company.
See "Item 1- Business -- Competition."
RISKS OF HEDGING TRANSACTIONS
In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company has in the past and expects to continue to enter
into oil and natural gas price hedging arrangements with respect to a portion of
its expected production. These arrangements may include futures contracts on the
New York Mercantile Exchange (NYMEX), fixed price delivery contracts and
financial swaps. While intended to reduce the effects of volatility of the price
of oil and natural gas, such transactions may limit potential gains by the
Company if oil and natural gas prices were to rise substantially over the price
established by the hedge. In addition, such transactions may expose the Company
to the risk of financial loss in certain circumstances, including instances in
which (i) production is less than expected, (ii) if there is a widening of price
differentials between delivery points for the Company's production and the
delivery point assumed in the hedge arrangement, (iii) the counterparties to the
Company's future contracts fail to perform the contract or (iv) a sudden,
unexpected event materially impacts oil or natural gas prices. See "Item 7-
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Transactions" and "Item 1- Business -- Oil and Gas
Marketing."
ITEM 2 - DESCRIPTION OF PROPERTIES
ITEM 2 (A) - SIGNIFICANT PROPERTIES
The Company has grown principally through the acquisition and development
of properties in the Gulf of Mexico offshore Louisiana. The first four leases
were acquired from the State of Louisiana, four leases were purchased from third
parties and the remaining leases have been acquired at Gulf of Mexico State and
Federal OCS lease sales. At December 31, 1997 the Company had 34 lease blocks in
the Gulf of Mexico. All of the Company's proved oil and gas reserves at December
31, 1997 were in these blocks.
ITEM 2 (B) - RESERVES
The information on the Company's oil and gas reserves is set out under
Item 1 on page 6.
The information on the Company's oil and gas production is set out under
Item 7 on page 25.
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ITEM 3 - LEGAL PROCEEDINGS
LEGAL PROCEEDINGS
The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot be
predicted with certainty, the Company does not expect these matters to have a
material adverse effect on the financial position, results of operations or
liquidity of the Company.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All the shares of common stock are held by the Parent Company, Petsec
Energy Ltd. See "Notes to Financial Statements -- Note 1(a) Description of
Business" on page 42.
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ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected historical financial data for the
Company as of and for each of the periods indicated. The financial data, for the
years ended December 31, 1994, 1995, 1996 and 1997 are derived from the
financial statements of the Company audited by KPMG Peat Marwick LLP,
independent auditors. The financial data, for the year ended December 31, 1993
is derived from the Company's unaudited financial statements which, in the
opinion of management, include all adjustments (which consist only of normal
recurring adjustments) necessary for a fair presentation of the financial
position and results of operations of the Company for such period. The following
information should be read in conjunction with "Item 7- Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the financial
statements of the Company and the related notes thereto included elsewhere in
this Annual Report.
<TABLE>
<CAPTION>
Years Ended December 31,
---------------------------------------------------------
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C> <C>
Statement of Operations data:
Oil and gas sales $11,829 $15,098 $30,462 $67,027 $125,139
Lease operating expenses 2,782 3,855 4,757 6,161 11,527
Depletion, depreciation and amortization 4,113 4,291 9,256 29,639 63,864
Exploration expenditures 2,603 3,020 3,396 7,061 17,782
General and administrative 1,421 2,046 4,502 5,259 6,054
Stock compensation expense -- -- -- 481 905
-------- ------- -------- -------- --------
Total operating expenses 10,919 13,212 21,911 48,601 100,132
--------- ------- -------- -------- --------
Income from operations 910 1,886 8,551 18,426 25,007
Other income (expense) -- (55) 35 -- 1,418
Gain (loss) on sale of property, plant
and equipment -- (16) 4,312 6 --
Interest expense (347) (959) (2,452) (3,369) (7,586)
Interest income 19 14 64 172 871
--------- ------- -------- -------- --------
Income before income taxes 582 870 10,510 15,235 19,710
Income tax expense -- 25 3,537 6,311 6,610
--------- ------- -------- -------- --------
Net income $ 582 $ 845 $ 6,973 $ 8,924 $ 13,100
========= ======= ======== ======= ========
As of December 31,
-------------------------------------------------------------
1993 1994 1995 1996 1997
-------------------------------------------------------------
(in thousands)
Balance Sheet Data:
Total assets $21,894 $36,969 $89,110 $146,145 $234,104
Senior subordinated notes -- -- -- -- 99,630
Bank credit facility 9,766 12,825 32,350 37,000 --
Subordinated shareholder loan 11,386 11,386 25,038 57,954 37,298
--------- ------- -------- -------- --------
Total long-term debt 21,152 24,211 57,388 94,954 136,928
Shareholder's equity (2,188) (1,342) 5,631 15,036 48,635
========== ======== ======== ======== =========
</TABLE>
23
<PAGE> 24
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion is intended to assist in the understanding of the
Company's historical financial position and results of operations for each year
in the three years ended December 31, 1997. Financial Statements and notes
thereto included elsewhere in this Annual Report should be referred to in
conjunction with the following discussion.
OVERVIEW
The Company is the principal operating subsidiary of Petsec Energy Ltd, an
Australian public company with ADRs listed on The Nasdaq Stock Market SM. The
Company was incorporated in March 1990 to evaluate oil and gas exploration
opportunities in the United States. In 1990, the Company participated in an oil
discovery in the Paradox Basin in Colorado. In addition the Company acquired oil
and gas lease interests in northern California. The Company also established an
office in Lafayette, Louisiana, hired several former employees of Tenneco Oil
Company and acquired leases in the Gulf of Mexico, offshore Louisiana. The
Company subsequently made a strategic decision to focus its efforts entirely in
the Gulf of Mexico and disposed of its interests in the Paradox Basin in January
1995.
The Company has acquired substantially all of its 34 leases in the Gulf of
Mexico at federal or state lease sales. The Company maintains an active lease
acquisition program in order to increase its inventory of prospects. To date,
the Company has retained a 100% working interest ownership in all but one of its
leases in the Gulf of Mexico, which enables it to effectively control expenses,
capital allocation, and the timing and method of exploration and development of
its properties. In the future, the Company intends to maintain substantial
working interest positions.
The Company has historically expanded its oil and gas reserves principally
through drilling. The Company is currently producing from 18 of its lease
blocks. The Company's activities are focused in the shallow waters of the Gulf
of Mexico, which provides the Company with access to the substantial
infrastructure of the Gulf and allows the Company to utilize lower cost rigs and
equipment in bringing its production on line. Over the last three years,
concurrent with increases in production, the Company has lowered its lease
operating expenses and general and administrative expenses per unit of
production.
The Company has significantly increased production and proved reserves in
the last three years. Production has increased from 13,603 MMcfe in 1995 to
46,408 MMcfe in 1997. As of December 31, 1997, the Company's proved reserves
were 186.0 Bcfe, 66% of which were natural gas.
The Company markets its oil through spot price contracts and typically
receives a premium above the price posted. The Company's gas production is sold
under contracts which generally reflect spot market conditions in the central
Gulf of Mexico. The Company has historically entered into crude oil and natural
gas price swaps to reduce its exposure to price fluctuations. The results of
operations described herein reflect any hedging transactions undertaken by the
Company. See Note 10 to the Financial Statements.
24
<PAGE> 25
The Company follows the successful efforts method of accounting. Under this
method, the Company capitalizes lease acquisition costs, costs to drill and
complete exploration wells in which proved reserves are discovered and costs to
drill and complete development wells. Costs to drill exploratory wells that do
not find proved reserves are expensed. Seismic, geological and geophysical, and
delay rental expenditures are expensed as incurred.
The Company is allocated stock compensation expense in respect to options
in Petsec Energy Ltd (the Parent) which are granted to the Company's employees
and certain consultants. In 1996, the Parent adopted SFAS No. 123, Accounting
for Stock-Based Compensation under which it recognizes as expense over the
vesting period the fair value of all stock based awards on the date of grant.
See Note 5 to the Financial Statements.
The Company reimburses Petsec Energy Ltd for direct expenses incurred in
connection with the Company's operations. In addition, the Company has received
subordinated loans from its parent to finance its operations. See "-- Liquidity
and Capital Resources."
The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and gas, which are in
turn dependent upon numerous factors that are beyond the Company's control, such
as economic, political and regulatory developments and competition from other
sources of energy. The energy markets have historically been volatile, and there
can be no assurance that oil and gas prices will not be subject to wide
fluctuations in the future. A substantial or extended decline in oil and gas
prices could have a material adverse effect on the Company's financial position,
results of operations and access to capital, as well as the quantities of oil
and gas reserves that the Company may economically produce. Current prices are
lower than those realized in 1997.
The following table sets forth certain operating information with respect
to the oil and gas operations of the Company.
Years Ended December 31,
---------------------------------
1995 1996 1997
---------- ---------- -----------
Net production:
Gas (MMcf) 7,519 11,722 27,940
Oil (MBbls) 1,014 2,150 3,078
Total (MMcfe) 13,603 24,622 46,408
Net sales data (in thousands):
Gas $13,863 $23,056 $ 64,770
Oil $16,599 $43,971 $ 60,369
Total $30,462 $67,027 $ 125,139
Average sales price (1):
Gas (per Mcf) $ 1.84 $ 1.97 $ 2.32
Oil (per Bbl) $ 16.37 $ 20.45 $ 19.61
Total (per Mcfe) $ 2.24 $ 2.72 $ 2.70
Average costs (per Mcfe):
Lease operating expenses $ 0.35 $ 0.25 $ 0.25
General, administrative and
other expenses $ 0.33 $ 0.21 $ 0.13
(1) Includes effects of hedging activities.
25
<PAGE> 26
RESULTS OF OPERATIONS
1997 COMPARED TO 1996
General. The Company drilled twenty wells during the year ended December
31, 1997, of which 14 have subsequently been brought into production. In
addition, the Company completed the installation of facilities at West Cameron
461, South Marsh Island 7, Grand Isle 45, Main Pass 104 and Main Pass 84. This
resulted in an increase in production of 21.8 Bcfe to 46.4 Bcfe in 1997, an 88%
increase over the 24.6 Bcfe in 1996.
Oil and Gas Revenues. Oil and gas revenues for 1997 were $125.1 million, an
increase of $58.1 million, or 87% above 1996 revenues of $67.0 million. A 43%
increase in oil production offset by a 4% decrease in oil prices combined to
account for $16.4 million of the increase. A 138% increase in gas production and
an 18% increase in the gas price accounted for the remaining $41.7 million of
the increase. Increased oil production followed the development of the Ship
Shoal 194 field, while the increased gas production stems from the drilling and
development of the West Cameron 461, South Marsh Island 7 and Grand Isle 45
fields.
The average realized gas price in 1997 was $2.32 per Mcf, or 8% below the
$2.53 per Mcf average gas price that would have otherwise been received if no
hedging had been undertaken. In the same period, the average realized oil price
was $19.61 per Bbl, or 3% above the $19.10 per Bbl that would have otherwise
been received if no hedging had taken place. In 1996 the average realized gas
price was $1.97 per Mcf, or 24% below the $2.58 per Mcf price that would have
otherwise been received if no hedging had been undertaken. In the same period
the average realized oil price was $20.45 per Bbl, or 3% below the $21.04 per
Bbl that would have otherwise been received if no hedging had taken place.
Hedging activities resulted in a $4.4 million decrease in revenues for 1997
compared to an $8.4 million decrease in 1996.
Lease Operating Expenses. Lease operating expenses in 1997 were $11.5
million, an increase of $5.3 million, or 85%, from $6.2 million in 1996. The
increase was attributable to increased production. Lease operating expenses per
Mcfe were $0.25 in both years.
Depletion, Depreciation and Amortization ("DD&A"). DD&A expense increased
$34.3 million, or 116%, from $29.6 million in 1996 to $63.9 million in 1997.
Production increases accounted for $26.1 million of the increase while an
increase in the average rate per unit from $1.20 to $1.38 per Mcfe accounted for
the balance. The increase in the unit rate was due to increased capital
expenditures from the Company's exploration and development activities coupled
with increased costs of drilling goods and services, platform and facilities
construction and transportation services in the industry. As a result of Ryder
Scott reserve revisions in the fourth quarter, the unit DD&A rate was reduced to
$1.25 per Mcfe in the fourth quarter compared to an average rate of $1.41 for
the preceding three quarters.
Exploration Expenditures. The Company uses the successful efforts method to
account for oil and gas exploration, evaluation and development expenditure.
Under this method $10.5 million for dry hole and impairment costs and $7.3
million for seismic, geological and geophysical expenditures were expensed as
incurred in 1997. There were no dry hole and impairment costs in 1996 while
seismic, geological and geophysical expenditures totaled $7.1 million.
General and Administrative Expense. General and administrative expense
increased $0.8 million, or 15%, to $6.1 million in 1997 from $5.3 million in
1996. On a per Mcfe basis the rate decreased 38% from $0.21 to $0.13 due to
increased production.
Interest Expense. Interest expense in 1997 increased $4.2 million, or 124%,
to $7.6 million from $3.4 million in 1996 due to increased borrowings coupled
with an increased effective interest rate as a result of the Senior Subordinated
Notes.
26
<PAGE> 27
Net Income. As a result of the conditions noted above, net income for 1997
was $13.1 million, an increase of $4.2 million, or 47% over the earnings of $8.9
million for 1996.
1996 COMPARED TO 1995
General. During the year ended December 31, 1996, the Company set a larger
platform and facility at Ship Shoal 193, significantly increasing production
capacity at that field. In addition, a facility and pipeline was completed to
tie-in its Main Pass 91 wells to its Main Pass 6/7 facility. The Company drilled
and completed eight wells during the period. This activity resulted in an
increase in production of 81% from 13.6 Bcfe in 1995 to 24.6 Bcfe in 1996.
Average daily production for 1996 increased 81% to 67.5 MMcfe from 37.3 MMcfe
for 1995.
Oil and Gas Revenues. Oil and gas revenues for 1996 were $67.0 million, an
increase of $36.5 million, or 120% above 1995 revenues of $30.5 million. A 112%
increase in oil production coupled with a 25% increase in oil prices combined to
account for $27.3 million of the increase. A 56% increase in gas production and
a 7% increase in the gas price accounted for the remaining $9.2 million of the
increase. The increased oil production resulted from the tie-back of additional
wells and increased capacity at Ship Shoal 193 following installation of a
larger manned four pile platform. The increased gas production resulted from a
full year's production at West Cameron 543/544 and commencement of production at
Main Pass 91 in the second half of the year.
The average realized gas price in 1996 was $1.97 per Mcf, or 24% below the
$2.58 per Mcf that would have otherwise been received if no hedging had been
undertaken. In the same period the average realized oil price was $20.45 per
Bbl, or 3% below the $21.04 per Bbl that would have otherwise been received if
no hedging had taken place. The average realized gas price in 1995 was $1.84 per
Mcf, or 4% above the $1.76 per Mcf that would have otherwise been received if no
hedging had been undertaken. In the same period the average realized oil price
was $16.37, or 1% above the $16.22 per Bbl that would have otherwise been
received if no hedging had taken place. Hedging activities resulted in a $8.4
million decrease in revenues for 1996 compared to a $0.8 million increase in
1995.
Lease Operating Expenses. Lease operating expenses in 1996 were $6.2
million, an increase of $1.4 million, or 29%, from $4.8 million in 1995.
Production efficiencies were realized as lease operating expense per Mcfe
decreased from $0.35 in 1995 to $0.25 in 1996.
Depletion, Depreciation and Amortization. DD&A expense increased $20.3
million, or 218%, from $9.3 million in 1995 to $29.6 million in 1996. Production
increases accounted for $7.5 million of the increase while an increase in the
average rate per unit from $0.68 to $1.20 per Mcfe accounted for the balance.
The increase in rate was attributable to increased capital expenditures from the
Company's exploration and production activities.
Exploration Expenditures. Under the successful efforts method of accounting
$7.1 million of seismic, geological and geophysical expenditures were expensed
as incurred in 1996. This was an increase of $3.7 million, or 109%, over the
expense of $3.4 million for 1995 as the Company expanded its access to a broader
seismic base in the Gulf of Mexico.
General and Administrative Expenses. General and administrative expense
increased $0.8 million, or 18%, to $5.3 million in 1996 from $4.5 million in
1995. This increase was attributable to the Company's success and resultant
growth in production. On a per Mcfe basis the rate decreased 36% from $0.33 to
$0.21.
27
<PAGE> 28
Interest Expense. Interest expense in 1996 increased $0.9 million, or 36%,
to $3.4 million from $2.5 million in 1995 due to increased borrowings under the
Bank credit facility.
Net Income. As a result of the conditions noted above, net income for 1996
was $8.9 million, an increase of $1.9 million, or 27% over the earnings of $7.0
million for 1995.
LIQUIDITY AND CAPITAL RESOURCES
The following table represents cash flow data for the Company for the
periods indicated.
Years Ended December 31,
-------------------------------
1995 1996 1997
-------------------------------
(in thousands)
CASH FLOW DATA:
Net cash provided by operating activities $21,561 $47,297 $95,740
Net cash used in investing activities 47,836 85,939 148,432
Net cash provided by financing activities 27,158 37,566 59,781
The fluctuation in cash provided by operating activities from 1996 to 1997
was primarily due to increased oil and gas production. Similarly the fluctuation
from 1995 to 1996 was primarily due to increased oil and gas production coupled
with higher prices for both commodities. Before changes in operating assets and
liabilities, funds from operations were $93.7 million in 1997, $45.4 million in
1996 and $16.0 million in 1995.
The increase in cash used in investing activities in all periods was due to
expenditures on exploration and development.
The cash provided by financing activities in 1997 consisted primarily of
proceeds from a June 1997 Senior Subordinated Note issue (described below) a
portion of which was used to repay outstandings under the bank credit facility.
The cash provided by financing activities in 1995 and 1996 consisted of advances
from Petsec Energy Ltd and borrowings under the bank credit facility.
Since 1990 the Company has financed its working capital needs, operations
and growth primarily with advances from its parent, Petsec Energy Ltd, cash flow
from operations and bank borrowings.
Petsec Energy Ltd made an initial cash investment of $11.4 million in the
Company and, subsequently, increased this investment with advances of $18.5
million from an Australian offering of Ordinary Shares in September 1995 and
$31.0 million out of net proceeds from a U.S. offering of ADRs in July 1996.
Funds advanced by the Parent have historically been provided in the form of
subordinated loans. These loans are subordinated to the payment of all Senior
Indebtedness and have been subordinated to the Notes defined herein. The US
dollar loans bear interest at 7.18% and, in the case of Australian dollar
borrowings, 6.83%. The loans from the Parent do not have mandatory principal
payments due until December 31, 2007. No interest was paid or accrued on these
loans prior to June 1, 1997. Any payments or distributions made by the Company
to its Parent have been principally for reimbursement of direct expenses
incurred in connection with the Company's operations.
28
<PAGE> 29
In April 1996, the Company entered into a $75 million bank credit facility,
under which the current borrowing base is $60 million. In addition, a sublimit
of $15 million exists for letter of credit purposes to support the bonding
requirements of the MMS and commodity swap transactions. At December 31, 1997,
there were no borrowings outstanding under the bank credit facility. The bank
credit facility is a two-year revolving credit facility followed by a two-year
term period with equal quarterly amortization payments. The facility matures in
April 2001. The bank credit facility is secured by the Company's Gulf of Mexico
producing properties and contains financial covenants that require the Company
to maintain a ratio of senior debt to earnings before interest, taxes,
depletion, depreciation and amortization of not more than 2.75 to 1.0 and a
coverage ratio of earnings before interest, taxes and depletion, depreciation
and amortization to total interest of not less than 3.0 to 1.0. The Company is
currently in compliance with all financial covenants under the bank credit
facility. Outstanding borrowings accrue interest at the rate of LIBOR plus a
margin of 1.25% to 1.50% per annum, depending upon the total amount borrowed.
The Company is obligated to pay a fee equal to .30% to .35% per annum based on
the unused portion of the borrowing base under the facility
The Company's ability to borrow under the bank credit facility is dependent
upon the reserve value of its oil and gas properties, as determined by The Chase
Manhattan Bank ("Chase"). If the reserve value of the Company's borrowing base
declines, the amount available to the Company under the bank credit facility
will be reduced and, to the extent that the borrowing base is less than the
amount then outstanding (including letters of credit) under the bank credit
facility, the Company will be obligated to repay such excess amount upon ninety
days' notice from Chase or to provide additional collateral.
In June 1997, the Company issued $100 million of 9 1/2% Senior Subordinated
Notes due 2007 (the "Notes"). The Notes were issued at a discount with a yield
to maturity of 9.56% per annum. The net proceeds from the offering of the Notes
were approximately $96.4 million. The Company used a portion of the net proceeds
to repay borrowings under the bank credit facility. The remainder of the net
proceeds is being used to provide working capital for the Company and to fund
further exploration and development of its oil and gas properties, the
acquisition of lease blocks and other general corporate purposes.
The Company intends to finance expenditures for 1998 with cash on hand,
cash flow from operations and bank borrowings. The Company was high bidder on
seven lease blocks at the March 18, 1998, OCS Louisiana Offshore Sale. If the
Company is awarded all of these leases, the committed costs will be $7.8
million. The capital expenditure budget is continually re-evaluated based on
drilling results, commodity prices, cash flow from operations and property
acquisitions.
HEDGING TRANSACTIONS
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more predictable
cash flow and to reduce its exposure to oil and gas price fluctuations. While
these hedging arrangements limit the downside risk of adverse price movements,
they may also limit future revenues from favorable price movements. The use of
hedging transactions also involves the risk that the counterparties will be
unable to meet the financial terms of such transactions. The credit worthiness
of counter parties is subject to continuing review and full performance is
anticipated. The Company limits the duration of the transactions and the
percentage of the Company's expected aggregate oil and gas production that may
be hedged. The Company accounts for these transactions as hedging activities
and, accordingly, gains or losses are included in oil and gas revenues when the
hedged production is delivered.
29
<PAGE> 30
The Company enters into forward swap contracts with major financial
institutions to reduce the price volatility on the sale of oil and gas
production. In swap agreements, the Company receives the difference between a
fixed price per unit of production and a floating price issued by a third party.
If the floating price is higher than the fixed price, the Company pays the
difference.
The Company also enters into collar agreements with third parties. A collar
agreement is similar to a swap agreement except that the Company receives the
difference between the floor price and the floating price if the floating price
is below the floor. The Company pays the difference between the ceiling price
and the floating price if the floating price is above the ceiling. The Company
has proved reserves sufficient to cover all of these contracts and does not
trade in derivatives without underlying forecasted production and proved
reserves.
For the years ended December 31, 1995, 1996 and 1997, hedging activities
increased revenues by $0.8 million and reduced revenues by $8.4 million and $4.4
million, respectively.
YEAR 2000
The Company is aware of the issues associated with the programming code in
existing computer systems as the year 2000 approaches. The Company is utilizing
both internal and external resources to identify, correct or reprogram, and test
the systems for the year 2000 compliance. It is anticipated that all
reprogramming efforts will be complete by December 31, 1998, allowing adequate
time for testing. To date, confirmations have been received from the Company's
primary processing vendors that plans are being developed to address processing
of transactions in the year 2000. Management has not yet assessed the year 2000
compliance expense and related potential effect on the Company's financial
position, results of operations or liquidity.
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial information in this form 10-K refers to Petsec Energy Inc., a
wholly owned subsidiary of Petsec Energy Ltd. The publicly listed Petsec Energy
Ltd files its annual consolidated financial statements separately under form
20-F and a summary of its quarterly consolidated financial statements under form
6-K. The response to this item begins on page 37.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
30
<PAGE> 31
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
MANAGEMENT
DIRECTORS AND EXECUTIVES
The following table sets forth the name, age and position of each person
who is a director, executive officer, key employee, or who provides services to
the Company.
Name Age Position
- ---- --- --------
Terrence N. Fern 50 Chairman and Chief Executive Officer
Anthony J. Walton 55 Director
Maynard V. Smith 47 General Manager-- Exploration and Production
Howard H. Wilson, Jr. 39 Vice President (Operations)
Mark A. Gannaway 42 Exploration Manager
Prent H. Kallenberger 43 Geophysical Manager
Ross A. Keogh 38 Director, Treasurer and Financial Controller
James E. Slatten III 39 Director, Secretary and Manager -- Land and Legal
Mr. Smith provides services to the Company through an arrangement with the
Company's parent.
The following biographies describe the business experience of the
directors, executive officers and those who provide services to the Company.
Directors serve annual terms.
TERRENCE N. FERN has served as Chairman and Chief Executive Officer of the
Company since 1990. Mr. Fern has over 25 years of extensive international
experience in petroleum and minerals exploration, development and financing. Mr.
Fern holds a Bachelor of Science degree from The University of Sydney and has
followed careers in both exploration geophysics and natural resource investment.
ANTHONY J. WALTON has served as Director of the Company since 1994. Mr.
Walton is President of Armstrong Holdings Corp., a private investment company
and corporate finance advisory firm. Previously, Mr. Walton was Chief Executive
Officer of Llama Company, a regional investment bank specializing in private
equity and debt placements for medium-sized companies. Prior to joining Llama
Company, Mr. Walton served as Chief General Manager, Americas and Europe, of
Westpac Banking Corporation of Sydney, Australia, and held various management
positions with Chase Manhattan Bank in New York and London. Mr. Walton received
his Bachelor of Arts degree from Haverford College and a Master of Business
Administration degree in International Finance from the Wharton Graduate School
of Finance at the University of Pennsylvania.
MAYNARD V. SMITH has served as General Manager -- Exploration and
Production since 1990. Mr. Smith has over 20 years of oil and gas exploration
experience and has served in various technical and executive positions with Gulf
Oil Corporation, Tenneco Oil Company, Natomas Oil Company, and Barcoo Petroleum
Company in the United States, Australia and Southeast Asia.
31
<PAGE> 32
Mr. Smith holds a Bachelor of Science degree in Geology from the California
State University at San Diego.
HOWARD H. WILSON, JR. has served as Vice President (Operations) of the
Company since 1993. Between 1981 and 1993, Mr. Wilson held various technical and
managerial positions with Placid Oil Company and Nerco Oil and Gas, Inc.
involving onshore and offshore oil and gas fields in Louisiana. Mr. Wilson holds
a Bachelor of Science degree in Petroleum Engineering from the Louisiana
Polytechnic Institute.
MARK A. GANNAWAY is the Exploration Manager of the Company. Mr. Gannaway
joined the Company in July 1991. Between 1979 and 1988, Mr. Gannaway worked for
Tenneco Oil Company in various technical and supervisory positions and his
career with Tenneco involved working in the Midcontinent and Eastern Gulf of
Mexico regions. From 1988 to 1990 Mr. Gannaway was a geologic consultant in
Lafayette, Louisiana. Mr. Gannaway holds a Bachelor of Science degree in
Geological Engineering from the University of Oklahoma.
PRENT H. KALLENBERGER is the Geophysical Manager of the Company. He joined
the Company in September 1992. Between 1982 and 1992, Mr. Kallenberger worked in
various technical and supervisory positions with Tenneco Oil Company, Union
Pacific Resources, Inc., and Unocal Corporation in California and Texas. Mr.
Kallenberger holds a Bachelor of Science degree in Geology from Boise State
University and a Master of Science degree in Geophysics from the Colorado School
of Mines.
ROSS A. KEOGH has served as Financial Controller and Treasurer of the
Company since 1990 and has 15 years experience in the oil and gas industry.
Between 1979 and 1989, Mr. Keogh worked in the financial accounting and
budgeting divisions of Total Oil Company and as Joint Venture Administrator for
Bridge Oil Limited in Australia. Mr. Keogh holds a Bachelor of Economics degree,
with a major in Accounting, from Macquarie University in Sydney.
Mr. Keogh was appointed as a Director in March 1998.
JAMES E. SLATTEN III was appointed as Manager--Land and Legal in January
1998. He has over 14 years experience in corporate and energy law. Prior to
joining the Company he was a partner in the Louisiana law firm of Gordon, Arata,
McCollam & Duplantis. Mr. Slatten holds a Bachelor of Arts degree in political
science and economics from the University of Southwestern Louisiana and
post-graduate degrees in law (J.D.) and business management (M.H.A.) from Tulane
University. Mr. Slatten was appointed as a Director and Secretary in March 1998.
32
<PAGE> 33
ITEM 11 - EXECUTIVE COMPENSATION
COMPENSATION OF EXECUTIVE OFFICERS
The following table sets forth the compensation paid by the Company for
services rendered during each of the last two fiscal years to or for the
accounts of the Chief Executive Officer and the other six most highly
compensated Executive Officers (collectively, the "Named Executive Officers").
The Company has entered into employment agreements with certain management and
technical personnel. These agreements expire in June 1999.
<TABLE>
<CAPTION>
LONG TERM
COMPENSATION
ANNUAL COMPENSATION AWARDS
-------------------------------- -------------------
OTHER ALL
NAME ANNUAL SECURITIES OTHER
AND COMPEN- UNDERLYING COMPEN-
PRINCIPAL SALARY BONUS SATION OPTIONS/ SATION
POSITION YEAR ($) ($) ($) (2) SARS (3) ($) (4)
- ----------------------- -------- ---------- --------- ----------- ------------------- -----------
<S> <C> <C> <C> <C> <C> <C>
Terrence N. Fern (1) 1997 0 0 0 0 0
Chairman of the 1996 0 0 0 0 0
Board,
Chief Executive
Officer
and President
Alan H. Stevens (5). 1997 175,000 0 61,374 0 125,000
Chief Operating 1996 0 0 0 0 0
Officer
Prent H. Kallenberger 1997 150,000 150,686 0 0 0
Geophysical Manager 1996 139,375 17,114 0 275,000 0
Mark A. Gannaway . .. 1997 150,000 52,747 0 0 0
Exploration Manager 1996 139,375 113,875 0 275,000 0
Jeffrey H. Warren (6) 1997 155,833 31,136 0 0 0
Vice President 1996 169,800 16,263 0 110,000 0
and Secretary
Howard H. Wilson, Jr. 1997 150,000 32,007 0 0 0
Vice President- 1996 140,000 45,561 0 125,000 0
Operations
Ross A. Keogh . . . . 1997 134,500 0 0 0 0
Financial Controller 1996 118,333 10,548 0 110,000 0
and Treasurer
</TABLE>
(1) Mr. Fern receives no compensation from the Company. The Parent made
payments in 1997 and 1996 of $290,000 and $292,334, respectively, to a
company controlled by Mr. Fern's family and which provides management and
geological services to the Parent.
(2) "Other Annual Compensation includes payments to Mr. Stevens of $61,374 for
relocation costs.
(3) Options issued are in respect of ordinary shares in the Parent Company.
(4) "All Other Compensation" includes forgiveness of a loan to Mr. Stevens
for housing assistance.
(5) Mr. Stevens resigned as an Officer and Director of the Company
in December, 1997.
(6) Mr. Warren resigned as an Officer and Director of the Company
in November, 1997
33
<PAGE> 34
SHARE AND OPTION PLANS
The Parent maintains an Employee Share Plan (the "Share Plan") and an
Employee Share Option Plan (the "Option Plan"). Both plans were approved by the
shareholders at the Parent's 1994 Annual General Meeting and are administered by
a committee (the "Remuneration Committee") appointed by the Board of Directors
of the Parent. The total number of Ordinary Shares issued or subject to option
under all share and option plans during any five year period may not exceed 5%
of the total number of issued Ordinary Shares at the relevant date.
The Share Plan provides for the issue of Ordinary Shares to employees and
directors at prevailing market prices. Purchases pursuant to the Share Plan are
financed by interest free loans from the Parent, subject to certain conditions
set by the Remuneration Committee. Grants are subject to a minimum six month
vesting term and the vesting may also be contingent upon the market price of the
Ordinary Shares on the Australian Stock Exchange ("ASX") achieving certain
benchmarks. After the vesting of such shares, the grantee may either repay the
Parent loan or sell such shares and retain the difference. As of December 31,
1997, all employees and directors of the Company, in the aggregate, owned
1,525,000 Ordinary Shares subject to the terms of this Plan.
The Option Plan provides for the issue of options to purchase Ordinary
Shares to employees and directors at prevailing market prices and subject to
certain conditions set by the Remuneration Committee. Grants are subject to a
minimum six month vesting term and the vesting may also be contingent upon the
market price on the ASX of the Ordinary Shares achieving certain benchmarks.
Options granted under the Option Plan expire five years from the date of grant.
As of December 31, 1997, all directors and employees of the Company, in the
aggregate, held options to purchase an aggregate of 1,361,000 Ordinary Shares
pursuant to the Option Plan.
STOCK OPTION GRANTS AND EXERCISES
The Parent did not grant any stock options or stock appreciation rights
("SARs") to the Named Executive Officers of the Company in 1997.
34
<PAGE> 35
The following table sets forth the aggregated option exercises by each of the
Named Executive Officers during the year ended December 31, 1997.
<TABLE>
<CAPTION>
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND
FISCAL YEAR-END OPTIONS VALUE
NUMBER OF VALUE OF
SECURITIES UNEXERCISED
UNDERLYING IN-THE-MONEY
UNEXERCISED OPTIONS AT
OPTIONS AT FISCAL
FISCAL YEAR-END
SHARES VALUE YEAR-END ($)
ACQUIRED ON REALIZED EXERCISABLE/ EXERCISABLE/
Name EXERCISE (#) ($) UNEXERCISABLE UNEXERCISEABLE
----
--------------- ------------- -------------------- ------------------------
<S> <C> <C> <C> <C>
Terrence N. Fern -- $ -- -- /-- -- /--
Alan H. Stevens -- $ -- -- /-- -- /--
Prent H. Kallenberger 270,000 $961,558 -- /275,000 -- /--
Mark A. Gannaway 100,000 $317,276 -- /275,000 -- /--
Jeffrey H. Warren 50,000 $110,355 -- /-- -- /--
Howard H. Wilson, Jr. 50,000 $128,027 -- /125,000 -- /--
Ross A. Keogh -- $ -- --/110,000 -- / $4,430
</TABLE>
COMPENSATION OF DIRECTORS
Anthony J. Walton was paid $20,000 in 1997 and $40,000 in 1996 for services
as a director pursuant to an arrangement whereby Mr. Walton provided financial
advice to the Company. In 1997 Mr. Walton was granted options underlying 50,000
ordinary shares of the Parent Company at an exercise price of A$5.69. The
exercise price for the options is in Australian dollars ("A$") being the
currency of the ordinary shares subject to the options. The expiry date is June
29, 2001. There were no other arrangements pursuant to which directors of the
Company receive compensation for their services as directors in 1997 or 1996.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Common Stock of the Company is owned by Petsec (USA) Inc. which is
a wholly owned subsidiary of the Parent Company, Petsec Energy Ltd. See "Notes
to Financial Statements -- Note 1(a) Description of Business" on page 42.
35
<PAGE> 36
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company has historically been financed in part with borrowings from its
immediate parent company, Petsec (U.S.A.), Inc., which is an indirect
wholly-owned subsidiary of Petsec Energy Ltd. Outstanding borrowings (the
"Subordinated Shareholder Loan") are made by the Company under a subordinated
note (the "Subordinated Shareholder Note") in either or both U.S. or Australian
dollars, which effective as of June 1, 1997 bears interest at market rates,
currently LIBOR plus 1.5% or, in the case of Australian dollar borrowings, the
Australian bank bill rate plus 1.5%. The Subordinated Shareholder Note provides
that the Subordinated Shareholder Loan (i) is subordinated in right of payment
to all present and future Indebtedness of the Company for borrowed money and
(ii) not subject to any mandatory principal or sinking fund payment, or
mandatory repurchase obligation, until 91 days following the final Stated
Maturity of the Notes. The Company has agreed not to modify these two terms of
the Subordinated Shareholder Loan until all outstanding Notes have been paid in
full, retired or acquired in their entirety by Affiliates of the Company. As of
December 31 1997, the amount of Subordinated Shareholder Loan outstanding was
$37.3 million.
Three executives, Mark Gannaway, Prent Kallenberger and Maynard Smith, also
own overriding royalty interests on certain leases held by the Company, which
were issued prior to July 1994 as incentives. As of July 1994, the granting of
overriding royalty interests as an incentive was replaced by grants under the
Parent's Option Plan.
36
<PAGE> 37
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
1. FINANCIAL STATEMENTS
INDEX TO FINANCIAL STATEMENTS
Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . . 38
Balance Sheets as of December 31, 1996, and 1997 . . . . . . . . . . . . . 39
Statements of Operations and Retained Earnings for the years ended
December 31, 1995, 1996 and 1997 . . . . . . . . . . . . . . . . . . . . 40
Statements of Cash Flows for the years ended
December 31, 1995, 1996 and 1997. . . . . . . . . . . . . . . . . . . . 41
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . . 42
37
<PAGE> 38
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Petsec Energy Inc.:
We have audited the accompanying balance sheets of Petsec Energy Inc. as of
December 31, 1996 and 1997 and the related statements of operations and retained
earnings and cash flows for each of the years in the three-year period ended
December 31, 1997. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Petsec Energy Inc. as of
December 31, 1996 and 1997, and the results of its operations and its cash flows
for each of the years in the three-year period ended December 31, 1997 in
conformity with generally accepted accounting principles.
As discussed in note 5 to the financial statements, in 1996 the Parent
Company adopted the method of accounting for stock-based compensation prescribed
by the Statement of Financial Accounting Standards No. 123 for the expense
allocated to the Company.
KPMG PEAT MARWICK LLP
New Orleans, Louisiana
January 30, 1998
38
<PAGE> 39
PETSEC ENERGY INC.
A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
BALANCE SHEETS
(DOLLARS IN THOUSANDS, EXCEPT SHARE AMOUNTS)
<TABLE>
<CAPTION>
December 31,
1996 1997
---------- -----------
<S> <C> <C>
ASSETS
------
Current Assets:
Cash $ 342 $ 7,431
Accounts receivable 11,855 13,978
Other receivables 101 80
Inventories of crude oil 45 43
Prepaid expenses 168 258
----------- -----------
Total Current Assets 12,511 21,790
Property, plant and equipment-- at cost under the successful efforts
method of accounting for oil and gas properties:
Proved oil and gas properties 131,933 227,049
Unproved oil and gas properties 7,276 20,759
Production facilities 38,049 66,956
Other 1,040 1,527
---------- -----------
178,298 316,291
Less accumulated depletion, depreciation
and amortization (44,664) (106,977)
---------- -----------
Net property, plant and equipment 133,634 209,314
Other assets -- 3,000
---------- -----------
Total Assets $ 146,145 $234,104
========== ===========
LIABILITIES AND SHAREHOLDER'S EQUITY
------------------------------------
Current Liabilities:
Trade accounts payable 18,364 15,107
Interest payable 202 1,720
Other accrued liabilities 6,003 11,967
---------- -----------
Total Current Liabilities 24,569 28,794
Senior Subordinated Notes -- 99,630
Bank credit facility 37,000 --
Subordinated shareholder loan 57,954 37,298
Provision for dismantlement 1,738 3,289
Deferred income taxes 9,848 16,458
---------- -----------
Total Liabilities $131,109 $185,469
---------- -----------
Shareholder's Equity:
Common stock, $1 par value; authorized 1,000,000
shares; issued and outstanding 1 share -- --
Additional paid-in-capital 482 20,981
Retained earnings 14,554 27,654
---------- -----------
Total Shareholder's Equity 15,036 48,635
---------- -----------
Total Liabilities and Shareholder's Equity $146,145 $234,104
========== ===========
</TABLE>
See accompanying notes to financial statements.
39
<PAGE> 40
PETSEC ENERGY INC.
A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
Years Ended December 31,
1995 1996 1997
--------- --------- --------
<S> <C> <C> <C>
Revenue:
Oil and gas sales $ 30,462 $ 67,027 $125,139
--------- --------- --------
Operating expenses:
Lease operating expenses 4,269 5,561 10,825
Production taxes 488 600 702
Exploration expenditures including dry hole costs 3,396 7,061 17,782
General and administrative 4,502 5,259 6,054
Stock compensation -- 481 905
Depletion, depreciation and amortization 9,256 29,639 63,864
--------- --------- --------
Total operating expenses 21,911 48,601 100,132
--------- --------- --------
Income from operations 8,551 18,426 25,007
Other income (expenses):
Interest expense (2,452) (3,369) (7,586)
Interest income 64 172 871
Gain on sale of property, plant and equipment 4,312 6 --
Other, principally foreign exchange gain 35 -- 1,418
--------- --------- --------
1,959 (3,191) (5,297)
Income before income taxes 10,510 15,235 19,710
Income tax expense 3,537 6,311 6,610
--------- --------- --------
Net income 6,973 8,924 13,100
Retained earnings (deficit) at beginning of year (1,343) 5,630 14,554
--------- --------- --------
Retained earnings at end of year $ 5,630 $ 14,554 $ 27,654
========= ========= ========
</TABLE>
See accompanying notes to financial statements.
40
<PAGE> 41
PETSEC ENERGY INC.
A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
Years Ended December 31,
1995 1996 1997
---- ---- ----
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 6,973 $ 8,924 $ 13,100
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation and amortization 9,256 29,639 63,864
Amortization of bond issue costs -- -- 190
Deferred income taxes 3,537 6,311 6,610
Gain on sale of property, plant and equipment (4,312) -- --
Dry hole costs and abandonments 545 2 10,454
Stock compensation expense -- 481 905
Other (30) -- (1,418)
Changes in operating assets and liabilities:
Increase in receivables (6,197) (3,523) (2,123)
Decrease (increase) in inventories (78) 43 2
Decrease (increase) in prepayments (140) 23 (90)
Decrease (increase) in other receivables (334) 301 21
Decrease (increase) in other assets (1,937) 1,937 --
Increase (decrease) in trade accounts payable 12,754 (237) (3,257)
Increase in other accrued liabilities 1,337 3,381 5,964
Increase in interest payable 187 15 1,518
---------- ---------- ---------
Net cash provided by operating activities 21,561 47,297 95,740
---------- ---------- ---------
Cash flows from investing activities:
Lease acquisitions (2,792) (6,367) (8,074)
Exploration and development expenditures (50,369) (78,951) (139,871)
Proceeds from sale of property ,plant and equipment 5,500 -- --
Other asset additions (175) (621) (487)
---------- ---------- ---------
Net cash used in investing activities (47,836) (85,939) (148,432)
---------- ---------- ---------
Cash flows from financing activities:
Proceeds from senior subordinated notes -- -- 96,446
Proceeds from bank credit facility 20,025 63,540 21,000
Repayment of bank credit facility (6,000) (58,890) (58,000)
Proceeds from shareholder loans 18,500 36,000 1,500
Repayment of shareholder loans (5,367) (3,084) (1,165)
---------- ---------- ----------
Net cash provided by financing activities 27,158 37,566 59,781
--------- ---------- ----------
Net increase (decrease) in cash 883 (1,076) 7,089
Cash at beginning of year 535 1,418 342
---------- ----------- -----------
Cash at end of year $ 1,418 $ 342 $ 7,431
=========== ============= ===========
</TABLE>
See accompanying notes to financial statements.
41
<PAGE> 42
PETSEC ENERGY INC.
NOTES TO FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Description of Business
Petsec Energy Inc.(the Company), located in Lafayette, Louisiana, is a
wholly-owned subsidiary of Petsec (U.S.A.) Inc., which is a wholly-owned
subsidiary of Petsec America Pty. Limited, a company incorporated in Australia.
The ultimate holding company is Petsec Energy Ltd (the Parent Company),
(formerly Petroleum Securities Australia Limited), also incorporated in
Australia.
The primary business of the Company is exploration, development and
production of oil and gas; therefore, the Company is directly affected by
fluctuating economic conditions of the oil and gas industry. The Company's
activities are focused in the shallow waters of the Gulf of Mexico, primarily
offshore Louisiana and Texas.
(b) Income Taxes
The Company is included in the consolidated federal and state income tax
returns of Petsec (U.S.A.) Inc. The income tax provision has been prepared as
if the Company were a separate taxpayer.
The Company accounts for income taxes under Statement of Financial
Accounting Standards No. 109 (Statement 109), Accounting for Income Taxes. Under
the asset and liability method of Statement 109, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. Under Statement 109, the effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period that
includes the enactment date.
(c) Oil and Gas Properties
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves, and
to drill and equip development wells are capitalized. Costs to drill exploratory
wells that do not find proved reserves, and geological and geophysical costs are
expensed.
Unproved oil and gas properties are periodically assessed on a
property-by-property basis, and a loss is recognized to the extent, if any, that
the cost of the property has been impaired. Capitalized costs of producing oil
and gas properties are depreciated and depleted by the units-of-production
method.
Effective in 1996, the Company began assessing the impairment of
capitalized costs of proved oil and gas properties and other long-lived assets
in accordance with Statement of Financial Accounting Standards No. 121
42
<PAGE> 43
(Statement 121), Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of. Under this method, the Company generally
assesses its oil and gas properties on a field-by-field basis, utilizing its
current estimate of future revenues and operating expenses. In the event net
undiscounted cash flow is less than the carrying value, an impairment loss is
recorded based on estimated fair value, which would consider discounted future
net cash flows. Prior to 1996, this assessment had been determined on a
company-wide basis. The adoption of Statement 121 did not have an effect on the
Company's financial position or results of operations.
The estimated costs of dismantling and abandoning offshore oil and gas
properties are provided currently using the units-of-production method. Such
provision is included in depletion, depreciation and amortization in the
accompanying statement of operations.
On the sale or retirement of a complete unit of a proved property, the
cost and related accumulated depletion, depreciation and amortization are
eliminated from the property accounts, and the resultant gain or loss is
recognized.
(d) Other Property, Plant and Equipment
Depreciation is calculated using the straight-line method over the
estimated useful lives of the assets.
(e) Inventories
Inventories are stated at the lower of cost or market. Cost is determined
principally on the average cost method.
(f) Hedging Activities
The Company uses derivative commodity instruments to manage commodity
price risks associated with future natural gas and crude oil production but does
not use them for speculative purposes. The Company's commodity price hedging
program utilizes swap contracts and collars. To qualify as a hedge, these
contracts must correlate to anticipated future production such that the
Company's exposure to the effects of commodity price changes is reduced. The
gains and losses related to these hedging transactions are recognized as
adjustments to the revenue recorded for the related production. The Company uses
the accrual method of accounting for derivative commodity instruments. At
inception, any contract premiums paid are recorded as prepaid expenses and, upon
settlement of the hedged production month, are included with the gains and
losses on the contracts in oil and gas revenues.
(g) 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 and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
(h) Reclassifications
Certain amounts in prior years' financial statements have been
reclassified to conform to the 1997 financial statement presentation.
43
<PAGE> 44
2. BANK CREDIT FACILITY AND SENIOR SUBORDINATED NOTES
In April 1996, the Company entered into a $75 million revolving credit
facility (the facility) with a syndicate of banks. The facility is a two-year
revolving credit facility followed by a two-year term loan with equal quarterly
amortization payments. The facility matures in the year 2001 and is secured by
the Company's Gulf of Mexico producing properties. Outstanding borrowings accrue
interest at LIBOR plus a margin of 1.25% to 1.50% per annum, depending on the
balance drawn. The Company is obligated to pay a fee of .30% to .35% per annum
of the unused portion of the borrowing base.
At December 31, 1996, borrowings outstanding totaled $37 million at a
weighted average annual interest rate of 7.155% and letters of credit
outstanding totaled $12.21 million. At December 31, 1996, the fair value of the
facility's outstanding borrowings approximated the carrying value. At December
31, 1997, the borrowing base of the bank credit facility was $60 million with no
borrowings outstanding. Letters of credit outstanding totaled $9.96 million. The
facility is subject to certain restrictive covenants.
In June 1997, the Company issued $100 million 9 1/2% Senior Subordinated
Notes due in 2007. The notes were issued at a discount with an annual yield to
maturity of 9.56%. A portion of the proceeds was used to pay the outstanding
balance on the bank credit facility. At December 31, 1997, the fair value of the
notes was $102,625,000 based on quoted market prices. These notes are subject to
certain restrictive covenants.
3. SUBORDINATED SHAREHOLDER LOAN
Petsec (U.S.A.) Inc. had advances outstanding to the Company of $58.0
million and $37.3 million at December 31, 1996 and 1997, respectively. A
summary of activity is as follows (in thousands):
Beginning Ending Balance
Balance Additions Reductions
1995 11,905 18,500 (4,848) 25,038
1996 25,038 36,000 (3,084) 57,954
1997 57,954 1,500 (22,156) 37,298
The average balance outstanding for the years ended 1995, 1996 and
1997 was $13.7 million, $33.6 million, and $47.0 million, respectively.
Prior to June 1, 1997, the advances were without interest charges or
fixed repayment terms. Effective June 1, 1997, Petsec (U.S.A.) Inc. began
charging the Company interest on the subordinated shareholder loan. At December
31, 1997, the rates were 7.18% for U.S. dollar loans and 6.83% for Australian
dollar loans. The Company is unable to determine the fair value of these loans
because they are with a related party. In addition, effective June 1, 1997, $20
million of the outstanding subordinated shareholder loan was recapitalized as
equity. Petsec (U.S.A.) Inc. has confirmed that no repayments will be required
prior to December 31, 2007.
44
<PAGE> 45
4. SIGNIFICANT CUSTOMERS
Customers which account for 10% or more of revenue for the years ended
December 31, 1995, 1996 and 1997 follow:
1995 1996 1997
---- ---- ----
Vision Resources, Inc. 55% 60% 46%
Aquila Energy Marketing Corporation 30% 12% *
Duke Energy Trading & Marketing, L.L.C., formerly
Pan Energy Trading & Marketing Services, L.L.C. 13% 19% 22%
P G & E Energy Trading Corporation - - 16%
Natural Gas Clearinghouse * * 12%
* less than 10%
Based upon the current demand for oil and gas, the Company does not
believe the loss of any current purchasers would have a material adverse effect
on the Company. The Company continually evaluates the financial strength of its
customers but does not require collateral to support trade receivables.
5. STOCK COMPENSATION EXPENSE
The Parent Company has an Employee Option Plan and issues options to
employees and certain consultants of the Company to purchase stock in the Parent
Company. The Parent Company's equity securities are traded on both the
Australian Stock Exchange and The Nasdaq Stock Market SM.
The Company is allocated stock compensation expense in respect to the
options in the Parent Company which are granted to the Company's employees and
certain consultants. Prior to 1996, the Parent Company accounted for its expense
related to the stock option plan in accordance with the provisions of Accounting
Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees,
and related interpretations. In 1996, the Parent Company adopted Statement of
Financial Accounting Standards No. 123 (Statement 123), Accounting for
Stock-Based Compensation, under which it recognizes as expense over the vesting
period the fair value of all stock-based awards on the date of grant. The amount
is recorded as an increase to additional paid-in-capital. The fair value was
determined using the Black-Scholes valuation method. The calculation takes into
account the exercise price, expected life, current price of underlying stock,
expected volatility of the underlying stock, expected dividend yield and the
risk-free interest rate. The expected life, volatility, dividend yield and
risk-free interest rates used in determining the fair value of options granted
in 1996 were 2.1 to 3.5 years (weighted average 3.0 years); 30%; 0; and 7.1% to
8.4% per annum (weighted average 8% per annum), respectively, and 1.5 to 2.5
years (weighted average 2.1 years); 30%; 0; and 5.8% to 6.5% per annum (weighted
average 6.1% per annum), respectively, in 1997.
6. INCOME TAXES
Although the Company is included in the consolidated federal and state
income tax returns of Petsec (U.S.A.) Inc., the income tax provision has been
prepared as if the Company were a separate taxpayer. Income tax expense
attributable to income from continuing operations was $3.5 million, $6.3 million
and $6.6 million for the years ended December 31, 1995, 1996 and 1997
45
<PAGE> 46
respectively, and differed from the amounts computed by applying the U.S.
federal income tax rate of 34% to income before income taxes as a result of the
following:
<TABLE>
<CAPTION>
1995 1996 1997
---- ---- ----
(dollars in thousands)
<S> <C> <C> <C>
Computed "expected" tax expense $ 3,573 $ 5,180 $ 6,701
Increase (reduction) in income taxes resulting from:
Items not deductible for tax 78 550 30
State income taxes 282 322 368
Other -- 259 (489)
Change in the beginning of the year balance of the valuation
allowance for deferred tax assets allocated to income tax
expense (396) -- --
--------- --------- --------
$ 3,537 $ 6,311 $ 6,610
========= ========= ========
</TABLE>
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at December 31,
1996 and 1997 are presented below.
<TABLE>
<CAPTION>
1996 1997
---- ----
(dollars in thousands)
<S> <C> <C>
Deferred tax assets:
Financial provisions not currently deductible for tax purposes $ 1,160 $ 1,091
Net operating loss carryforwards 17,167 16,823
--------- --------
Total gross deferred tax assets 18,327 17,914
--------- --------
Deferred tax liabilities:
Differences in depreciation and depletion of oil and gas assets (28,175) (34,372)
--------- --------
Net deferred tax liability $ (9,848) $(16,458)
========= ========
</TABLE>
At December 31, 1997, the Company has net operating loss carryforwards for
federal income tax purposes of $46.7 million which are available to offset
future federal taxable income, if any, through 2012. Although realization is not
assured, management believes that it is more likely than not that all of the
deferred tax assets will be realized.
7. RELATED PARTY TRANSACTIONS
The Parent Company has advanced funds to Petsec Energy Inc. through its
wholly-owned subsidiaries, Petsec America Pty. Limited and Petsec (U.S.A.) Inc.
(Note 3). The funds were used to finance operations.
For the years ended December 31, 1995, 1996 and 1997, Petsec Energy Inc.
paid an amount of $630,000, $1.0 million and $540,000 to the Parent Company
principally for reimbursement of direct expenses incurred in connection with the
Company's operations.
46
<PAGE> 47
8. COMMITMENTS AND CONTINGENCIES
Future minimum lease commitments at December 31, 1997, applicable to
noncancelable operating leases with terms of one year or more are summarized as
follows (in thousands):
Year
1998 $ 225
1999 208
2000 69
-----
$ 502
=====
Rent expense for the years ended December 31, 1995, 1996 and 1997 was
$239,000, $281,000 and $264,000, respectively.
9. ADDITIONAL PAID-IN-CAPITAL
The following is a reconciliation of additional paid-in-capital for 1997:
Balance at December 31, 1996 $ 482
Recapitalization of loan 19,594
Stock Options 905
--------
Balance at December 31, 1997 $ 20,981
========
10. HEDGING ACTIVITIES
Energy Swaps:
The Company enters into forward swap contracts with major financial
institutions to reduce the price volatility on the sale of oil and gas
production. In swap agreements, the Company receives the difference between a
fixed price per unit of production and a floating price issued by a third party.
If the floating price is higher than the fixed price, the Company pays the
difference. At December 31, 1997, the Company had contracts maturing monthly
through May 2000 on the net sale of 1.6 million barrels of oil at an average
price of $20.02 per barrel and on the net sale of 19.4 million mmbtu of gas at
an average price of $2.155 per mmbtu. The effect to the Company to terminate
these contracts at December 31, 1997 is estimated to be a gain of $2.5 million
for oil and a cost of $1.6 million for gas.
For the years ended December 31, 1995, 1996 and 1997, hedging activities
increased revenues by $0.8 million and reduced revenues by $8.4 million and $4.4
million, respectively.
Collars:
The Company enters into collar agreements with third parties. A collar
agreement is similar to a swap agreement except that the Company receives the
difference between the floor price and the floating price if the floating price
is below the floor. The Company pays the difference between the ceiling price
and the floating price if the floating price is above the ceiling. At December
31, 1997, the Company had 3,480,000 mmbtu of gas hedged through December 1998 in
costless collars with an average floor price of $2.27 per mmbtu and an average
ceiling price of $3.69 per mmbtu. The effect to the Company to terminate these
contracts at December 31, 1997 is estimated to be a gain of $0.4 million.
47
<PAGE> 48
11. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest was $2.3 million, $3.4 million and $6.8 million for
the years ended December 31, 1995, 1996 and 1997, respectively. The Company has
not paid any cash for income taxes in these years.
12. LITIGATION
The Company is involved in certain lawsuits arising in the ordinary course
of business. While the outcome of any of these lawsuits cannot be predicted with
certainty, management expects these matters to have no material adverse effect
on the financial position, results of operations or liquidity of the Company.
13. SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate that 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 be expected to be
recovered through existing wells with existing equipment and operating methods.
Prior to December 31, 1996 the Company had a June 30 fiscal year end. As
such, reserve data for December 31 was unavailable prior to 1995.
Estimates of proved and proved developed reserves at June 30, 1994 and
1995 and December 31, 1995, 1996 and 1997 were based on studies performed
by Ryder Scott Company.
No major discovery or other favorable or adverse event subsequent to
December 31, 1997 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
48
<PAGE> 49
ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES
The following table sets forth the Company's net proved reserves,
including the changes therein, and proved developed reserves (all within the
United States) as estimated by Ryder Scott Company:
<TABLE>
<CAPTION>
Crude Oil Natural Gas
(MBbl) (MMcf)
<S> <C> <C>
Proved developed and undeveloped reserves:
June 30, 1994 2,650 12,830
Revisions of previous estimates 2,861 293
Extensions, discoveries and other additions 2,210 11,194
Production (583) (3,556)
Sale of reserves in place (257) (434)
--------- ---------
June 30, 1995 6,881 20,327
Revisions of previous estimates (675) (482)
Extensions, discoveries and other additions 1,624 35,783
Production (658) (5,881)
--------- ---------
December 31, 1995 7,172 49,747
Revisions of previous estimates 211 2,297
Extensions, discoveries and other additions 3,085 32,969
Production (2,150) (11,722)
--------- ---------
December 31, 1996 8,318 73,291
Revisions of previous estimates 2,220 12,194
Extensions, discoveries and other additions 3,181 64,604
Production (3,078) (27,940)
--------- ---------
December 31, 1997 10,641 122,149
========= =========
Crude Oil Natural Gas
(MBbl) (MMcf)
Proved developed reserves:
December 31, 1995 6,962 25,852
December 31, 1996 6,670 43,133
December 31, 1997 8,430 88,199
</TABLE>
Capitalized costs for oil and gas producing activities consist of the
following:
<TABLE>
<CAPTION>
As of December 31,
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
Proved properties $86,082 $169,982 $294,005
Unproved properties 5,859 7,276 20,759
--------- --------- --------
91,941 177,258 314,764
Accumulated depreciation, depletion and amortization (15,484) (44,349) (106,392)
-------- -------- ---------
Net capitalized costs $76,457 $132,909 $208,372
======== ========= ========
</TABLE>
49
<PAGE> 50
Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:
Years Ended December 31,
1995 1996 1997
(in thousands)
Lease acquisition $ 2,930 $ 6,699 $ 8,437
Exploration 34,786 71,490 115,523
Development 12,925 14,187 31,327
------- ------- -------
Total costs incurred $50,641 $92,376 $155,287
======= ======= ========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS REVENUES
The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures
about Oil and Gas Producing Activities" (SFAS No. 69) and based on natural gas
and crude oil reserve and production volumes estimated by Ryder Scott Company.
It may be useful for certain comparative purposes, but should not be solely
relied upon in evaluating the Company or its performance. Further, information
contained in the following table should not be considered as representative of
realistic assessments of future cash flows, nor should the Standardized Measure
of Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.
The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (4)
future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying period end oil and gas prices adjusted for fixed and determinable
escalations including hedged prices to the estimated future production of
period-end proved reserves. As of December 31, 1997, approximately 19.4 million
mmbtu of the Company's future gas production and 1.6 million barrels of oil were
subject to such positions. Future cash inflows were reduced by estimated future
development, abandonment and production costs based on period-end costs in order
to arrive at net cash flow before tax. Future income tax expense has been
computed by applying period-end statutory tax rates to aggregate future pretax
net cash flows, reduced by the tax basis of the properties involved and tax
carryforwards. Use of a 10% discount rate is required by SFAS No. 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
50
<PAGE> 51
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows:
<TABLE>
<CAPTION>
As of June As of December 31,
30, --------------------------------------
1995 1995 1996 1997
(in thousands)
<S> <C> <C> <C> <C>
Future cash inflows $154,139 $251,971 $479,220 $472,470
Future production costs (32,022) (36,163) (58,367) (101,765)
Future development and abandonment costs (19,600) (25,105) (47,873) (53,851)
Future income tax expense (21,143) (43,552) (102,669) (64,064)
-------- -------- --------- --------
Future net cash flows after income taxes 81,374 147,151 270,311 252,790
10% annual discount for estimated timing of cash flows (16,238) (15,663) (46,930) (48,676)
-------- -------- --------- --------
Standardized measure of discounted future net cash flows $ 65,136 $131,488 $223,381 $204,114
========= ========= ========= ========
</TABLE>
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves is as follows:
<TABLE>
<CAPTION>
Year Ended 6 Months Ended Year Ended
June 30, December 31, December 31,
-------- -------------- ---------------------
1995 1995 1996 1997
(in thousands)
<S> <C> <C> <C> <C>
Beginning of the period $ 30,122 $65,136 $131,488 $223,381
-------- -------- --------- --------
Sales and transfers of oil and gas produced, net of production
costs (12,482) (17,791) (60,764) (113,462)
Net changes in prices and production costs 4,532 19,708 61,394 (142,243)
Extensions, discoveries and improved recoveries, net of 76,642 88,947 145,494 134,467
future production costs
Net changes due to revisions in quantity estimates (1,220) 2,547 10,070 40,994
Development costs incurred during the period -- 4,200 8,945 1,050
Sales of reserves in place (3,140) -- -- --
Change in estimated future development costs (4,050) (10,355) (26,208) (5,674)
Accretion of discount (13,174) 1,505 12,079 32,481
Net change in income taxes (12,094) (22,409) (59,117) 33,120
-------- --------- --------- --------
Net increase (decrease) 35,014 66,352 91,893 (19,267)
-------- --------- --------- --------
End of period $ 65,136 $131,488 $223,381 $204,114
======== ========= ========= ========
</TABLE>
The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1997 was based on
average natural gas prices of approximately $2.39 per mcf and on average liquids
of approximately $17.00 per barrel. Had March 1998 prices been used, the
Company's standardized measure of discounted future net cash flows relating to
proved oil and gas reserves at December 31, 1997 would have been reduced.
51
<PAGE> 52
2. FINANCIAL STATEMENTS SCHEDULES
None
3. EXHIBITS
Exhibit No. Exhibit
----------- -------
4.1 Articles of Incorporation of the Company (filed with Registration
Statement on Form S-4 (No. 333-31625) and included herein
by reference)
4.2 By-Laws of the Company (filed with Registration Statement on
Form S-4 (File No. 333-31625) and included herein by reference)
4.3 Indenture dated as of June 13, 1997 among the Company, as
issuer, and the Bank of New York, as trustee (filed with
Registration Statement on Form S-4. (File No 333-31625)
and is included herein by reference)
4.4 Registration Rights Agreement dated June 13, 1997 by and among
the Company and Merrill Lynch & Co., Merrill, Lynch, Pierce,
Fenner & Smith Incorporated, Donaldson, Lufkin & Jenrette
Securities Corporation and Salomon Brothers Inc. (filed with
Registration Statement on Form S-4 (File No. 333-31625) and
included herein by reference)
10.1 Credit Agreement by and among Petsec Energy Inc. and Chase
Manhattan Bank and certain financial institutions named therein
as Lenders (filed with Registration Statement on Form S-4 filed
(File No. 333-31625) and included herein by reference)
23.1* Consent of Ryder Scott Company
24.1* Power of Attorney (included on the signature pages of this Annual
Report)
27* Financial Data Schedule
- -----------------------
* Filed herewith
4. REPORTS ON FORM 8-K
No Reports were filed.
52
<PAGE> 53
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, this 31st day of
March 1998.
Petsec Energy Inc.
By: /s/Ross A. Keogh
-------------------------------
Name: Ross A. Keogh
Title:Director and Treasurer
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Ross A. Keogh, his true and lawful
attorney-in-fact and agent, with full power of substitution and resubstitution,
for him and in his name, place and stead, in any and all capacities, to sign on
his behalf individually and in each capacity stated below any and all amendments
to this annual report, and to file the same, with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission,
granting unto said attorney-in-fact and agent, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said
attorney-in-fact and agent, or his substitutes, may lawfully do or cause to be
done by virtue hereof.
Name Title Date
---- ----- ----
/s/Terrence N. Fern Chairman and Chief Executive March 31, 1998
- ----------------------- Officer (Principal Executive
Terrence N. Fern Officer)
/s/Anthony J. Walton March 31, 1998
- -----------------------
Anthony J. Walton Director
/s/James S. Slatten III March 31, 1998
- -----------------------
James S. Slatten III Director and Secretary
53
<PAGE> 54
EXHIBIT INDEX
Exhibit No. Exhibit
----------- -------
4.1 Articles of Incorporation of the Company (filed with Registration
Statement on Form S-4 (No. 333-31625) and included herein
by reference)
4.2 By-Laws of the Company (filed with Registration Statement on
Form S-4 (File No. 333-31625) and included herein by reference)
4.3 Indenture dated as of June 13, 1997 among the Company, as
issuer, and the Bank of New York, as trustee (filed with
Registration Statement on Form S-4. (File No 333-31625)
and is included herein by reference)
4.4 Registration Rights Agreement dated June 13, 1997 by and among
the Company and Merrill Lynch & Co., Merrill, Lynch, Pierce,
Fenner & Smith Incorporated, Donaldson, Lufkin & Jenrette
Securities Corporation and Salomon Brothers Inc. (filed with
Registration Statement on Form S-4 (File No. 333-31625) and
included herein by reference)
10.1 Credit Agreement by and among Petsec Energy Inc. and Chase
Manhattan Bank and certain financial institutions named therein
as Lenders (filed with Registration Statement on Form S-4 filed
(File No. 333-31625) and included herein by reference)
23.1* Consent of Ryder Scott Company
24.1* Power of Attorney (included on the signature pages of this Annual
Report)
27* Financial Data Schedule
- -----------------------
* Filed herewith
<PAGE> 1
EXHIBIT 23.1
[RYDER SCOTT COMPANY LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
As independent petroleum engineers, we hereby consent to the use of
our name in the Annual Report and Form 10K of Petsec Energy Inc., for the
period ended December 31, 1997. We further consent to the inclusion of our
estimate of reserves and present value of future net reserves in such Annual
Report.
/s/ RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
March 26, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 7,431
<SECURITIES> 0
<RECEIVABLES> 14,058
<ALLOWANCES> 0
<INVENTORY> 43
<CURRENT-ASSETS> 21,790
<PP&E> 316,291
<DEPRECIATION> 106,977
<TOTAL-ASSETS> 234,104
<CURRENT-LIABILITIES> 28,794
<BONDS> 99,630
0
0
<COMMON> 0
<OTHER-SE> 48,635
<TOTAL-LIABILITY-AND-EQUITY> 234,104
<SALES> 125,139
<TOTAL-REVENUES> 125,139
<CGS> 0
<TOTAL-COSTS> 100,132
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,586
<INCOME-PRETAX> 19,710
<INCOME-TAX> 6,610
<INCOME-CONTINUING> 13,100
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 13,100
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
