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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
(Mark One)
[ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g)
OF THE SECURITIES EXCHANGE ACT OF 1934
OR
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the twelve months ended December 31, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from........................to.....................
Commission file number 0-28608
PETSEC ENERGY LTD
(Exact name of Registrant as specified in its charter)
NEW SOUTH WALES, AUSTRALIA
(Jurisdiction of incorporation or organization)
LEVEL 13, GOLD FIELDS HOUSE, 1 ALFRED STREET, SYDNEY, NSW 1225, AUSTRALIA
(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.
American Depositary Shares
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.
107,601,041 Ordinary Shares
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 which financial statement item the registrant has
elected to follow.
Item 17 [ ] Item 18 [X]
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TABLE OF CONTENTS
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Page
<S> <C>
Introduction........................................................................ 3
Glossary of Certain Industry Terms.................................................. 4 - 5
PART I
Item 1. Description of Business.............................................. 6 - 18
Item 2. Description of Properties............................................ 19
Item 3. Legal Proceedings.................................................... 19
Item 4. Control of Registrant................................................ 20
Item 5. Nature of Trading Market............................................. 20 - 22
Item 6. Exchange Controls and Other Limitations Affecting Security Holders... 22 - 23
Item 7. Taxation............................................................. 23 - 24
Item 8. Selected Financial Data.............................................. 25 - 27
Item 9. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................. 27 - 37
Item 9A. Quantitative and Qualitative Disclosure about Market Risk... ....... 37 - 38
Item 10. Directors and Officers of Registrant................................. 39 - 40
Item 11. Compensation of Directors and Officers............................... 40 - 41
Item 12. Options to Purchase Securities from Registrant or Subsidiaries....... 40 - 41
Item 13. Interest of Management in Certain Transactions....................... 40 - 41
PART II
Item 14. Description of Securities to be Registered........................... 41
PART III
Item 15. Defaults Upon Senior Securities...................................... 42
Item 16. Changes in Securities................................................ 42
PART IV
Item 17. Financial Statements................................................. 42
Item 18. Financial Statements................................................. 42
Signatures.......................................................................... 43
Item 19. Financial Statements and Exhibits.................................... F1 - F24 and
.................................................................................... Ex-23.1 and Ex-23.2
</TABLE>
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PART I
INTRODUCTION
Unless the context otherwise indicates, references in this Form 20-F to
"Petsec" or the "Company" are to Petsec Energy Ltd, an Australian public
limited company (Australian Company Number 000 602 700), and its
majority-owned subsidiaries and entities in which it owns at least a 50%
ownership interest. The Company publishes consolidated financial statements in
Australian dollars as required under Australian law and under Australian
generally accepted accounting principles ("Australian GAAP"). It also
publishes consolidated financial statements in US dollars and under US
generally accepted accounting principles ("US GAAP") as set out under Item 18
in this Form 20-F. On previous Forms 20-F, the Company provided US dollar
financial statements prepared in accordance with Australian GAAP, with a
reconciliation to US GAAP. All financial information in this Form 20-F is
based on US GAAP.
As used herein the term "fiscal" prior to a calendar year means the Company's
fiscal year ended June 30 of such year until June 30, 1996 and the Company's
fiscal years ended December 31, 1997 and 1998. The Company's fiscal year end
changed in 1996 from June 30 to December 31 and this report covers the fiscal
year ended June 30, 1996, the six month period ended December 31, 1996 and the
fiscal years ended December 31, 1997 and 1998.
References to "US dollars" or "US$" or "$" are to United States dollars and
references to "A$" are to Australian dollars.
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GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below apply to the indicated terms as used in this
Form 20-F. 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 of gas 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.
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.
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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 expense 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.
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.
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PART I
ITEM 1 - DESCRIPTION OF BUSINESS
GENERAL
Petsec Energy Ltd is an independent oil and gas exploration and
production company operating in the shallow waters of the Gulf of Mexico. It
is an Australian public company with ADRs listed on the New York Stock
Exchange (symbol: PSJ). 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, 1998 and after taking into account the sale of a
50% working interest in certain of its oil and gas properties to Apache
Corporation ("Apache"), the Company's estimated net proved reserves were 90.3
Bcfe (approximately 65% of which were attributable to natural gas), with a
PV10 of approximately $67.1 million.
The Company owns 44 leases on the Outer Continental Shelf, of which,
effective January 1, 1999, 23 leases are held in a 50% joint venture with
Apache. The Company is currently negotiating to farm out a number of the 21
leases in which it owns a 100% interest.
BUSINESS STRATEGY
The Company has assembled a team of geologists, geophysicists and
engineers with an extensive base of knowledge regarding geophysical processing
and interpretation of data, as well as field operating practices in the Gulf
of Mexico. 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.
Until recently, the Company held 100% working interests in its Gulf
of Mexico properties, unlike many other independent energy companies that
conduct business through fractional working interests and non-operated joint
ventures. Effective January 1, 1999, the Company sold a 50% working interest
in a substantial number of the properties to Apache, a third party independent
E&P company. It also transferred operations on the properties sold. 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.
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 been previously applied and in unexplored areas.
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.
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CLIMAX MINING LTD
The Company owns approximately 39 million ordinary shares,
representing a 44% interest, in Climax Mining Ltd ("Climax"), a
publicly-traded international minerals exploration company based in Sydney,
Australia. Climax's exploration activities are focussed on gold and
copper-gold porphyry deposits located along the Pacific Rim, in particular in
the Philippines. The ordinary shares of Climax are traded on the Australian
Stock Exchange under the symbol "CMX" and the closing stock price on April 23,
1999 was A$0.20 per share ($0.13 per share based on the Noon Buying Rate).
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, 1996 and December 31, 1996, 1997 and
1998. All information 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 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.
December 31, 1998 reserves are shown net of the sale to Apache of a
50% working interest in certain of the Company's oil and gas properties which
was effective January 1, 1999.
<TABLE>
<CAPTION>
AS OF JUNE 30, AS OF DECEMBER 31,
1996 1996 1997 1998
<S> <C> <C> <C> <C>
TOTAL NET PROVED:
Oil (MBbls) 10,217 8,318 10,641 5,337
Gas (MMcf) 61,880 73,291 122,149 58,252
Total (MMcfe) 123,182 123,199 185,995 90,274
NET PROVED DEVELOPED:
Oil (MBbls) 8,084 6,670 8,430 3,054
Gas (MMcf) 31,043 43,133 88,199 26,965
Total (MMcfe) 79,547 83,153 138,779 45,289
Estimated future net revenues
before income taxes
(in thousands) $263,067 $372,980 $316,855 $83,132
Present value of estimated future
net revenues before income taxes
(in thousands) (1) $210,000 $308,226 $255,839 $67,053
Standardized measure of
discounted future net cash flows
(in thousands) (2) $160,542 $223,381 $204,114 $67,053
Average prices used in calculating the
net present values:
Oil ($ per Bbl) $ 19.73 $ 25.09 $ 17.00 $ 11.98
Gas ($ per Mcf) $ 2.70 $ 3.68 $ 2.39 $ 2.04
</TABLE>
(1) The present value of estimated future net revenues attributable to the
Company's reserves was prepared using constant prices, including the
effects of hedging as of the calculation date, discounted at 10% per
annum on a pre-tax basis. These prices have varied significantly from
year to year, affecting the net present values, and are not necessarily
representative of current prices.
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(2) 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.
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 in the Gulf of Mexico
during the period indicated. This table does not include costs incurred in
other areas in the United States or in Australia.
<TABLE>
<CAPTION>
FISCAL YEAR SIX MONTHS FISCAL YEARS
ENDED TO ENDED
JUNE 30, DECEMBER 31, DECEMBER 31,
1996 1996 1997 1998
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<S> <C> <C> <C> <C>
Acquisition costs $ 7,577 $ 44 $ 8,437 $ 7,836
Exploration costs 53,974 46,147 115,523 107,111
Development costs 15,345 6,966 31,327 10,301
------- ------- -------- --------
Total costs incurred $76,896 $53,157 $155,287 $125,248
======= ======= ======== ========
</TABLE>
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,
1998.
<TABLE>
<CAPTION>
GROSS NET (5)
<S> <C> <C>
Productive wells (1):
Oil (2) 16 8
Gas (3) 36 19
----- -----
Total 52 27
===== =====
Developed Acreage (1) 51,786 28,393
Undeveloped Acreage (1) (4) 89,252 78,201
------ ------
Total 141,038 106,594
======= =======
</TABLE>
(1) Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting 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.
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(2) Two gross oil wells each have dual completions.
(3) Fourteen gross gas wells each have dual completions.
(4) Leases covering 11% of the Company's undeveloped acreage will expire in
1999, 17% in 2000, 27% in 2001, 12% in 2002 and 33% in 2003.
(5) Net wells and acreage are shown after giving effect to the sale to Apache
of a 50% working interest in certain properties effective January 1, 1999.
Drilling activity. The following table sets forth the Company's drilling
activity for the periods indicated.
<TABLE>
<CAPTION>
Fiscal year ended Six months to Fiscal years ended
June 30, December 31, December 31,
1996 1996 1997 1998
Gross Net Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Gulf of Mexico
Exploratory wells 4 4 1 1 13 13.0 4 4
Development wells 4 4 3 3 4 4.0 1 1
Dry holes 0 0 0 0 3 2.4 3 3
---- ---- ---- ---- ---- ---- ---- ----
Total 8 8 4 4 20 19.4 8 8
---- ---- ---- ---- ---- ---- ---- ----
</TABLE>
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 on 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 "Item 9 - 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.
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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
1998, Duke Energy Trading & Market Services, L.L.C. and Columbia Energy
Services 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.
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 extensively regulated by United States
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 are under constant review
for amendment and expansion for 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 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 or complying with such regulations.
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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 has under consideration proposals to change the method of
calculating royalties and the valuation of crude oil produced from federal
leases. These changes, if adopted, would modify the valuation procedures for
crude oil to reduce use of posted prices and assign a value to crude oil
intended to better reflect market value. The Company cannot predict at this
stage how it might be affected if the MMS adopts such changes.
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
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.
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 although recent price declines for natural gas
may, in part, reflect increased competition and more efficient gas
transportation resulting from Order No. 636. The Courts have largely affirmed
the significant features of Order No. 636 and numerous related orders
pertaining to the individual pipelines, although certain appeals remain
pending and the FERC continues to review and modify its open access
regulations. In particular, the FERC has recently begun a broad review of
11
<PAGE> 12
its transportation regulations, including how they operate in conjunction with
state proposals for retail gas marketing restructuring, whether to eliminate
cost-of-service rates for short-term transportation, whether to allocate all
short-term capacity on the basis of competitive auctions, and whether changes
to its long-term transportation policies may also be appropriate to avoid a
market bias toward short-term contracts. The Company cannot predict what
action the FERC will take on these matters, nor can it accurately predict
whether the FERC's actions will, over the long-term, 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 the 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 new
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.
In Order Nos. 561 and 561-A the FERC established 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 affirmed by the courts. The Company
does not believe that these rules affect it any differently than other oil
producers and marketers with which it competes.
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.
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 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.
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<PAGE> 13
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 non-hazardous 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 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 $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 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 operator will provide evidence of financial responsibility on
properties in which the Company has non-operating working interest. The
Company will satisfy OPA responsibility obligations with respect to its other
properties through insurance over the level of $200,000 which is the Company's
self-insurance amount. 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.
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<PAGE> 14
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.
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, explosion,
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 they operate.
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 33 full-time staff, primarily
professionals, including geologists, geophysicists and engineers, with 24 of
the staff in Lafayette, Louisiana, USA and 9 in Australia. 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 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 of 1933 and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). Except for
statements of historical facts included in this Annual Report, all statements,
including without limitation statements under "Item 9 - Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Item 1- Description of Business" regarding the planned capital expenditures,
oil and gas production, the Company's financial position, business strategy
and other plans and objectives for future 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.
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SUBSTANTIAL LEVERAGE
As of December 31, 1998, the Company's total debt was $173.7 million,
of which $99.7 million was senior subordinated notes maturing on June 15, 2007
and $74 million was borrowings under the Company's bank credit facility. In
February 1999, upon settlement of the $68.3 million sale to Apache of certain
of its oil and gas properties, the Company repaid $65 million of bank debt,
reducing total debt to $108.7 million.
The Company's level of indebtedness will have several important
effects on its operations, including (i) a significant 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 9 - Management's Discussion
and Analysis of Financial Condition and Results of Operations Capital
resources and liquidity."
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 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 9 - Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Item 1- Description of 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
15
<PAGE> 16
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 50% of the Company's total proved reserves at December
31, 1998 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 - Description of 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 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 Description
of 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 $155 million during 1997 and $124 million during 1998.
As a result of the sale of 50% working interest in certain properties to
Apache, the Company's 1999 revenues and cash flows will be significantly
reduced. Similarly its 1999 capital budget in respect of those properties will
also significantly reduce. In addition, the Company is currently discussing
farm-out proposals on a number of its exploration properties to reduce its
risk and financial exposure in the testing of prospects on these properties.
However, if revenues or cash flows from operations further 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 9
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Capital resources and liquidity."
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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 - Description of Business - Regulation."
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 Officers of 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 - Description of Business Competition."
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<PAGE> 19
RISK 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 9 - Management's Discussion and
Analysis of Financial Condition and Results of Operations - Hedging
transactions" and "Item 1 - Description of Business - Oil and gas marketing."
OWNERSHIP INTEREST IN CLIMAX
The Company currently owns an equity interest in Climax. No assurance
can be given as to the value of the Company's investment in Climax, which will
be affected by a number of factors including the business results of Climax.
There are many uncertainties in any mineral exploration and development
program, such as the location of economic ore bodies, the receipt of necessary
government permits and the construction of mining and processing facilities,
as well as widely fluctuating prices of minerals. Substantial time may elapse
from the initial phases of mining until operations are commercial.
Furthermore, although the securities of Climax are traded in Australia, such
values are not necessarily representative of any consideration which the
Company could obtain for its investment, currently or in the future.
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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, 1998 the
Company had 44 lease blocks in the Gulf of Mexico. All of the Company's proved
oil and gas reserves at December 31, 1998 were in these blocks. Effective
January 1, 1999 a 50% working interest in 23 of the leases was sold to Apache.
ITEM 2 (B) - RESERVES
The information on the Company's oil and gas reserves is set out
under Item 1 on page 7.
The information on the Company's oil and gas production is set out
under Item 9 on page 28.
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.
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ITEM 4 - CONTROL OF REGISTRANT
The following table sets forth certain information regarding the
beneficial ownership of the Company's ordinary shares ("Ordinary Shares") as
of May 17, 1999 by each person who is known by the Company to own beneficially
10% or more of the Ordinary Shares and by all directors and executives of the
Company and Petsec Energy Inc, as a group. The percentages herein have been
calculated based on the 107,501,041 Ordinary Shares outstanding on May 17,
1999.
<TABLE>
<CAPTION>
NUMBER OF PERCENTAGE
NAME ORDINARY SHARES BENEFICIALLY OWNED
<S> <C> <C>
All Directors and executives as a group
(10 persons) (1) (2) (3) 29,188,816 27.1%
Terrence N. Fern (2) (3) 28,386,498 26.4%
Den Duyts Corporation Pty Limited (3) 18,344,639 17.1%
</TABLE>
(1) Includes Ordinary Shares held by family-controlled entities or
companies associated with such individuals. Also includes Ordinary
Shares reflected for Terrence N. Fern, Chairman and Managing Director
of the Company. See Notes (2) and (3) below.
(2) Includes 4,000 Ordinary Shares held by Mr. Fern directly; 1,500,000
Ordinary Shares held by Mr. Fern pursuant to the Company's Employee
Share Plan; 96,509 Ordinary Shares held by a trust of which Mr. Fern is
a shareholder of the corporate trustee; 6,470,661 Ordinary Shares held
by a trust of which Den Duyts Corporation Pty Limited ("Den Duyts") is
a shareholder and Mr. Fern is a director of the corporate trustee;
1,966,689 Ordinary Shares held by a corporation of which Mr. Fern is a
shareholder; 18,344,639 Ordinary Shares held by a trust Den Duyts; and
4,000 Ordinary Shares held by a minor child. Excludes 4,000 Ordinary
Shares held by Mr. Fern's wife of which he disclaims that he is the
beneficial owner and 8,000 Ordinary Shares held by Mr. Fern's son of
which he disclaims that he is the beneficial owner (as defined under
Rule 13D-3 of the Securities Exchange Act of 1934 (the "Exchange Act")
("Beneficial Owner")). See Note (3) below.
(3) Den Duyts is a company which acts as the trustee of a trust, the
beneficiaries of which include members of Mr. Fern's family. Mr. Fern
is deemed to be the Beneficial Owner of such shares.
Under Australian law a shareholder is required to disclose to the
Company if the shareholder is "entitled" to 5% or more of the Company's
Ordinary Shares. A shareholder making such disclosure is required to
aggregate with the shares held personally and beneficially by such
shareholder any other shares in which the shareholder or an "associate"
of the shareholder has a "relevant interest". Under Australian law, a
person has a "relevant interest" in a share held by another person if
the first person or a corporate entity controlled by the first person
has the right to exercise or control the exercise of the voting rights
in respect of that share or has the power to dispose of or control the
disposal of that share. An "associate" is defined broadly and includes
any person with whom the first person has an agreement, arrangement or
understanding relating to control over shares, or with whom the first
person proposes to act in concert. The "relevant" interests of Den
Duyts including its associates at May 17, 1999, were 28,395,498
Ordinary Shares and the "relevant" interests of Mr. Fern were
28,386,498 Ordinary Shares.
ITEM 5 - NATURE OF TRADING MARKET
The trading market for the Company's Ordinary Shares is the
Australian Stock Exchange Limited ("ASX"), which is the only stock exchange in
Australia. On August 29, 1996 the Company's industry classification changed
from Diversified Resources (Oil, Gold, Investment) to Oil and Gas (Oil/Gas
Producer). The Company's symbol on the ASX is "PSA".
20
<PAGE> 22
All on-market transactions for the Company's shares are executed on
the ASX's electronic trading system and information on transactions is
therefore immediately available. Current ASX settlement requirements are
within five days after the transaction.
Effective July 23, 1996 the Company's American Depositary Receipts
("ADRs") commenced quotation and trading on the Nasdaq National Market
(symbol: PSALY) and on May 18, 1998 transferred to the New York Stock Exchange
(symbol: PSJ). Each ADR evidences one American Depositary Share ("ADS"), which
represents five Ordinary Shares. The depositary of the ADRs representing the
ADSs is The Bank of New York ("Depositary").
As at March 31, 1999 5,362,235 ADRs were on issue. These were
equivalent to 26,811,175 Ordinary Shares or approximately 25% of the Company's
issued capital.
The following table sets forth, for the periods indicated, the high
and low closing sale prices per Ordinary Share as reported on the ASX in
Australian dollars and translated into US dollars at the Noon Buying Rate on
the respective dates on which such closing prices occurred, unless otherwise
indicated.
<TABLE>
<CAPTION>
A$ US$
High Low High Low
<S> <C> <C> <C> <C>
Year ended June 30, 1996:
First Quarter 3.40 2.10 2.59 1.49
Second Quarter 3.40 2.70 2.53 2.02
Third Quarter 3.60 3.20 2.69 2.39
Fourth Quarter 4.95 3.25 3.92 2.54
Six Months ended December 31, 1996:
First Quarter 5.88 4.80 4.65 3.80
Second Quarter 6.00 5.00 4.73 3.94
Year ended December 31, 1997:
First Quarter 7.02 4.95 5.42 3.95
Second Quarter 6.53 4.85 4.97 3.76
Third Quarter 7.25 5.90 5.22 4.34
Fourth Quarter 7.30 4.02 5.33 2.63
Year ended December 31, 1998:
First Quarter 5.69 4.07 3.76 2.65
Second Quarter 6.50 4.21 4.17 2.57
Third Quarter 5.70 1.70 3.59 1.00
Fourth Quarter 1.85 0.43 1.10 0.27
Year ended December 31, 1999:
First Quarter 0.53 0.34 0.33 0.22
</TABLE>
21
<PAGE> 23
The following table sets forth for the periods indicated the high and low
closing prices per ADR on the New York Stock Exchange in US dollars:
<TABLE>
<CAPTION>
US$
High Low
<S> <C> <C>
Six Months ended December 31, 1996:
First Quarter (from July 23, 1996) 23.25 19.75
Second Quarter 23.63 20.00
Year ended December 31, 1997:
First Quarter 27.38 19.63
Second Quarter 25.13 18.63
Third Quarter 26.75 21.75
Fourth Quarter 26.63 13.06
Year ended December 31, 1998:
First Quarter 16.50 13.50
Second Quarter 21.75 13.44
Third Quarter 17.00 4.94
Fourth Quarter 5.56 1.38
Year ended December 31, 1999:
First Quarter 1.88 1.00
</TABLE>
ITEM 6 - EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS
The Australian government currently does not impose any limits,
including any foreign exchange controls, that restrict the export or import of
capital by the Company or that affect the remittance of dividends, interest or
other payments to non-resident holders of the Company's securities (except as
set out below). Any transfer of Australian or foreign currency of A$10,000 or
more by a person and any international funds transfer into or out of Australia
by certain banks and other cash dealers must be reported to the Australian
government's Transaction Reports and Analysis Centre (AUSTRAC). See also
"Taxation - Australian Taxation" for a discussion of the Australian dividend
withholding tax.
There is no provision in Australian law (except as stated below) or
in the Company's constituent documents that prevents or restricts a
non-resident of Australia from freely owning and voting the Ordinary Shares
which underlie the Company's ADRs.
Non-Australian shareholders should be aware that Australian law
contains certain provisions that may apply if a significant interest in the
Ordinary Shares is proposed to be acquired. The following brief discussion of
relevant Australian law restrictions on non-Australian ownership of securities
is in no way intended to be an exhaustive statement of the Australian
position. The discussion does not address general restrictions in Australian
law on securities ownership per se.
The Australian Foreign Acquisitions and Takeovers Act of 1975 (the
"Foreign Takeovers Act") requires notification to the Australian government of
any proposed acquisition by a foreign person which would result in such person
and any of its associates controlling not less than 15% of the voting power or
holding an interest in not less than 15% of the shares of an Australian
company with total assets valued at A$5 million or more. Upon receipt of such
notification, the Australian government has the authority to review such
acquisition. The Australian government also has the authority to review any
transaction involving two or more foreign persons who, with their associates,
are able to control at least 40% of the voting power or hold interests in not
less than 40% of the shares of an Australian corporation. Under its present
policy and except in certain special cases, the Australian government will
automatically approve such acquisitions if the corporation has total assets of
less than A$50 million. Where the corporation has assets in excess of A$50
million (as does the Company), the Australian government either may permit the
proposed acquisition to proceed subject to conditions or may prohibit the
transaction as contrary to the national interest. Under the terms of the
Foreign Takeovers Act, ownership of ADRs will constitute ownership of shares
or voting power of the Company.
22
<PAGE> 24
Section 709 of the Australian Corporations Law requires a shareholder
who is entitled (within the meaning of the Australian Corporations Law) to 5%
or more of the voting shares of a corporation (a "substantial shareholder") to
notify the corporation of such shareholding within two business days after the
shareholder becomes aware that the shareholder is a substantial shareholder.
Section 710 of the Australian Corporations Law requires a substantial
shareholder to further notify the corporation when its entitlement changes by
an amount equal to 1% or more of the voting shares. Under Australian
Corporations Law, a person who holds an ADR is deemed to be entitled to the
underlying shares.
Section 615 of the Australian Corporations Law prohibits, subject to
the making of a formal takeover offer or certain limited exceptions, a
shareholder from acquiring shares in an Australian company if the acquisition
would result in the shareholder having an entitlement (within the meaning of
the Australian Corporations Law) to more than 20% of the voting shares of the
corporation (or the acquisition would result in a shareholder who is already
entitled to not less than 20% but less than 90% of the shares becoming
entitled to a greater percentage).
The Australian Trade Practices Act of 1974 regulates, among other
matters, offshore acquisitions affecting Australian markets. Under Section 50A
of such Act, the Australian Competition Tribunal may, in certain
circumstances, make a declaration that prohibits a corporation from carrying
on business in a particular market for goods and services in Australia where a
foreign acquisition would have the effect or be likely to have the effect of
substantially lessening competition in that market. Such acquisitions may be
examined by the Australian Competition Tribunal on public interest grounds.
Shareholders who could possibly be affected by any of the above
legislation should seek independent advice from a qualified Australian
attorney.
ITEM 7 - TAXATION
AUSTRALIAN TAXATION
The following is a summary of the principal Australian tax
consequences of the purchase, ownership and sales of ADSs (which are evidenced
by ADRs) by United States resident shareholders. It is not a complete analysis
or listing of all the possible tax consequences of such purchase, ownership
and sale. Such shareholders therefore should consult their tax advisors with
respect to the tax consequences of the purchase, ownership and the sale of
Ordinary Shares or ADRs, including consequences under state and local tax
laws.
The taxation treatment of a United States resident shareholder of
Ordinary Shares or ADRs will depend on the particular circumstances of that
shareholder. The following summarizes the general principles of the
application of Australian taxation laws.
To the extent that dividends paid to United States resident
shareholders are "unfranked" (essentially, not paid out of profits which have
borne Australian tax), pursuant to Australian tax laws and the
Australia/United States Double Taxation Agreement they will be subject to a
15% Australian dividend withholding tax except where the shares are
effectively connected with a permanent establishment of a United States
shareholder who carries on business in Australia or with a fixed base of a
United States shareholder who provides independent personal services in
Australia, in which case they will be subject to ordinary Australian tax
rates. The Company may pay a dividend out of foreign profits which, even
though unfranked, would not be subject to Australian dividend withholding tax.
United States resident securities traders who are not residents of
Australia for tax purposes are not subjected to Australian tax on capital
gains arising on the sale of the Ordinary Shares or ADRs provided that the
investor and its associates do not at any time during the five years preceding
disposal beneficially own 10% or more of the Company's issued share capital.
23
<PAGE> 25
Under the New South Wales Stamp Duties Act no New South Wales stamp
duty will be payable on the acquisition or disposal of ADRs. Any transfer of
Ordinary Shares will in most cases require the payment of New South Wales
Stamp Duty calculated at 0.3% of the transaction value. If the transfer takes
place on the ASX, the stamp duty is split between the transferor and
transferee. If the transfer does not take place on the ASX, the transferee is
liable for the full stamp duty, and the transfer cannot be registered until
the duty is paid.
UNITED STATES FEDERAL TAXATION
The following is a summary of the principal United States federal
income tax consequences of the purchase, ownership and sale of ADSs (which are
evidenced by ADRs) by a citizen, resident or corporation of the United States
(as the case may be, a "US Holder"). It is not a complete analysis or listing
of all of the possible tax consequences of such purchase, ownership and sale
and does not address tax consequences to special persons such as tax-exempt
entities and corporations owning at least 10% of the stock of the Company.
Shareholders therefore should consult their tax advisors with respect to the
tax consequences of the purchase, ownership and sale of Ordinary Shares or
ADRs, including consequences under the estate and local tax laws.
TAXATION OF CASH DIVIDENDS
For United States federal income tax purposes, US Holders of ADRs
generally will be treated as the owners of the underlying Ordinary Shares.
Dividends paid with respect to the Ordinary Shares represented by ADRs will be
includable in the gross income of the US Holder as ordinary income when the
dividends are received by the Depositary and will not be eligible for the
dividends received deduction generally allowed to corporations under the
Internal Revenue Code of 1986, as amended, and will be treated as foreign
source dividend income. Dividends paid in Australian dollars will be
includable in income in the US dollar amount based on the exchange rate on the
date such dividends are paid by the Company. US Holders of ADRs will be
required to recognize their share of any exchange gain or loss realized by the
Depositary upon the conversion of Australian dollars into US dollars and any
such gain or loss will be ordinary gain or loss.
TAXATION OF WITHDRAWALS
US Holders of ADRs that exercise their right to withdraw Ordinary
Shares from the Depositary in exchange for the ADR representing such ADRs will
generally not be subject to United States federal income tax on such
withdrawal. The aggregate basis of the Ordinary Shares so received will be
equal to the US Holder's aggregate adjusted basis on ADRs exchanged therefor.
TAXATION OF CAPITAL GAINS
A US Holder that holds ADRs as a capital asset will recognize capital
gain or loss for United States federal income tax purposes upon a sale or
other disposition of such ADRs in an amount equal to the difference between
such US Holder's basis in the ADRs and the amount realized on their
disposition. Such capital gain or loss will be deemed long-term capital gain
or loss if the US Holder holds such ADRs for more than one year. Certain
limitations exist on the deductibility of capital losses by both corporate and
individual taxpayers. Capital gains and losses on the sale or other
disposition by a US Holder of ADRs generally will constitute gains or losses
from sources within the United States.
24
<PAGE> 26
ITEM 8 - SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The following table sets forth in US dollars and under US GAAP
selected historical consolidated financial data for the Company as of and for
each of the periods indicated. The financial data for the fiscal year ended
June 30, 1996, the six months ended December 31, 1996 and the two fiscal years
ended December 31, 1997 and 1998 is derived from the Company's US Dollar
Financial Statements, which were prepared under US GAAP. The following data
should be read in conjunction with "Item 9 -Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the financial
statements and notes thereto included elsewhere in this Annual Report.
25
<PAGE> 27
<TABLE>
<CAPTION>
Six months to Fiscal year ended
Fiscal years ended June 30 December 31 December 31
1994 1995 1996 1996 1997 1998
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas sales (net of royalties) $ 13,919 $ 17,031 $ 51,150 $ 37,521 $ 125,139 $ 92,017
--------- --------- --------- --------- --------- ---------
Lease operating expenses 3,714 3,808 6,892 3,279 11,527 14,989
Depletion, depreciation and amortization 4,736 5,661 21,098 15,368 63,903 57,672
Exploration expenditure 2,921 2,697 2,175 5,249 7,328 7,427
Dry hole and abandonment costs - - 1,145 - 10,454 27,503
Impairment expense - - - - - 72,916
General, administrative and other expenses 2,558 4,543 7,001 3,339 9,001 10,777
Stock compensation expense - 102 1,749 677 1,461 937
--------- --------- --------- --------- --------- ---------
Total operating expenses 13,929 16,811 40,060 27,912 103,674 192,221
--------- --------- --------- --------- --------- ---------
Income (loss) from operations (10) 220 11,090 9,609 21,465 (100,204)
Other income (expense) 117 52 223 - 132 (86)
Profit (loss) on sale of assets (14) 4, 257 7,208 31 68
Interest expense (745) (1,725) (3,687) (1,472) (6,022) (9,044)
Interest income 115 210 485 822 1,685 1,214
Equity in income (loss) of affiliates 709 (3,864) 282 (1,326) (1,595) -
--------- --------- --------- --------- --------- ---------
Income (loss) before tax 172 (811) 8,650 14,841 15,696 (108,052)
Income tax benefit (expense) 138 465 (895) (3,888) (5,416) 11,547
--------- --------- --------- --------- --------- ---------
Net income (loss) $ 310 $ (346) $ 7,755 $ 10,953 $ 10,280 $ (96,505)
--------- --------- --------- --------- --------- ---------
BASIC AND DILUTED EARNINGS PER SHARE:
Earnings (loss) per ordinary share $ 0.00 $ (0.01) $ 0.09 $ 0.10 $ 0.10 $ (0.90)
Earnings (loss) per ADR (1) $ 0.02 $ (0.02) $ 0.45 $ 0.52 $ 0.48 $ (4.48)
Weighted average number of ordinary
shares outstanding 74,773 75,874 86,297 104,977 107,320 107,601
CASH FLOW DATA:
Net cash provided by operating activities $ 6,676 $ 9,572 $ 38,601 $ 26,454 $ 90,806 $ 55,056
Net cash used in investing activities (15,724) (24,559) (73,228) (33,227) (145,790) (134,750)
Net cash provided by financing activities 7,891 15,291 37,734 15,760 61,512 74,011
BALANCE SHEET DATA:
Total assets $ 43,338 $ 63,857 $ 125,690 $ 161,083 $ 247,962 $ 199,213
Current maturities - credit facility - - - - - 67,250
Borrowings less current maturities 8,700 14,900 52,000 37,000 99,630 106,406
Shareholders' equity 19,967 20,904 47,479 91,401 101,155 4,355
</TABLE>
(1) No ADRs were issued prior to June 30, 1996; net income (loss) per ADR
has been calculated by dividing net income (loss) by the weighted
average number of ordinary and ordinary equivalent shares outstanding,
multiplied by five (the Ordinary Share to ADR ratio).
EXCHANGE RATES
Where US dollar amounts in this Form 20-F have not been derived from
the Financial Statements (and therefore translated using the exchange rates in
the notes to the Financial Statements), the translations of Australian dollars
into US dollars (unless otherwise indicated) have been made at the appropriate
Noon Buying Rate as specified.
26
<PAGE> 28
The following table sets forth certain information with respect to
historical exchange rates, using the Noon Buying Rates for Australian dollars
expressed in US dollars per Australian dollar:
<TABLE>
<CAPTION>
US Dollar Per Australian Dollar
Period Average* High Low End of Period
<S> <C> <C> <C> <C>
Year ended June 30, 1994 0.6926 0.7438 0.6450 0.7310
Year ended June 30, 1995 0.7412 0.7778 0.7108 0.7108
Year ended June 30, 1996 0.7627 0.8026 0.7100 0.7856
Six months ended December 31, 1996 0.7928 0.8180 0.7721 0.7944
Year ended December 31, 1997 0.7385 0.7978 0.6490 0.6515
Year ended December 31, 1998 0.6295 0.6868 0.5550 0.6123
January 1, 1999 through April 23, 1999 0.6352 0.6520 0.6179 0.6516
</TABLE>
* Average of Noon Buying Rates for the period based on month end rates
Fluctuations in the Australian dollar/US dollar exchange rate will
affect the US dollar equivalent of the Australian dollar price of the
Company's Ordinary Shares on the ASX and, as a result, are likely to affect
the market price of the Company's ADRs in the United States. Such fluctuations
also would affect the US dollar amounts received by holders of ADRs on
conversion by the Depositary of cash dividends, if any, paid in Australian
dollars on the Ordinary Shares underlying the ADRs.
The Company's primary operations are in the United States, and its
sales and operation costs are denominated predominantly in US dollars. For the
foreseeable future, therefore, fluctuations in the Australian dollar/US dollar
exchange rate are expected to have only a small effect on the Company's
underlying performance, as measured in US dollars, and on the Company's
financial statements prepared in US dollars, other than any impact which might
arise from the Company's investment in Climax. Such fluctuations would affect
the Company's financial results as reported in Australian dollars.
The Company has not paid any dividends for the fiscal year ended June
30, 1996, the six month period ended December 31, 1996 and years ended
December 31, 1997 and 1998.
ITEM 9 - 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 financial position for the fiscal year ended June 30, 1996,
the six month period ended December 31, 1996 and the fiscal years ended
December 31, 1997 and 1998. The Financial Statements for these periods are set
out under Item 18 and should also be referred to in conjunction with the
following discussion.
OVERVIEW
The Company's income from operations is almost exclusively generated
from its operations in the Gulf of Mexico, which is the primary focus of this
discussion. For the periods discussed, however, other factors also impacted
income from operations and net income, which are discussed below under the
caption "Other Operating Expenses and Results."
The Company has acquired substantially all of its 44 leases in the
Gulf of Mexico at federal or state lease sales. A disappointing drilling
program in 1998 compounded by low oil and gas prices caused the Company's
outstanding debt to reach unacceptable levels. In December 1998, the Company
agreed to sell to Apache a 50% working interest in 17 developed leases and 6
exploration leases. In addition, Apache assumed operatorship of the assets.
The $68.3 million sale was effective January 1, 1999 and completed on February
1, 1999, reducing bank debt to $9 million and total debt to $108.7 million.
The $100 million of interest-only subordinated notes are due for repayment in
2007.
27
<PAGE> 29
The Company is currently producing from 18 of its lease blocks.
Production increased significantly from 24,622 MMcfe in 1996 to 46,408 MMcfe
in 1997, but through natural decline decreased in 1998 to 39,511 MMcfe. As of
December 31, 1998, after giving effect to the Apache sale, the Company's net
proved reserves were 90.3 Bcfe , 65% of which were natural gas.
The Company accounts for its oil and gas operations under 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'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.
The Company markets its oil through spot price contracts and typically
receives a premium above the price posted. Gas produced is sold under
contracts that primarily reflect spot market conditions in the central Gulf of
Mexico. The Company has historically entered into crude oil and natural gas
swaps to reduce its exposure to price fluctuations. The results of operations
described herein reflect any hedging transactions undertaken by the Company.
See note 9(d) to the Financial Statements.
The following table sets forth certain operating information with
respect to the oil and gas operations of the Company.
<TABLE>
<CAPTION>
Fiscal year ended Six months to Years ended
June 30, December 31, December 31,
-------- ---------------- -------------------------
1996 1995 1996 1996 1997 1998
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Net production:
Oil (MBbls) 1,680 670 1,145 2,155 3,078 2,353
Gas (MMcf) 11,529 5,881 6,074 11,722 27,940 25,390
Total (MMcfe) 21,609 9,901 12,944 24,652 46,408 39,511
Net sales data (in thousands):
Oil $ 29,937 $ 10,674 $ 24,904 $ 44,168 $ 60,369 $ 37,846
Gas 21,213 10,773 12,617 23,056 64,770 54,171
------- -------- -------- -------- -------- --------
Total $ 51,150 $ 21,447 $ 37,521 $ 67,224 $125,139 $ 92,017
-------- -------- -------- -------- -------- --------
Average sales prices (1):
Oil (per Bbl) $ 17.82 $ 15.93 $ 21.75 $ 20.50 $ 19.61 $ 16.08
Gas (per Mcf) 1.84 1.83 2.08 1.97 2.32 2.13
Total (per Mcfe) 2.37 2.17 2.90 2.73 2.70 2.33
Average costs (per Mcfe):
Lease operating expenses $ 0.32 $ 0.36 $ 0.25 $ 0.26 $0.25 $ 0.38
Depletion, depreciation
and amortization 0.98 0.72 1.19 1.20 1.38 1.46
General, administrative
and other expenses 0.32 0.31 0.26 0.29 0.19 0.27
</TABLE>
(1) Includes effects of hedging activities.
28
<PAGE> 30
RESULTS OF OPERATIONS
FISCAL 1998 COMPARED TO FISCAL 1997
General. The Company drilled and/or sidetracked eight wells
during the year ended December 31, 1998, of which three have been brought into
production, two encountered mechanical difficulties and are suspended pending
further evaluation, and three were plugged and abandoned. Production in 1998
of 39.5 Bcfe was 15% less than 1997 due to natural decline and disappointing
drilling results.
Oil and Gas Revenues. Oil and gas revenues for 1998 were $92
million, a decrease of $33.1 million, or 26% below 1997 revenues of $125.1
million. A 24% decrease in oil production coupled with an 18% decrease in oil
prices combined to account for $22.5 million of the decrease. A 9% decrease in
gas production and an 8% decrease in the gas price accounted for the remaining
$10.6 million of the decrease.
The average realized gas price in 1998 was $2.13 per Mcf, or 2%
above the $2.08 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 $16.08 per Bbl, or 20% above the $13.36 per Bbl that
would have otherwise been received if no hedging had taken place. In 1997 the
average realized gas price was $2.32 per Mcf, or 8% below the $2.53 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 $19.61 per
Bbl, or 3% above the $19.10 per Bbl that would have otherwise been received if
no hedging had taken place. Hedging activities resulted in a $7.7 million
increase in revenues for 1998 compared to a $4.4 million decrease in 1997.
Lease Operating Expenses. Lease operating expenses in 1998 were
$15.0 million, an increase of $3.5 million, or 30%, from $11.5 million in
1997. The increase was attributable to workovers and recompletions in wells
with declining production from zones that were first perforated. These costs
coupled with lower production resulted in the per unit rate increasing from
$0.25 per Mcfe in 1997 to $0.38 per Mcfe in 1998.
Depletion, Depreciation and Amortization ("DD&A"). DD&A expense
decreased $6.2 million, or 10%, from $63.9 million in 1997 to $57.7 million in
1998. Lower production accounted for a decrease of $9.5 million partially
offset by an increase in the average rate per unit from $1.38 to $1.46 per
Mcfe. The increase in the unit rate was due to increased costs of drilling
goods and services, platform and facilities construction and transportation
services in the industry. Lower commodity prices caused Ryder Scott downward
reserve revisions in the fourth quarter and the unit DD&A rate increased to
$1.80 per Mcfe in that quarter compared to an average rate of $1.36 for the
preceding three quarters.
Exploration Expenditures and Dry Hole Costs. The Company uses the
successful efforts method to account for oil and gas exploration, evaluation
and development expenditures. Under this method $27.5 million was expensed for
dry hole costs and $7.4 million for seismic, geological and geophysical
expenditures was expensed as incurred in 1998. In 1997 expenses were $10.5
million for dry hole costs and $7.3 million for seismic, geological and
geophysical expenditures.
Impairments. A non-cash charge of $72.9 million reflecting the impact
of lower commodity prices on the carrying value of the Company's oil and gas
properties was expensed in 1998. There were no impairments recorded in 1997.
General and Administrative Expense. General and administrative
expense increased $1.8 million, or 20%, to $10.8 million in 1998 from $9.0
million in 1997.
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FISCAL 1997 COMPARED TO THE TWELVE MONTHS TO DECEMBER 1996
The comparison of fiscal 1997 has been made against the twelve months
in 1996, which cover six months of the transition period ending December 31,
1996 (when the Company changed its year end) and the second six months of
fiscal 1996, which ended on June 30, 1996.
General. The Company drilled twenty wells during fiscal 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 $57.9 million, or 86% above 1996 revenues of $67.2
million. A 43% increase in oil production offset by a 4% decrease in oil
prices combined to account for $16.2 million of the increase. A 138% increase
in gas production and a 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 successful 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 $20.50 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 a $8.4 million decrease in 1996.
Lease operating expenses. Lease operating expenses in 1997 were $11.5
million, an increase of $5.2 million, or 83%, from $6.3 million in 1996. The
increase was attributable to increased production. Lease operating expenses
per Mcfe were reduced to $0.25 in 1997, compared with $0.26 in 1996.
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 $25.9 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 proved reserve estimates by the Company's petroleum engineers, Ryder
Scott Company, in the fourth quarter the unit DD&A rate per Mcfe was reduced
to $1.25 per Mcfe compared to an average rate of $1.41 per Mcfe 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 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 in 1996 totaled $7.1 million.
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SIX MONTHS TO DECEMBER 1996 COMPARED TO SIX MONTHS TO DECEMBER 1995
General. Following the setting of a larger production facility at
Ship Shoal 193 and the completion and tie back of two wells at Main Pass 91,
the Company's net production increased 31% in the six months to December 31,
1996 compared with the same period in 1995.
Net oil and gas revenues. Net oil and gas revenues for the six month
period to December 1996 were $37.5 million, an increase of 75% over the
corresponding period in 1995. Net production of 12.9 Bcfe in the six month
period to December 1996 was 31% higher than the corresponding period in 1995.
The average sales price for oil and gas increased by 37% and 14% respectively.
In the six month period to December 31, 1996 gas hedging activities
resulted in an average realized price of $2.08 per Mcf, or 16% below the $2.48
per Mcf price that would otherwise have been received. Over the same period,
oil price hedging resulted in an average realized price of $21.75 per Bbl, or
2% below the $22.14 per Bbl price that would otherwise have been received.
Hedging activities resulted in a $3.6 million decrease in oil and gas
revenues. In the six month period to December 31, 1995 gas hedging activities
resulted in an average realized price of $1.83 per Mcf, or 3% above the $1.77
per Mcf that would otherwise have been received. Over the same period oil
hedging resulted in an average realized price of $15.93 per Bbl, or 4% above
the $15.38 per Bbl that would otherwise have been received. Hedging activities
resulted in a $622,000 increase in oil and gas revenues.
Lease operating expenses. Lease operating expenses for the six month
period to December 1996 were $3.3 million, 9% less than the corresponding
period in 1995. Lease operating expenses per Mcfe decreased from $0.36 to
$0.25 continuing the trend of previous years reflecting economies of scale
from higher rates of production.
Depletion, depreciation and amortization ("DD&A"). DD&A expense for
the six month period to December 1996 increased to $15.4 million (117%) from
$7.1 million, compared to the corresponding period in 1995. The increase was
principally attributable to the increase in oil and gas production in the 1996
period. The depletion rate per unit of $1.19 per Mcfe for the six month period
to December 1996 increased from $0.72 per Mcfe for the corresponding period in
1995. The increase in the unit rate was due to increased capital expenditures
from the Company's exploration and development activities.
Exploration expenditures. The Company uses the successful efforts
method to account for oil and gas exploration, evaluation and development
expenditure. Under this method $5.2 million of seismic, geological and
geophysical expenditures were expensed as incurred during the six month period
to December 1996. This was an increase of 253% over the expenditure of $1.5
million for the six months to December 31, 1995 as the Company expanded its
access to a broader seismic base in the Gulf of Mexico.
OTHER OPERATING EXPENSES AND RESULTS
The Company's results in the past three years have been increasingly
dominated by the results of the Gulf of Mexico operations, which now
contribute almost all of the revenue and the income from operations of the
Company.
Non-Gulf of Mexico operations. Since June 1996 the Company has not
had any material operations outside the Gulf of Mexico. Until December 31,
1994 the oil and gas operations in the United States included the Company's
interests in the Paradox Basin in Colorado. The interests were sold for $5.5
million, effective January 1, 1995, generating a pre-tax profit for the
Company of $4.3 million.
The Company has small gas-producing interests in California, which
are not material to the overall results. The Company's former oil interests in
Australia contributed sales revenue of $0.5 million in fiscal 1996. The
Company sold these Australian interests for approximately $0.3 million on June
24, 1996.
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General, administrative and other expenses. The Company's general and
administrative costs are incurred both in Lafayette and in the head office in
Australia. These expenses have increased from $4.5 million in fiscal 1995 to
$7.0 million in fiscal 1996, $3.3 million in the six months to December 31,
1996, $9.0 million in fiscal 1997 and $10.8 million in fiscal 1998.
Contributing to this increase are costs associated with increased activity and
the sale of a 50% working interest in certain properties to Apache which
resulted in severance charges of $422,000 related to employee terminations. On
a per Mcfe basis the rate increased 54% from $0.13 to $0.20 due to the costs
noted above and decreased production. As a result of the sale to Apache, the
Company significantly reduced its workforce which may result in future general
and administrative expense savings.
Sale of assets. In the six months to December 31, 1996 the Company
recorded a profit before tax of $7.2 million on the sale of assets. This
represented 56% of the surplus above book value of the Company's share of its
interest in the gold/copper project at Didipio in the Philippines when it was
sold in July 1996 to Climax (which in turn is 44% owned by the Company). There
were no significant asset sales in fiscal 1997 or fiscal 1998.
Interest expense. The net interest expense of the Company has risen,
reflecting the increased borrowings of the Company due to the expansion of its
activities and, to a lesser extent, an increased effective interest rate.
Borrowings net of cash deposits decreased from $48.5 million at June 1996 to
$24.5 million at December 1996, reflecting amongst other matters the ADR
capital raising in July 1996. In 1997 net borrowings increased to $80.7
million at December 31, 1997. The increase in interest rates in 1997 was
mainly due to the repayment of a bank credit facility by borrowings under a
senior subordinated note issue with a ten year maturity at a higher interest
rate. Interest expense in 1998 increased 54% to $11.7 million due to increased
borrowings under the bank credit facility from nil to $74 million. Details of
the interest rates are set out in "Item 9A - Quantitative and Qualitative
Disclosure About Market Risk".
Equity investments. The equity-accounted income and loss now relates
only to the Company's 44% holding in Climax. In fiscal 1998, Climax's
principal activity was the finalizing of the feasibility study of the
gold/copper project at Didipio in the Philippines. In addition there was
activity on exploration projects in Australia, the Philippines and South
America.
The Didipio project is in the pre-development phase. As yet Climax
has not made a decision to proceed with mining. The study has included
drilling to define the extent and grade of the gold and copper resources at
the Dinkidi deposit at Didipio and its geological model, metallurgical
testwork, ore processing studies and environmental studies. Pre-development
work is continuing.
In earlier periods Climax's principal activities also included the
operations of its gold mine in New South Wales, Australia (which ceased
operations in the final quarter of calendar 1995), a 50% interest in the
commercial building in Sydney sold in May 1996 and the realization of various
investments. In fiscal 1996, the equity-accounted loss was reduced by the
profit on the disposal of Climax's 19% holding in Solomon Pacific Resources
NL, an Australian gold mining company.
The periods up to and including fiscal 1996 also included the
Company's equity-accounted income in respect of its 50% interest in a
commercial building held jointly with Climax. The income brought to account in
fiscal 1996 was $0.4 million. The building was sold in May 1996 and therefore
had no effect on income in the six months to December 31, 1996 or fiscal 1997
and fiscal 1998.
The Company's results will continue to equity account the results of
Climax as long as the Company holds an investment in Climax of between 20% and
50% (and below 20% in certain circumstances). In turn, the Company expects
Climax's results themselves to reflect its expenditure on exploration
projects, the results of operations arising from any successful development of
exploration projects and the disposal of any of its assets. However, the
carrying value of the Company's investment in Climax was reduced to nil during
fiscal 1997, and further losses in Climax (for example, due to expensing
exploration expenditures) will have no effect on the equity accounted result
in the Company as long as the carrying value is nil. No equity income (loss)
from the Company's investment in Climax was recognized in fiscal 1998 and will
not be recognized in future
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periods until all unrecognized equity losses of Climax are recouped.
Tax matters. In fiscal 1998, 1997, the six months to December 31,
1996 and in fiscal 1996 the Company brought to account nil, $0.6 million, $1.4
million and $2.5 million, respectively, of accumulated tax losses in Australia
that had not previously been recognized as deferred tax assets. These losses
mainly arose from exploration deductions.
The effective tax rate has altered due to a variety of factors, in
particular the Company's share of Climax's tax expense on its Australian
profits, the tax on the profit upon the sale of the Company's interest in the
Didipio project, the fact that the Company's equity-accounted share of its
expenditure at Didipio in the Philippines had not been tax effected and the
recognition of valuation allowances (primarily in 1998) on carry forward
losses due to the uncertainty of future realization.
Net operating losses and other carryforwards. For US federal income
tax purposes, at December 31, 1998 the Company had net operating losses
("NOLs") of approximately $98.7 million which are available to offset future
federal taxable income, if any, from 2005 through 2018.
For alternative minimum tax purposes, NOLs may be further adjusted to
determine the allowable alternative tax NOLs, and the alternative tax NOLs can
be used to offset no more than 90% of alternative minimum tax income.
Accordingly, the Company may owe an alternative minimum tax even though its
NOLs otherwise eliminated its regular tax liability.
CAPITAL RESOURCES AND LIQUIDITY
Since 1990 the Company has financed its operations and growth
primarily with cash flow from operations, bank borrowings, equity offerings
and asset sales. The Company made an initial cash investment of $11.4 million
in its US operations, and, subsequently, increased this investment with
advances of $18.4 million from an Australian offering of 8.3 million Ordinary
Shares in September 1995 and the public offering of 4,000,000 American
Depositary Receipts (each representing 5 Ordinary Shares) at $19 per ADR,
raising $70.4 million, net of costs in July 1996. $41.2 million of this was
used to buy back the 11.7 million Ordinary Shares held by affiliate company,
Climax, under approval from shareholders granted in June 1996. $13.7 million
was also raised at the same time from selling the Company's interest in the
gold/copper project at Didipio in the Philippines.
In response to changing market conditions and restricted capital
availability, the Company will take a more risk diverse approach to its
exploration and development program. This will result in a much lower capital
budget than previous years. The Company was recently the high bidder on two
leases at the March 18, 1999 lease sale with one lease awarded recently and
the second still to be confirmed. If both are awarded by the MMS the cost to
the Company is $1.9 million, which currently can be met from net operating
cash flows. The Company intends to finance its 1999 drilling program with cash
on hand, cash flow from operations and proceeds from farm-outs of certain oil
and gas properties. The success of the drilling program will determine the
amount of funds required for development expenditures and, accordingly,
additional capital may have to be raised at that time. The capital expenditure
budget is continually re-evaluated based on drilling results, commodity
prices, cash flow from operations and opportunities for property acquisitions.
At December 31, 1998, the Company had cash and cash investments of
$13.5 million, a decrease from $19.2 million at December 31, 1997. Net cash
provided by operating activities decreased from $90.8 million to $55.1 million
due to lower oil and gas production coupled with lower commodity prices. In
response to lower commodity prices and earlier disappointing drilling results
the Company deferred certain of its exploration program in 1998. As a result,
cash used in investing activities decreased from $145.8 million to $134.8
million. Cash provided by financing activities in1998 consisted entirely of
borrowings under the bank credit facility.
At December 31, 1997, the Company had cash and cash investments of
$19.2 million, an increase from the $12.5 million at December 31, 1996. Net
cash provided by operating activities continued to grow as production expanded
and was $90.8 million in fiscal 1997. Net cash used in investing activities
for the fiscal 1997 was $145.8 million, which almost entirely represented
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increased expenditure on oil and gas properties. The cash provided by
financing activities for fiscal 1997 was $61.5 million, mainly representing a
$100 million senior subordinated note issue net of the repayment of the
Company's bank credit facility (of which there was $37.0 million outstanding
at December 31, 1996).
In the six months to December 31, 1996 period cash and cash
investments had also increased, from $3.5 million at June 30, 1996 to $12.5
million at December 31, 1996. Cash flow used in investing activities ($33.2
million) was more than offset by cash flow from operations ($26.5 million) and
cash flow from financing ($15.8 million). The latter represented the proceeds
from the equity issues (mainly the ADR offering of $70.4 million net) less
repayment of borrowings under the Company's credit facility ($15 million) and
the buy back of 11.7 million Ordinary Shares from Climax ($41.2 million).
In fiscal 1996, net cash provided by operating activities was $38.6
million, the increase on the previous year mainly reflecting the increased
production of oil and gas and working capital movements. Net cash used in
investing activities for fiscal 1996 was $73.2 million, while net cash
provided by financing activities for fiscal 1996 was $37.7 million, with the
main source of finance being increased bank borrowings under the Company's
credit facility ($19.9 million) and an equity issue of $18.4 million.
At December 31, 1996, the Company's working capital deficit was $0.5
million. The Company's working capital position was strengthened in June 1997
by a senior subordinated note issue (see below) of $100 million in June 1997.
At December 31, 1997 there was a working capital surplus of $7.4 million. At
December 31, 1998 the Company's working capital surplus further increased to
$15.8 million as a result of the sale of certain assets to Apache.
In April 1996, Petsec Energy Inc ("PEI"), a wholly owned subsidiary
of the Company which owns and operates all of the Company's Gulf of Mexico oil
and gas properties, entered into a $75 million bank credit facility under
which the borrowing base at December 31, 1998 was $75 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, 1998, borrowings outstanding under the bank credit facility were $74
million with letters of credit outstanding of $1 million. Upon settlement of
the sale of a 50% working interest in certain properties to Apache on February
1, 1999, $65 million in borrowings under the bank credit facility was repaid
and the borrowing base was reduced to $10 million. 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 PEI to maintain a
ratio of senior debt to earnings before interest, taxes, depletion,
depreciation and amortization of not more than 4.0 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. PEI 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 1.75% per annum, depending upon the total amount borrowed. PEI is
obligated to pay a fee equal to 0.3% to 0.375% 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. Borrowing base repayments, if required, are expected to be met
from estimated future net operating cash flow.
Following the sale of the jointly-owned commercial building in May
1996 and the Didipio sale referred to below, the Company has no guarantees or
funding commitments in respect of Climax Mining Ltd or any of Climax's
subsidiaries.
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On June 13, 1997, PEI, issued $100 million (net proceeds: $96.4
million) of 9.5% senior subordinated notes due June 15, 2007. A portion of the
proceeds was used to repay its then outstanding borrowings under the bank
credit facility.
Apart from the repayment of indebtedness under the credit agreement
the proceeds of the note issue have been used to provide working capital to
the Company and to fund further exploration and development of the Company's
oil and gas properties, the acquisition of lease blocks and other general
corporate purposes.
The notes were issued under an indenture between PEI as issuer and
The Bank of New York as trustee. The notes are not guaranteed by the Company.
The notes are redeemable at the option of PEI on or after June 15,
2002 at varying redemption prices starting at 104.75% and declining to 100% in
2005. The indenture pursuant to which the notes were issued contains certain
covenants on PEI including, without limitation, covenants with respect to the
following matters: (1) limitations on the indebtedness of PEI (2) limitations
on payments by PEI of dividends, redemptions of capital, repayments of
subordinated indebtedness and payments in respect of non-permitted
investments; (3) limitations on PEI's transactions with affiliates (but these
are not to restrict PEI from various intra-group transactions specified in the
indenture); (4) limitations on liens of PEI; (5) limitations on disposition of
proceeds of asset sales by PEI; (6) limitations on other senior subordinated
indebtedness of PEI; (7) limitations on the conduct of business by PEI; (8)
limitations on non-guarantor restricted subsidiaries of PEI (at present these
have no effect as PEI has no subsidiaries); and (9) reports (PEI, as the
issuer, files its results with the SEC under its own name, in addition to the
filings of Petsec.)
Upon an occurrence of a change of control PEI is obliged to make an
offer to repay the noteholders at 101% of the face value of the notes. Change
of control is defined in the indenture to include, among other things, a
person or group (other than interests associated with the Managing Director,
Mr Fern) becoming beneficial owner of more than 50% of the shares of the
Company, a change in the majority of the directors of the Company without the
consent of existing directors or, if the Company no longer controls PEI,
similar provisions with respect to PEI.
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 counterparties 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.
The Company has entered into swap agreements and collar agreements to
reduce the effect of price volatility on oil and gas sales. In swap
agreements, the Company settles with a counterparty the difference between an
agreed fixed price per unit of production and a floating price (based on NYMEX
prices). If the floating price upon maturity is higher than the fixed price,
the Company pays the difference to the counterparty and vice versa. In collar
agreements, the Company settles with a counterparty when a floating price upon
maturity of the agreement is lower than an agreed fixed price floor or above
an agreed fixed price ceiling, the settlement amount in both cases being the
difference between the floating price upon maturity and the agreed fixed
price, multiplied by the volume hedged. The Company has proved reserves
sufficient to cover all of the base contracts and does not trade in
derivatives without underlying forecasted production and proved reserves.
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In June of 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities". Statement 133 establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. Statement 133 requires that all derivatives be recognized as
either assets or liabilities in the balance sheet and measured at fair value.
The accounting for changes in the fair value of a derivative (that is, gains
and losses) depends on the intended use of the derivative and resulting
designation. If certain conditions are met, a derivative may be specifically
designated as a "fair value hedge," "cash flow hedge," or a hedge of the
foreign currency exposure of a net investment in a foreign operation.
Statement 133 amends and supersedes a number of existing Statements of
Financial Accounting Standards, and nullifies or modifies the consensus
reached in a number of issues addressed by the Emerging Issues Task Force.
Statement 133 is currently effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. The Company is assessing the impact of adoption
of Statement 133, and at the present time, has not quantified the effect of
adoption or continuing impact of such adoption.
OTHER MATTERS
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. Additionally, the MMS may require operators in
the OCS to post supplemental bonds in excess of lease and area-wide bonds with
respect to abandonment obligations. Under certain circumstances, the MMS may
require any 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. See "Business
Regulation".
The Company's operations are subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company believes its current operations are in material compliance with
current applicable environmental laws and regulations. However, there can be
no assurance that current regulatory requirements will not change, currently
unforeseen environmental incidents will not occur or past unknown
non-compliance with environmental laws will not be discovered.
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.
YEAR 2000
The Company has a plan in place to address Year 2000 ("Y2K") issues. The
plan requires the Company to assess its information technology ("IT") systems
and non-information technology ("non-IT") systems (primarily embedded
technology in process control equipment containing microprocessors or other
similar circuitry) and those of its principal suppliers, customers and
business associates whose Y2K readiness could reasonably be expected to have a
material effect on the Company's business, results of operations or financial
condition.
On February 1, 1999 the Company completed the sale of a 50% working
interest in most of the Company's producing oil and gas properties to Apache
including the responsibilities associated with the operation of these assets.
As a result, Apache is primarily responsible for Y2K compliance issues
concerning these oil and gas operating assets. The Company will assist Apache
in assessing the Y2K exposure and has made available to Apache all data and
testing accumulated to date that is relevant to the oil and gas assets that
are now jointly owned. With Apache now among the Company's principal business
partners, the Company will undertake to assess Apache's Y2K readiness.
Prior to the Apache transaction, the Company had identified all material
IT and non-IT systems it uses directly in its operations that could be
affected by Y2K issues. Of these identified systems, the Company has assessed
the Y2K readiness of 95% of the systems, with 10% having been found to
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have Y2K compliance problems. All identified compliance problems can be remedied
without the expenditure of any material sums. In addition, the licensor of the
Company's primary financial software has certified that this software is Y2K
compliant. Surveys have been received from a substantial number of the
Company's principal suppliers, customers and business associates. The
Company's management expects to identify all principal suppliers, customers
and business associates with respect to which the Company does not have
verification of Y2K compliance before June 30, 1999. The Company will continue
to seek Y2K compliance assurances from its principal suppliers, customers and
business associates who have not already done so. There can be no guarantee,
however, that the systems of other companies on which the Company's operations
rely will be timely converted, or that a failure to convert by another
company, or a conversion that is incompatible with the Company's systems would
not have a material adverse effect on the Company.
The Company has begun to formulate contingency plans to address Y2K
risks. These contingency plans presently consist of identifying suppliers,
hydrocarbon purchasers and other business associates that have developed
systems that are Y2K compliant. In addition, the Company is working on plans
to conduct its operations manually in the event an unexpected Y2K problem
would shut down significant systems. There can be no assurance that the
Company's contingency plans will be effective to mitigate an anticipated Y2K
compliance problem or that the Company has anticipated all Y2K compliance
problems that could arise.
The Company has and will utilize both internal and external resources to
complete tasks and perform testing necessary to address the Y2K issue. The
Company expects to continue to assess its Y2K risks and develop contingency
plans to minimize those risks during the year. To date, the Company has not
incurred any significant costs on its Y2K project and estimates a total cost
of less than $80,000 related to the assessment and remediation of Year 2000
issues.
ITEM 9A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risk from adverse changes in
commodity prices and interest rates as discussed below.
Commodity Price Risk. The Company produces and sells natural gas
and crude oil. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response
to changing market forces. The Company has made use of derivative financial
instruments such as forward swap contracts and collars as a hedging strategy
to manage commodity prices associated with oil and gas sales and to reduce the
impact of commodity price fluctuations. The Company used the hedge or deferral
method of accounting for these instruments and, as a result, gains and losses
on commodity derivative financial instruments were generally offset by similar
changes in the realized prices of the commodities. See "Item 9 - Management's
Discussion and Analysis of Financial Condition and Results of Operations
Hedging Transactions".
The Company uses a sensitivity analysis technique to evaluate
the hypothetical effect that changes in the market value of crude oil and
natural gas may have on the fair value of the Company's derivative
instruments. At December 31, 1998, the potential change in the fair value of
commodity derivative instruments assuming a 10 percent adverse movement in the
underlying commodity price is a $3.3 million decrease in the deferred benefit
at December 31, 1998.
For purposes of calculating the hypothetical change in fair
value, the relevant variables are the type of commodity (crude oil or natural
gas), the commodities futures prices and volatility of commodity prices. The
hypothetical fair value is calculated by multiplying the difference between
the hypothetical price and the contractual price by the contractual volumes.
Interest Rate Risk. Currently, the Company has no open interest
rate swap or interest rate lock agreements.
37
<PAGE> 39
Therefore, the Company's exposure to changes in interest rates
primarily results from its short-term and long-term debt with both fixed and
floating interest rates. The following table presents principal amounts
(stated in thousands) and related average interest rates by year of maturity
for the Company's debt obligations at December 31, 1998:
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
---- ---- ---- ---- ---- ---------- ----- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Long-term debt, including
current maturities
Variable rates - bank 67,250 4,500 2,250 - - - 74,000 74,000
Average interest rates 7.3% 7.3% 7.3% - - - 7.3%
Fixed rates - - - - - 100,000 100,000 57,000
Average interest rates 9.5% 9.5% 9.5% 9.5% 9.5% 9.5% 9.5%
</TABLE>
If market interest rates average 1% higher or lower in 1999 than in 1998,
interest expense would increase (decrease), and loss before income taxes would
increase (decrease) by approximately $0.3 million.
38
<PAGE> 40
ITEM 10 DIRECTORS AND OFFICERS OF REGISTRANT
The following table sets forth the name, age and position of each
director and executive of the Company.
<TABLE>
<CAPTION>
Name Age Position *
<S> <C> <C>
Directors:
Terrence N. Fern ...... 51 Chairman, Managing Director and Chief Executive Officer
David A. Mortimer ..... 54 Director
R. Bruce Corlett ...... 54 Director
Executives:
Maynard V. Smith ...... 48 Chief Operating Officer
Ross A. Keogh ......... 40 Chief Financial Officer
Howard H. Wilson, Jr... 41 Vice President - Operations*
John T. Bellatti 41 Vice President - Exploration and Chief Geophysicist*
William R. Sack 37 Vice President - Exploration and Joint Ventures*
James E. Slatten III ... 40 Vice President - Land and Legal*
Geoffrey H. Fulcher 58 Company Secretary
</TABLE>
* Messrs. Fern and Smith provide services to the Company through
contractual arrangements between the Company and their respective
corporate affiliates. See "Executive and director compensation and
interests of management in certain transactions". The titles shown for
Messrs. Wilson, Bellatti, Sack and Slatten are positions held with the
Company's wholly-owned subsidiary, Petsec Energy Inc. Adrian J Fletcher
retired as director and Chairman of the Company on May 14, 1999.
The following biographies describe the business experience of the
directors and executives of the Company and Petsec Energy Inc.
TERRENCE N. FERN has over 28 years of extensive international experience
in petroleum and minerals exploration, development and financing. He holds a
Bachelor of Science degree from The University of Sydney and has followed
careers in both exploration geophysics and natural resource investment. Mr
Fern is also the Managing Director of Climax Mining Ltd.
DAVID A. MORTIMER was a senior TNT Limited Group Executive from 1973 and
in 1997 retired as its Chairman and Chief Executive. He is a director of
Adsteam Marine Limited, Ci Technologies Group Limited (Chairman), F.H. Faulding
& Co Limited, Leighton Holdings Limited and Sydney Airports Corporation Limited
(Chairman). Mr Mortimerholds a Bachelor of Economics degree from The University
of Sydney.
R. BRUCE CORLETT practised as a solicitor for a short time before moving
into the commercial arena where he has been an executive and director of many
publicly listed companies. He is currently a director of a number of public
companies including, Adsteam Marine Limited, FAI Life Limited, Stockland Trust
Group Limited and Tourism Asset Holdings Limited (Chairman). Mr Corlett has
degrees in Arts and Law from The University of Sydney and was admitted as a
solicitor of the Supreme Court of New South Wales in 1969.
MAYNARD V. SMITH has served as General Manager - Exploration and
Production since 1990 and became Chief Operating Officer in 1999. 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. Mr Smith holds a Bachelor of Science
degree in Geology from the California State University at San Diego.
39
<PAGE> 41
ROSS A. KEOGH has served as Treasurer of Petsec Energy Inc since 1990 and
has 16 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. During the year Mr Keogh was appointed to the position of Chief
Financial Officer of the Company. Mr Keogh holds a Bachelor of Economics
degree, with a major in Accounting, from Macquarie University in Sydney.
HOWARD H. WILSON, JR. has served as Vice President - Operations of
Petsec Energy Inc. 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.
JOHN T. BELLATTI is Vice President - Exploration and Chief Geophysicist
of Petsec Energy Inc. He joined Petsec Energy Inc. in January 1996. Mr. Bellatti
worked for Shell Oil Co. between 1981 and 1995 in various technical and
supervisory positions in the Michigan Basin and the shallow water Gulf of
Mexico. He holds a Bachelor of Arts degree in Physics from Hanover College, a
Master of Science degree in Geophysics from the Colorado School of Mines and a
Master of Business Administration in Finance from the University of Houston.
WILLIAM R. SACK is Vice President - Exploration and Joint Ventures of
Petsec Energy Inc. Mr. Sack joined Petsec Energy Inc in January 1996. Between
1988 and 1996 Mr. Sack held various technical and supervisory positions with
Shell Offshore Inc., involving exploration, development and business
activities. Mr. Sack holds a Bachelor of Science degree in Earth Science and
Physics from St. Cloud State University (MN), a Master of Science degree in
Geology from Michigan State University, and a Master's degree in Business
Administration from Tulane University.
JAMES E SLATTEN III is Vice President - Land and Legal of Petsec Energy
Inc. He has over 15 years experience in corporate and energy law. Prior to
joining Petsec Energy Inc he was a partner in the Louisiana law firm of
Gordon, Arata, McCollam & Duplantis. Mr Slatten holds a Bachelors 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.
GEOFFREY H FULCHER has had over 30 years experience in the petroleum and
mining industries in field and management positions, with over 15 of those
years as a Corporate Secretary.
ITEMS 11, 12 AND 13 COMPENSATION OF DIRECTORS AND OFFICERS; OPTIONS; AND
INTERESTS OF MANAGEMENT IN CERTAIN TRANSACTIONS
EXECUTIVE AND DIRECTOR COMPENSATION AND INTERESTS OF MANAGEMENT IN
CERTAIN TRANSACTIONS
The total compensation received by the directors of the Company for
their services as directors for fiscal 1998 was $109,000. The total
compensation received by the six highest compensated executive officers of the
Company and its controlled and related companies for fiscal 1998 was $926,000.
In addition, a Company associated with Mr. Fern provided management services
to the Company at a cost of $437,000. Also a Company associated with Mr. Smith
provided management and geological services to the Company at a cost of
$224,000 and a Company associated with Mr. Fletcher provided management
consulting services to the Company at a cost of $25,000 (Mr Fletcher resigned
as a director and Chairman of the Company on May 14, 1999). Three executives,
Messrs Gannaway, Kallenberger and Smith, (Messrs Gannaway and Kallenberger
resigned during 1998) also own overriding royalty interests on certain leases
held by the Company, which were granted prior to July 1994 as incentives. The
granting of overriding royalty interests as an incentive was replaced
subsequent to July 1994 by grants under Company's share and option plans.
The Company has entered into employment agreements with certain
management and technical personnel. These agreements generally have three year
terms and expire in June 1999. In July 1996 the Company granted options for
Ordinary Shares to key employees pursuant to the Option
40
<PAGE> 42
Plan in connection with the extension of the terms of these employment
agreements. In addition, the Company has entered into agreements with entities
controlled by the families of Messrs Fern and Smith for the provision of
services.
Other than pursuant to the Share and Option Plans described below,
the Company also has outstanding options for 450,000 Ordinary Shares to a
company controlled by Mr Smith's family: these are at an exercise price of
A$0.50 per Ordinary Share and expire in May 2004.
Certain officers and directors of the Company own 2,653,900 ordinary
shares of Climax, representing less than 3% of the outstanding capital of
Climax. In addition, Mr Fern serves as Managing Director of Climax and Mr
Fulcher serves as Company Secretary of Climax.
SHARE AND OPTION PLANS
The Company 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 Company's 1994 Annual General Meeting and are
administered by a committee (the "Remuneration Committee") appointed by the
Board of Directors. 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 6.5% 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 Company, 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 ASX achieving certain benchmarks. After
the vesting of such shares, the grantee may either repay the Company loan or
sell such shares and retain the difference. As of April 23, 1999, all
employees and directors of the Company, in the aggregate, owned 1,765,000
Ordinary Shares subject to the terms of this Share Plan. As of April 23, 1999,
Mr Fern had a Company loan of A$2,625,000 ($1,775,000) in connection with
grants of a total of 1,500,000 Ordinary Shares under the Share Plan and Messrs
Mortimer and Corlett each had a Company loan of A$280,000 ($189,000) in
connection with grants of 50,000 Ordinary Shares under the Share 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 April 23, 1999 all directors and employees of
the Company, in the aggregate, held options to purchase an aggregate of
3,130,500 Ordinary Shares pursuant to the Option Plan.
PART II
ITEM 14 - DESCRIPTION OF SECURITIES TO BE REGISTERED
Not applicable
41
<PAGE> 43
PART III
ITEM 15 - DEFAULTS UPON SENIOR SECURITIES
Not applicable - none.
ITEM 16 - CHANGES IN SECURITIES
Not applicable - none.
PART IV
ITEM 17 - FINANCIAL STATEMENTS
Not applicable - see Item 18 below.
ITEM 18 - FINANCIAL STATEMENTS
The US Dollar Financial Statements of the Company and the Independent
Auditors' Report are included on pages F-1 through F-24 of this Form 20-F.
42
<PAGE> 44
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of
1934, the Registrant, Petsec Energy Ltd, certifies that it meets all the
requirements for filing on Form 20-F and has duly caused this annual report to
be signed on its behalf by the undersigned, thereunto duly authorized.
By: /s/ Ross A Keogh
Chief Financial Officer
Petsec Energy Ltd
June 10, 1999
43
<PAGE> 45
ITEM 19 - FINANCIAL STATEMENTS AND EXHIBITS
(a) Financial Statements, including
* Consolidated balance sheets of Petsec Energy Ltd and subsidiaries
as of December 31, 1997 and 1998 and the related consolidated
statements of operations, consolidated statements of comprehensive
income (loss), and consolidated statements of cash flows for the
year ended June 30, 1996, the six month period ended December 31,
1996 and each of the years in the two year period ended December
31, 1998.
* Independent Auditors' Report
(b) Exhibits
* Consent of KPMG
* Consent of Ryder Scott Company
44
<PAGE> 46
[PETSEC ENERGY LTD LOGO]
US DOLLAR FINANCIAL STATEMENTS
UNDER US GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
DECEMBER 31, 1998
Note: Further information relating
to the operations of the Company
is available through either of the
following:
1. The Company's home page at
http://www.petsec.com
2. By contacting
The Chief Financial Officer
Petsec Energy Ltd
143 Ridgeway Drive
Lafayette LA 70503 3402
(318) 989 1942
<TABLE>
- --------------------------------------------------------------------------------
<S> <C>
Consolidated Balance Sheets 2
- --------------------------------------------------------------------------------
Consolidated Statements of Operations 3
- --------------------------------------------------------------------------------
Consolidated Statements of Comprehensive
Income (Loss) 4
- --------------------------------------------------------------------------------
Consolidated Statements of Cash Flows 5
- --------------------------------------------------------------------------------
Notes to the Consolidated Financial
Statements 6
- --------------------------------------------------------------------------------
Independent Auditors' Report 24
- --------------------------------------------------------------------------------
</TABLE>
F-1
<PAGE> 47
CONSOLIDATED
BALANCE SHEETS Petsec Energy Ltd and subsidiaries
<TABLE>
<CAPTION>
December 31, December 31,
(US dollars, in thousands) 1997 1998
- --------------------------------------------------------------------------------------------
<S> <C> <C>
BALANCE SHEETS
Current assets
Cash $ 19,171 $ 13,488
Accounts receivable 13,978 8,279
Other receivables 156 4,718
Prepayments 391 322
Deferred tax assets (note 2) 1,446 1,399
Assets held for sale -- 68,300
Inventory - crude oil 43 45
Trading securities 196 75
--------- ---------
Total current assets 35,381 96,626
--------- ---------
Non-current assets
Proved oil and gas properties 227,049 156,265
Unproved oil and gas properties 20,759 31,984
Production facilities 66,956 43,321
Other 1,527 1,970
Less accumulated depletion, depreciation and amortization (106,977) (133,738)
--------- ---------
Net oil and gas properties 209,314 99,802
--------- ---------
Investment securities 6 1
Note issue costs (note 5) 3,000 2,682
Property, plant and equipment - Australia (note 6) 261 102
--------- ---------
Total assets $ 247,962 $ 199,213
========= =========
Current liabilities
Accounts payable and accrued liabilities (note 7) $ 27,969 $ 13,549
Credit facility (note 9) -- 67,250
--------- ---------
Total current liabilities 27,969 80,799
--------- ---------
Long-term liabilities
Long-term debt less current maturities (note 9) 99,630 106,406
Deferred tax liabilities (note 2) 15,612 4,757
Other accrued liabilities (note 8) 3,596 2,896
--------- ---------
Total long-term liabilities 118,838 114,059
--------- ---------
Shareholders' equity
Share capital (notes 10 and 11) 16,491 122,697
Additional paid-in capital (note 11) 105,269 --
Subscriptions receivable (note 11) (2,406) (2,637)
Accumulated other comprehensive loss (notes 4 and 11) (3,468) (4,469)
Retained deficit (14,731) (111,236)
--------- ---------
Total shareholders' equity 101,155 4,355
--------- ---------
Total liabilities and shareholders' equity $ 247,962 $ 199,213
========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-2
<PAGE> 48
CONSOLIDATED STATEMENTS
OF OPERATIONS Petsec Energy Ltd and subsidiaries
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Oil and gas sales (net of royalties) $ 51,150 $ 37,521 $ 125,139 $ 92,017
--------- --------- --------- ---------
Operating expenses
Lease operating expenses 6,892 3,279 11,527 14,989
Depletion, depreciation and amortization 21,098 15,368 63,903 57,672
Exploration expenditure 2,175 5,249 7,328 7,427
Dry hole and abandonment costs 1,145 -- 10,454 27,503
Impairment expense -- -- -- 72,916
General, administrative and other expenses 7,001 3,339 9,001 10,777
Stock compensation expense 1,749 677 1,461 937
--------- --------- --------- ---------
Total operating expenses 40,060 27,912 103,674 192,221
--------- --------- --------- ---------
Income (loss) from operations 11,090 9,609 21,465 (100,204)
Other income (loss) 223 -- 132 (86)
Profit on sale of assets 257 7,208 31 68
Interest expense (3,687) (1,472) (6,022) (9,044)
Interest income 485 822 1,685 1,214
Equity in income (loss) of affiliates 282 (1,326) (1,595) --
--------- --------- --------- ---------
Income (loss) before tax 8,650 14,841 15,696 (108,052)
Income tax benefit (expense) (note 2) (895) (3,888) (5,416) 11,547
--------- --------- --------- ---------
Net income (loss) $ 7,755 $ 10,953 $ 10,280 $ (96,505)
========= ========= ========= =========
Earnings (loss) per share (US dollars)
Basic and diluted earnings (loss) per ordinary share $ 0.09 $ 0.10 $ 0.10 $ (0.90)
Basic and diluted earnings (loss) per American Depositary
Receipt (based on the ratio of five ordinary shares
to one American Depositary Receipt) $ 0.45 $ 0.52 $ 0.48 $ (4.48)
The Company issued its first American Depositary Receipts
in July 1996 and the net earnings per ADR is for
comparative purposes only.
</TABLE>
F-3
<PAGE> 49
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME (LOSS) Petsec Energy Ltd and subsidiaries
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net income (loss) $ 7,755 $ 10,953 $ 10,280 $(96,505)
-------- -------- -------- --------
Foreign currency translation adjustments, net of tax (note 4) 775 61 (3,398) (999)
Unrealized gains (losses) on investment securities
arising during the period, net of tax (note 4) (983) 500 (457) (2)
-------- -------- -------- --------
Other comprehensive income (loss), net of tax (208) 561 (3,855) (1,001)
-------- -------- -------- --------
Comprehensive income (loss) $ 7,547 $ 11,514 $ 6,425 $(97,506)
======== ======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements
F-4
<PAGE> 50
CONSOLIDATED STATEMENTS
OF CASH FLOWS Petsec Energy Ltd and subsidiaries
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 7,755 $ 10,953 $ 10,280 $ (96,505)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
- - (earnings) loss in affiliates (282) 1,326 1,595 --
- - distributions received from affiliates 432 -- -- --
- - write down of investment 9 (10) -- --
- - depletion, depreciation and amortization 21,098 15,368 63,903 57,672
- - dry holes and abandonments 1,145 -- 10,454 27,503
- - impairments -- -- -- 72,916
- - loss (gain) on sale of assets (257) (7,208) (31) (68)
- - taxation payable 194 118 (9) 67
- - deferred tax 701 3,770 5,425 (10,808)
- - translation (gains) losses 101 (381) -- --
- - employee stock compensation 1,749 677 1,461 937
- - interest income on subscriptions receivable (196) (103) (190) (242)
- - amortization of borrowing costs and discount on notes -- -- 190 343
Changes in operating assets and liabilities:
- - accounts receivable (4,921) (4,382) (2,124) 5,699
- - other current assets (947) 1,436 (404) (4,374)
- - accounts payable and accrued liabilities 11,754 4,640 -- 2,614
- - other accrued liabilities 266 250 256 (698)
-------- -------- --------- ---------
Net cash provided by operating activities 38,601 26,454 90,806 55,056
-------- -------- --------- ---------
Investing activities
Additions to oil and gas properties (75,467) (48,419) (145,850) (134,869)
Additions to other assets -- (32) -- --
Proceeds of asset disposals 244 20 60 119
Proceeds of investment sales 3,651 13,703 -- --
Investment in affiliates (1,488) -- -- --
Restricted deposit (1,501) 1,501 -- --
Repayment from affiliate 1,333 -- -- --
-------- -------- --------- ---------
Net cash used in investing activities (73,228) (33,227) (145,790) (134,750)
-------- -------- --------- ---------
Financing activities
Proceeds from note issue - unsecured -- -- 96,446 --
Proceeds from borrowings - secured loans 28,650 7,000 21,000 74,000
Repayments of borrowings - secured loans (8,770) (22,000) (58,000) --
Issuance of ordinary shares 17,635 71,944 1,542 --
Buy-back of ordinary shares -- (41,184) -- --
Repayment of Employee Share Plan loan 219 -- 524 11
-------- -------- --------- ---------
Net cash provided by financing activities 37,734 15,760 61,512 74,011
-------- -------- --------- ---------
Effect of exchange rate changes on cash 41 -- 115 --
-------- -------- --------- ---------
Increase (decrease) in cash 3,148 8,987 6,643 (5,683)
Cash at the beginning of the period 393 3,541 12,528 19,171
-------- -------- --------- ---------
Cash at the end of the period $ 3,541 $ 12,528 $ 19,171 $ 13,488
======== ======== ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE> 51
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS December 31, 1998
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND PRACTICES
The significant accounting policies which have been adopted in the preparation
of this financial report are:
(a) Description of business
Petsec Energy Ltd (the "Company") is an independent exploration, development and
production company operating in the shallow waters of the Gulf of Mexico,
primarily offshore Louisiana and Texas. 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 in the oil and gas
industry.
(b) Basis of preparation
The financial statements have been prepared in accordance with US GAAP, with the
US dollar, as the reporting currency.
(c) Principles of consolidation
The consolidated financial statements include the financial statements of the
Company and its wholly-owned subsidiaries (the "Group"). All significant
intercompany balances and transactions have been eliminated on consolidation.
(d) 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 as incurred.
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.
The Company assesses the impairment of capitalized costs of proved 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.
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.
(e) Provision for dismantlement
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.
(f) Capitalized interest
The Company capitalized interest of $0.9 million and $3.5 million in 1997 and
1998, respectively, which is included in oil and gas properties.
(g) Depreciation - other property, plant and equipment
Depreciation is provided on other property, plant and equipment so as to write
off the assets progressively over their estimated useful life using the straight
line method.
<TABLE>
<CAPTION>
Method Estimated
useful life
<S> <C> <C>
Furniture and fittings Straight line 7
Office machines and equipment Straight line 7
Motor vehicles Straight line 4
Leasehold improvements Straight line 5
</TABLE>
(h) Investments, marketable equity securities held for trading and assets held
for sale
i) Investments, including marketable equity securities held for trading
Investment securities consist of investments in common stock and are stated at
fair value as determined by the most recently traded price of each security at
the balance sheet date. All investment securities are defined as either trading
securities or available-for-sale securities.
Management determines the appropriate classification of its investments in
investment securities at the time of purchase and reevaluates such determination
at each balance date. Securities that are bought and held principally for the
purpose of selling them in the near term are classified as trading securities
and unrealized holding gains and losses are included in earnings.
Available-for-sale securities are carried at fair value, with the unrealized
gains and losses, net of tax, reported as a separate component of accumulated
other comprehensive loss. Dividends received on investment securities are
recognized in earnings when received.
F-6
<PAGE> 52
ii) Assets held for sale
The assets held for sale consist of capitalized exploration costs in relation to
oil and gas leases, exploration and development activities. These assets
represent a 50% working interest in all but one of the operating leases held by
the Group and were disposed of for cash effective January 1999. See item (j)
below.
(i) Inventories
Inventories are stated at the lower of cost or market. Cost is determined
principally on the average cost method.
(j) Impairments
The non-cash impairment charge of $72.9 million was recorded in accordance with
SFAS No. 121, which requires that long-lived assets held and used by the Group
be reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of the asset may not be recoverable. The continued low
prices received for the sales of oil and natural gas along with the sale of
certain assets (see note 15) are such events. As a result of these events, after
related income tax benefits, this write down increased net loss by $69 million.
The carrying values for assets determined to be impaired were adjusted to
estimated fair values based on projected future discounted net cash flows for
such assets, and the proceeds from the sale of certain assets sold in February
1999. The Group has exposure to future impairments if oil and gas prices
deteriorate from December 1998 levels, which could have a material adverse
effect on financial condition, results of operations and liquidity in the near
term.
(k) Revenue recognition
Sales are brought to account when product is in the form in which it is to be
delivered and an actual physical quantity has been provided or allocated to a
purchaser pursuant to a contract.
(l) Hedging activities
The Group uses derivative commodity instruments to manage commodity price risks
associated with future crude oil and natural gas production but does not use
them for speculative purposes. The Group'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 Group'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 Group 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.
(m) Employee entitlements
The provision for employee entitlements to wages, salaries and annual leave
represents the amount of the present obligation to pay resulting from employees'
services provided up to balance date. The provision has been calculated based on
current wage and salary rates and includes related on-costs. Employer
contributions to superannuation funds are charged against earnings. Further
information is set out in Note 12.
(n) Income taxes
The Group accounts for income taxes following the asset and liability method.
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. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in income in the
period that incudes the enactment date.
(o) Foreign currency translation
Foreign currency transactions are translated at the rates of exchange ruling at
the date of the transactions. Amounts receivable and payable in foreign
currencies are translated at the rates of exchange ruling at balance date.
Exchange differences relating to amounts receivable and payable in foreign
currencies are brought to account in earnings as exchange gains or losses in the
financial period in which the exchange rates change.
The balance sheets of the Company and its Australian subsidiaries are translated
at the rates of exchange ruling at balance date. The statements of operations
are translated at a weighted average rate for the period. Exchange differences
arising on translation are taken directly to the foreign currency translation
reserve and forms part of the accumulated other comprehensive loss. The income
tax effect of exchange differences in respect of US dollar balances held by the
Company and certain subsidiaries has been taken to the foreign currency
translation reserve on consolidation.
F-7
<PAGE> 53
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS Petsec Energy Ltd and subsidiaries
- --------------------------------------------------------------------------------
CONTINUED
- --------------------------------------------------------------------------------
The exchange rates (US dollars for one Australian dollar) used in the
preparation of these financial statements are:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Twelve months Six months Twelve months
ended ended ended
June 30, December 31, December 31,
1996 1996 1997 1998
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Weighted average
exchange rate 0.7619 0.7918 0.7325 0.6302
Exchange rate at
period end 0.7839 0.7962 0.6514 0.6117
- --------------------------------------------------------------------------------
</TABLE>
(p) Note issue costs
Costs associated with the note issue (see note 9(a)) have been capitalized and
are amortized over the period to maturity.
(q) Comprehensive income (loss)
The Company adopted SFAS No. 130, "Reporting Comprehensive Income," in the year
ended December 31, 1998. SFAS No. 130 establishes standards for reporting and
presentation of comprehensive income and its components in a full set of
financial statements. Comprehensive income (loss) consists of net income (loss)
and other items of comprehensive income and is presented in the consolidated
statements of comprehensive income (loss). Prior year financial statements have
been reclassified to conform to the requirements of SFAS No. 130.
(r) Comparatives
Where necessary, comparative information has been reclassified to achieve
consistency in disclosure with current financial year amounts and other
disclosures.
(s) Change of year end
The Company changed its year end from June 30 to December 31 at December 31,
1996.
(t) Stock compensation
The Company has an Employee Option Plan and issues options to employees and
certain consultants of the Company to purchase stock in the Company.
The Company recognizes stock compensation expense in respect to the options
granted to the Company's employees and certain consultants. Prior to 1996, the
Company accounted for its expense related to the stock option plan in accordance
with the provision of Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees", and related interpretations. In
1996, the Company adopted Statement of Financial Accounting Standards 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. The amount is recorded as an increase to share capital. All shares and
options granted before June 30, 1996 will continue to be accounted for under APB
Opinion No. 25 which treats the shares and options granted which do not vest (or
become unrestricted) until the Company's shares have appreciated to a specified
level as a variable plan.
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 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; 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, and 2.4 to 4.5 years
(weighted average 3.4 years); 37%; 0 and 5.3% respectively, in 1998.
(u) Investment in affiliated company
The investment in an affiliated company consists of 44% of the common stock of
Climax Mining Ltd ("Climax"), an Australian minerals exploration company. This
investment is accounted for by the equity method of accounting, whereby the
investment is carried at cost of acquisition, plus the Group's equity in
undistributed earnings or losses since acquisition. This investment had a
carrying value of nil at December 31, 1998 and December 31, 1997, due to the
effect of equity accounted losses (quoted market values $5,968,000 and
$11,439,000, respectively). Refer to note 18 for selected consolidated financial
data under US GAAP for Climax Mining Ltd.
(v) Use of estimates
The preparation of the financial statements requires management to make
estimates and assumptions which 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 revenue and expenses during
the reported period. Actual results could differ from those estimates.
F-8
<PAGE> 54
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
2. INCOME TAXES
Income (loss) before income taxes for the year ended June 30, 1996, the six
month period ended December 31, 1996 and the years ended December 31, 1997 and
1998 was taxed under the following jurisdictions:
Australia $ (1,781) $ 5,265 $ (3,850) $ (2,457)
US 10,431 9,576 19,546 (105,595)
-------- -------- -------- ---------
$ 8,650 $ 14,841 $ 15,696 $(108,052)
======== ======== ======== =========
Income tax expense (benefit) is presented below:
Current:
Australia $ 493 $ 307 $ 136 $ 262
-------- -------- -------- ---------
Deferred:
Australia $ (3,169) $ 468 $ (1,301) $ 153
US 3,571 3,113 6,581 (11,963)
-------- -------- -------- ---------
402 3,581 5,280 (11,810)
-------- -------- -------- ---------
Income tax expense (benefit) $ 895 $ 3,888 $ 5,416 $ (11,547)
======== ======== ======== =========
Income tax expense (benefit) differed from the amounts computed by applying an
income tax rate of 36% (the statutory rate in effect in Australia) to income
before income taxes as a result of the following:
Computed "expected" tax expense (benefit) $ 3,114 $ 5,343 $ 5,651 $ (38,899)
Increase (reduction) in income taxes resulting from:
Items not deductible for tax 543 244 573 1,005
Change in the balance of the valuation allowance
for deferred tax assets (2,504) (1,373) (625) 25,600
Other (258) (326) (183) 747
-------- -------- -------- ---------
$ 895 $ 3,888 $ 5,416 $ (11,547)
======== ======== ======== =========
The tax effects of temporary differences that give rise to significant portions
of the deferred tax assets and deferred tax liabilities at December 31, 1997 and
1998 are presented below.
Deferred tax assets:
Financial provisions not currently deductible for tax purposes $ 1,612 $ 1,741
Net operating loss carry forward 21,181 35,525
Investments in affiliated company due to equity share of
losses of affiliated company 1,062 997
-------- ---------
23,855 38,263
Less valuation allowance -- (25,600)
-------- ---------
Total deferred tax assets $ 23,855 $ 12,663
-------- ---------
Deferred tax liabilities:
Difference in depreciation and depletion of property, plant
and equipment and exploration expenditures (34,763) (11,837)
Net unrealized foreign exchange gains transferred to the
foreign currency translation reserve (3,258) (4,184)
-------- --------
Total deferred tax liabilities $(38,021) $(16,021)
-------- ---------
Net deferred tax liability (14,166) (3,358)
-------- ---------
</TABLE>
F-9
<PAGE> 55
The net change in the valuation allowance for the year ended December 31, 1998
was an increase of $25.6 million. This change was made to provide for
uncertainties surrounding the realization of net operating loss carryforwards.
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. The ultimate realization of deferred tax assets is
dependant upon the generation of future taxable income during the periods in
which those temporary differences become deductible. Management considers the
scheduled reversal of deferred tax liabilities, projected future taxable income
and tax planning strategies in making this assessment. The remaining balance of
deferred tax assets are expected to be realized through the reversal of taxable
temporary differences.
At December 31, 1998, the Company has net operating loss carryforwards for
United States federal and state income tax purposes of $98.7 million which are
available to offset future taxable income, if any, from 2005 through 2018.
3. EARNINGS PER SHARE
Basic earnings (loss) per ordinary share is computed by dividing net income
(loss) by the weighted average number of ordinary shares outstanding during the
respective period. Diluted earnings per ordinary share is computed by dividing
net income by the weighted average number of ordinary shares outstanding plus
potentially dilutive ordinary shares. When the Group reports a net loss,basic
and diluted net loss per share are the same.
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
(in thousands)
--------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Weighted average number of ordinary shares used in the
calculation of the basic earnings per share 86,297 104,977 107,320 107,601
Weighted average number of ordinary shares used in the
calculation of the diluted earnings per share 87,167 105,956 107,851 107,601
</TABLE>
The difference between the weighted average number of ordinary shares used for
basic and diluted arises due to the dilutive effect of unexercised options and
is measured utilizing the treasury stock method. There is no difference between
the basic and diluted weighted average number of ordinary shares in the 1998
year as the exercise price of the options is above the average market price and
the Group reported a net loss for the period, thus any consideration of stock
options would be anti-dilutive.
4. OTHER COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
(US dollars, in thousands)
----------------------------------------------------------------
<S> <C> <C> <C> <C>
Foreign currency translation adjustments - Australian operations
(no tax effect) $ 2,807 $ 1,463 $ (9,944) $ 540
======== ======== ======== =======
Foreign currency translation adjustments - assets held in foreign
currency $ (3,175) $ (2,191) $ 10,228 $(2,405)
Income tax effect 1,143 789 (3,682) 866
-------- -------- -------- -------
(2,032) (1,402) 6,645 (1,539)
-------- -------- -------- -------
$ 775 $ 61 $ (3,398) $ (999)
======== ======== ======== =======
Unrealized gains (losses) on investment securities
arising during the period $ (1,536) $ 781 $ (714) $ (3)
Income tax effect 553 (281) 257 1
-------- -------- -------- -------
$ (983) $ 500 $ (457) $ (2)
======== ======== ======== =======
</TABLE>
F-10
<PAGE> 56
<TABLE>
<CAPTION>
December 31, December 31,
(US dollars, in thousands) 1997 1998
- -----------------------------------------------------------------------------
<S> <C> <C>
5. NOTE ISSUE COSTS
Note issue costs:
- at cost $ 3,171 $ 3,171
- accumulated amortization (171) (489)
------- -------
Net note issue costs (see Note 1(q)) $ 3,000 $ 2,682
======= =======
6. PROPERTY, PLANT AND EQUIPMENT - AUSTRALIA
- at cost $ 455 $ 314
- accumulated depreciation (194) (212)
------- -------
$ 261 $ 102
======= =======
7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Current
Trade creditors $15,268 $ 8,130
Interest payable 393 893
Sundry creditors and accruals 2,200 3,698
Accruals - lease operating expenses 400 650
Accruals - capitalised costs of oil and gas
properties 9,708 111
Provision for income tax -- 67
------- -------
Total current creditors and accruals $27,969 $13,549
======= =======
8. OTHER ACCRUED LIABILITIES
Employee entitlements provision $ 307 408
Provision for dismantlement 3,289 2,488
------- -------
$ 3,596 $ 2,896
======= =======
</TABLE>
9. FINANCING ARRANGEMENTS AND FINANCIAL INSTRUMENTS DISCLOSURES
(a) Financing arrangements
The Group has US dollar debt relating to its US oil and gas operations.
Petsec Energy Inc., a wholly-owned subsidiary, issued during 1997 $100 million
of senior subordinated notes with a semi-annual coupon of 9.5%per annum and a
ten year maturity. These notes were issued at a discount with an annual yield to
maturity of 9.56% and mature on June 15, 2007. The notes are unsecured and
subordinated to senior debt of the subsidiary, including its bank debt. The
notes were issued pursuant to an indenture which contains certain restrictive
covenants on Petsec Energy Inc. A portion of the proceeds was used to repay the
then outstanding balance on the bank credit facility.
Petsec Energy Inc. also has a reserve-based revolving credit facility of $75
million with a syndicate of banks under which the borrowing base at December 31,
1998 was $75 million. At December 31, 1998 there were $74 million in borrowings
and $1.0 million in letters of credit and guarantees outstanding under the
facility. The facility is a two year revolving credit facility followed by a two
year term loan with equal quarterly amortization payments and a final maturity
of April 2001. The facility is secured by the producing properties and assets of
Petsec Energy Inc. The agreement contains certain restrictive financial
covenants on Petsec Energy Inc. Petsec Energy Inc. is currently in compliance
with the covenants. In February 1999, the borrowing base was reduced to $10
million as a result of the sale of certain assets more fully described in Note
15. Concurrent with the sale of assets, the Company repaid $65 million of the
facility, which is classified as current in the accompanying balance sheet.
A summary of the maturities of long-term debt of the Group is as follows:
<TABLE>
<CAPTION>
December 31, December 31,
1997 1998
(US dollars, in thousands)
------------------------------
<S> <C> <C>
Due within:
First year (current) $ -- $ 67,250
Second year -- 4,500
Third year -- 2,250
Fourth year -- --
Thereafter $100,000 $100,000
</TABLE>
(b) Interest rate risk exposures
Details of interest relating to the senior subordinated notes are shown in Note
9(a).
The interest rate on the borrowings under the revolving credit facility detailed
in Note 9(a) is LIBOR plus a margin of 1.25% to 1.75% per annum depending upon
the balance drawn. There is also a fee of 0.30% to 0.375% per annum on the
unused portion of the borrowing base. The weighted average interest rate for the
twelve months ended December 31, 1998 was 7.3%, (1997: nil).
At December 31, 1998, the weighted average interest rate for cash deposits was
4.375% per annum (1997: 5.8%). The other financial assets and liabilities
detailed in the financial statements (receivables, payables and investments) are
all non-interest bearing.
F-11
<PAGE> 57
9. FINANCING ARRANGEMENTS AND FINANCIAL INSTRUMENTS DISCLOSURES (CONTINUED)
(c) Foreign exchange exposures
Nearly all of the Group's operations are in the United States and its sales,
operating costs and capital expenditure are denominated predominantly in
USdollars. It holds substantially all its liquid funds in US dollars and its
borrowings are denominated in US dollars. Fluctuations in the Australian
dollar /US dollar exchange rate are expected to have only a small effect on the
underlying performance of the Group, as measured in US dollars. The Group's
policy is not to hedge the Australian dollar/US dollar exchange rate risk of its
investment in the United States.
(d) Commodity price exposures
The income of the Group is affected by changes in natural gas and crude oil
prices, and various financial transactions have been entered into (swap
contracts and collar contracts involving NYMEX commodity prices for natural gas
and crude oil) to reduce the effect of these changes. The Group has proved
reserves of these commodities sufficient to cover all these transactions and it
only enters into, holds or issues such derivatives to match underlying physical
production and reserves.
Swaps
In a swap agreement the Group receives from the counterparty the difference
between the agreed fixed price and the NYMEX settlement price if the latter is
lower than the fixed price. If the NYMEX settlement price is higher than the
agreed fixed price, the Group will pay the difference to the counterparty.
At December 31, 1998, the Group had the following outstanding contracts maturing
monthly:
(i) swap agreements for the sale of 14.3 million MMbtu of natural gas at an
average price of $2.311 per MMbtu through December 2000; and
(ii) swap agreements for the sale of 517,000 barrels of oil at an average price
of $19.70 per barrel through May 2000.
At December 31, 1998, the effect to the Company to terminate these contracts
would have been a gain of $3.2 million for oil (1997: $2.5m gain) and a gain of
$4.2 million for gas (1997: a loss of $1.6 million), representing the fair value
of the contracts at that date.
For the year ended December 31, 1998, hedging activities increased revenues by
$7.7 million, (year ended June 30, 1996: reduction of $4.2 million, six months
ended December 31, 1996: reduction of $3.6 million, year ended December 31,
1997: reduction of $4.4 million).
Collars
A collar agreement is similar to a swap except that the Group receives from the
counterparty the difference between the floor price and NYMEX settlement price
if the settlement price is below the floor. The Group pays to the counterparty
the difference between the ceiling price and the NYMEX settlement price if the
settlement price is above the ceiling.
At December 31, 1998, the Group had no collar agreements outstanding.
The termination values for both swap and collar agreements will vary with
movements in prices until the contracts mature.
(e) Credit risk exposures
Credit risk represents the loss that would be recognized if counterparties
failed to perform as contracted.
On-balance sheet financial assets:
The credit risk on financial assets, excluding investments, of the Group which
have been recognized on the balance sheet is the carrying amount, net of any
provision for doubtful debts.
Customers which account for 10% or more of sales revenue:
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
---------------------------------------------------------------------
<S> <C> <C> <C> <C>
Vision Resources, Inc. 55% 62% 46% 30%
Aquila Energy Marketing Corporation 33% * * *
PG&E Energy Trading Corporation -- -- 16% *
Duke Energy Trading and Marketing, L.L.C 10% 24% 22% 19%
Natural Gas Clearinghouse * 10% 12% --
Columbia Energy Services -- -- * 36%
(* = less than 10%)
</TABLE>
Based upon the current demand for oil and gas, the Group does not believe the
loss of any current purchasers would have a material adverse effect on the
Group. The Group continually evaluates the financial strength of its customers
but does not require collateral to support trade receivables.
F-12
<PAGE> 58
Off-balance sheet financial instruments:
The credit risk on off-balance sheet derivative contracts is considered minimal
as counterparties are recognized financial intermediaries such as banks or
commodity trading houses with acceptable credit ratings determined by a
recognized rating agency. Letters of credit of $750,000 (1997: $4,500,000) have
been issued to support the Group's commodity hedging program in the event that
commodity prices are above the contracted amounts upon settlement.
(f) Fair values of financial assets and liabilities
The carrying values of cash, accounts receivable and accounts payable are
estimated to approximate fair value because of their short maturity.
The fair values of investment securities and commodity price contracts are set
out on the balance sheet and in note 9(d), respectively. For these financial
instruments, fair value estimates are made at a specific point in time based on
relevant market quotes on the financial instrument. These quotes do not consider
the level of market trading and therefore the amounts actually received should
all investment securities be sold may differ from the quoted market prices.
At December 31, 1998 the net fair value of the $100 million senior subordinated
notes was $57 million (1997: $102.6 million) based on quoted market prices of
the notes.
10. SHARE CAPITAL
<TABLE>
<CAPTION>
December 31, December 31,
1997 1998
(US dollars, in thousands)
----------------------------
<S> <C> <C>
Issued capital
107,601,041 ordinary shares (1997: 107,601,041 shares of
20 Australian cents par value), fully paid $ 16,491 $ 122,697
</TABLE>
Abolition of par value shares
The Australian Company Law Review Act 1998 (the "Act") came into effect on July
1, 1998. The Act abolished par value shares, and any amount standing to the
credit of additional paid-in capital became part of the Company's share capital
on July 1, 1998. As a result, the balance of additional paid-in capital
amounting to $106,206,000 was transferred to the share capital account on July
1, 1998, increasing the share capital to $122,697,000. From July 1, 1998, share
capital does not have a par value.
At its general meeting on November 29, 1994, the Company approved the
establishment of an Employee Share Plan and an Employee Option Plan. The plans
are administered by a committee appointed by the Board. The Employee Share Plan
(and associated loan scheme) provides for the issue of ordinary shares in the
Company at the ruling market price to employees and directors of the Group. Such
shares are restricted over a period designated by the committee. In addition,
these shares are restricted unless the market price of the Company's shares is
greater than or equal to an amount established by the committee. The purchases
of the shares are financed by interest free loans from the Company to the
employees and directors.
The Employee Option Plan provides for the issue of options to buy shares in the
Company to employees and directors of the Group. The exercise prices of the
options are the ruling market prices when the options are issued. Such options
vest over a period of time as designated by the committee. In addition, the
options are unable to be exercised unless the market price of the Company's
shares is greater than or equal to an amount established by the committee. The
total shares and options issued to employees over a five year period is not to
exceed 6.5% of the issued shares in the Company. This was amended from 5% at the
Company's general meeting on May 25, 1998. As at December 31, 1998, the number
of further shares or options which could be issued within the 6.5% limit was
2,461,568.
At December 31, 1998, there were the following unexercised options to purchase
the Company's ordinary shares:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Date of grant Expiry date Number of shares Exercise price
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
November 6, 1995 November 6, 2000 69,000 A$2.95 (employee options)
January 3, 1996 January 3, 2001 110,000 A$3.40 (employee options)
July 22, 1996 July 21, 2001 951,000 A$4.87 (employee options)
July 22, 1996 July 20,2001 350,000 A$7.00
September 4, 1996 September 3, 2001 25,000 A$5.58 (employee options)
October 25, 1996 October 24, 2001 10,000 A$5.89 (employee options)
January 16, 1998 January 15, 2003 45,000 A$4.11 (employee options)
February 17,1998 February 16, 2003 100,000 A$4.43 (employee options)
---------
Total unexercised options 1,660,000
=========
</TABLE>
Options become exercisable after various dates and share prices of the Company
have been reached.
F-13
<PAGE> 59
10. SHARE CAPITAL (CONTINUED)
Option plan:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Number Weighted Weighted Number Weighted
of average average exercisable average
outstanding exercise remaining exercise
options price contractual price
life of those
(years) exercisable
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
As at June 30, 1995 1,640,000 A$1.69 2.3 400,000 A$0.22
Granted 347,000 A$3.09
Forfeited (5,000) A$2.95
Exercised (100,000) A$2.20
---------
As at June 30, 1996 1,882,000 A$1.75 2.6 640,000 A$0.69
Granted 2,172,000 A$5.26
Exercised (720,000) A$0.89
---------
As at December 31, 1996 3,334,000 A$4.22 4.0 470,000 A$2.03
Granted 50,000 A$5.69
Forfeited (113,000) A$4.87
Exercised (970,000) A$2.09
---------
As at December 31, 1997 2,301,000 A$5.12 3.5 82,000 A$2.95
Granted 230,000 A$4.33
Forfeited (871,000) A$4.92
---------
As at December 31, 1998 1,660,000 A$5.11 2.6 -- --
=========
</TABLE>
Employee Share Plan:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Number Weighted Weighted Number Weighted
of average average unrestricted average
outstanding issue remaining issue
shares subject price contractual price
to life of those
employee loans of loan vested
(years)
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
As at June 30, 1995 2,237,500 A$1.75 4.5 0 N/A
Issued 35,000 A$3.36
Forfeited (27,500) A$1.75
Transferred to employees (160,000) A$1.75
---------
As at June 30, 1996 2,085,000 A$1.78 3.6 1,200,000 A$1.75
Issued 200,000 A$5.60
---------
As at December 31, 1996 2,285,000 A$2.11 3.2 1,200,000 A$1.75
Transferred to employees (410,000) A$1.75
---------
As at December 31, 1997 1,875,000 A$2.19 2.6 1,665,000 A$1.75
---------
Movements -- --
---------
As at December 31, 1998 1,875,000 A$2.19 1.3 -- --
=========
</TABLE>
<TABLE>
<CAPTION>
----------------------------------------------------------
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
-------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Weighted average grant-date fair value of:
Options granted at market price $ 0.58 $ 1.11 $0.91 $0.83
Options granted above market price -- $ 0.64 -- --
Employee shares issued at market price $ 0.71 $ 1.21 -- --
</TABLE>
F-14
<PAGE> 60
11. SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Twelve months Six months Twelve months ended
ended ended
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Issued capital $ 14,899 $ 16,344 $ 16,491 $ 122,697
Additional paid-in capital 31,453 102,421 105,269 --
Accumulated other comprehensive income (loss) (174) 387 (3,468) (4,469)
Retained earnings (deficit) 3,375 (25,011) (14,731) (111,236)
Subscriptions receivable (2,074) (2,740) (2,406) (2,637)
--------- --------- --------- ---------
Total shareholders' equity $ 47,479 $ 91,401 $ 101,155 $ 4,355
========= ========= ========= =========
Movements during the financial period
Issued capital
Balance at the beginning of the financial period $ 13,630 $ 14,899 $ 16,344 $ 16,491
Share placement 1,254 3,145 -- --
Ordinary shares issued on exercise of options 15 113 147 --
Ordinary shares issued under Employee Share Plan 4 32 -- --
Shares bought back under Employee Share Plan (4) -- -- --
Selective share buy back -- (1,845) -- --
Transfer balance of additional paid-in capital to share
capital on July 1, 1998 resulting from amendments to the
Australian Corporations Law
abolishing par
value shares -- -- -- 106,206
--------- --------- --------- ---------
Balance at the end of the financial period $ 14,899 $ 16,344 $ 16,491 $ 122,697
========= ========= ========= =========
Additional paid-in capital
Balance at the beginning of the financial period $ 13,621 $ 31,453 $ 102,421 $ 105,269
Share placement net of issue costs 16,220 68,128 (8) --
Premium on ordinary shares issued on exercise of options 147 391 1,395 --
Premium on ordinary shares issued under Employee
Share Plan 85 876 -- --
Shares bought back under Employee Share Plan (33) -- -- --
Other (378) 1,240 -- --
Additional paid-in capital in respect of stock compensation 1,791 333 1,461 937
Transfer of balance of additional paid-in capital to share
capital on July 1, 1998 resulting from amendments to the
Australian Corporations Law abolishing par value shares -- -- -- (106,206)
--------- --------- --------- ---------
Balance at the end of the financial period $ 31,453 $ 102,421 $ 105,269 $ --
========= ========= ========= =========
Retained earnings (deficit)
Balance at the beginning of the financial period $ (4,380) $ 3,375 $ (25,011) $ (14,731)
Net income (loss) 7,755 10,953 10,280 (96,505)
Selective share buy back -- (39,339) -- --
--------- --------- --------- ---------
Balance at the end of the financial period $ 3,375 $ (25,011) $ (14,731) $(111,236)
========= ========= ========= =========
Subscriptions receivable
Balance at the beginning of the financial period $ (2,001) $ (2,074) $ (2,740) $ (2,406)
Changes in Employee Share Plan loans 165 (564) 524 11
Discount on Employee Share Plan loans (238) (102) (190) (242)
--------- --------- --------- ---------
Balance at the end of the financial period $ (2,074) $ (2,740) $ (2,406) $ (2,637)
========= ========= ========= =========
Accumulated other comprehensive income (loss)
Unrealized gain (loss) on investment securities
Balance at the beginning of the financial period $ 927 $ (56) $ 444 $ (13)
Unrealized gains (losses) arising during the period (983) 500 (457) (2)
--------- --------- --------- ---------
Balance at the end of the financial period (56) 444 (13) (15)
--------- --------- --------- ---------
</TABLE>
F-15
<PAGE> 61
11. SHAREHOLDERS' EQUITY (CONTINUED)
<TABLE>
<CAPTION>
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Foreign currency translation reserve
Balance at the beginning of the financial period (893) (118) (57) (3,455)
Current period change 775 61 (3,398) (999)
------- ------ -------- ---------
Balance at the end of the financial period (118) (57) (3,455) (4,454)
------- ------ -------- ---------
Balance at the end of the financial period $ (174) $ 387 $ (3,468) $ (4,469)
======= ====== ======== =========
</TABLE>
12. COMMITMENTS AND CONTINGENT LIABILITIES
(a) Contingent liabilities
As at December 31, 1998, the estimated maximum contingent liability of the Group
in respect of securities issued in compliance with the conditions of various
agreements and permits granted to controlled entities pursuant to governmental
acts and regulations is $1,042,000 (1997: $10,191,000).
A subsidiary of the Company has been named as a defendant in certain lawsuits
arising in the ordinary course of business. While the outcome of any of these
lawsuits cannot be predicted with certainty, directors do not expect these
matters to have a material adverse effect on the financial position, results of
operations or liquidity of the subsidiary or the Group.
As at December 31, 1998, the total restoration and reclamation costs including
platform removals, and monitoring is estimated to be $8,539,000 (1997:
$7,318,000). This estimated expense is recognized progressively over the life of
each production facility.
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 US
federal, state and local laws and regulations primarily relating to protection
of human health and environment. To date, expenditure related to complying with
these laws and for remediation of existing environmental contamination has not
been significant in relation to the results of operations of the Group.
In addition, a subsidiary has contingent liabilities in respect of its commodity
hedging program (see Note 9).
(b) Lease commitments
<TABLE>
<CAPTION>
December 31,
1998
(US dollars, in thousands)
--------------------------
<S> <C>
Future operating lease rentals on property:
Due not later than 1 year $ 397
Due later than 1 year but not later than 2 years 237
Due later than 2 years but not later than 3 years 150
Due later than 3 years but not later than 4 years 150
Due later than 4 years but not later than 5 years 150
Due later than 5 years 301
--------
$ 1,385
--------
</TABLE>
(c) Guarantees
The Company has guaranteed the fulfilment by controlled entities of commitments
to provide funds for expenditure in respect of exploration, evaluation and
development of projects and investments as and when they fall due. Most of these
guarantees are in the process of being released.
(d) Superannuation commitments
The Group contributes to one employer established accumulation superannuation
fund and to employees' private superannuation arrangements. Employee
contributions are based on various percentages of their gross salaries. The
Group is under no legal obligation to make up any shortfall in the employer
established accumulation fund's assets or to meet payments due to employees. No
actuarial assessment has been undertaken and an assessment is not required. The
assets of the fund are sufficient to meet all benefits payable in the event of
its termination, or the voluntary or compulsory termination of employment of
each employee of the Group. During the twelve months ended June 30, 1996, six
months ended December 31, 1996 and the two years ended December 31, 1997 and
1998, superannuation contributions were $59,000, $86,000, $179,000 and $220,000,
respectively.
13. SEGMENT REPORTING
In the years ended December 31, 1997 and 1998, the Group operated predominantly
within the USA in oil and gas exploration and production. All operating revenues
are derived in the USA from sales of oil and gas. Virtually all long lived
assets are located in the USA and are utilized in oil and gas exploration,
development and production.
F-16
<PAGE> 62
14. RELATED PARTY DISCLOSURES
(a) Directors
At December 31, 1998 the aggregate amount of loans outstanding to directors was
$2,419,000 (December 1997: $2,419,000). These loans were five year interest free
loans made under the Company's Employee Share Plan to finance the purchase of
the Company's shares. The outstanding loans were to four directors of the
Company and to an employee who is a director of a subsidiary.
A company associated with a director provided management services to the Group
in the ordinary course of business and on normal terms and conditions. The cost
of the services provided to the Group during the year by this company was
$437,000 (1997: $290,000; six months to December 31, 1996: $133,000; twelve
months to June 30, 1996: $371,000).
(b) Related entities
Climax Mining Ltd was charged an amount of $347,000 by the Company for the
provision of management, financial and office services for the year to December
31, 1998 (1997: $475,000; six months to December 31, 1996: $257,000; twelve
months to June 30, 1996: $365,000).
15. EVENTS SUBSEQUENT TO BALANCE DATE
In February 1999, Petsec Energy Inc., a US subsidiary, completed the sale of a
50% working interest in certain of its oil and gas properties to Apache
Corporation for cash consideration of $68.3 million. The transaction was
effective January 1, 1999. Revenue in 1998 attributed to the 50% working
interest that was sold was $41 million.
The effect on the financial statements was that the current asset of $68.3
million listed as "assets held for sale" in the December 31 1998 balance sheet
was disposed of for cash. Of the cash received, $65.0 million was used to repay
the Revolving credit facility, reducing outstandings under the facility to $9.0
million.
16. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
(US dollars, in thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash paid during the period for:
Interest $ 3,746 $ 1,472 $ 6,022 $ 8,202
Income taxes 493 307 136 262
Non-cash activities
During fiscal 1996 an affiliate sold shares in which
the Company did not participate. As a result in
recording the Company's ownership percentage of this
sale, the investment balance and additional paid-in
capital decreased by $ (243) $ -- $ -- $ --
During the year the increase (decrease) in market value
of investment securities increased (decreased) the investment
balance and equity account - accumulated other comprehensive
income (loss) $ (2) $ 872 $ (89) $ --
During fiscal 1996 investment securities were disposed of
resulting in a decrease in the investment balance and the equity
account - accumulated other comprehensive income (loss) $(1,534) $ -- $ -- $ --
Deferred taxes associated with the movements from the
above-mentioned transactions caused the equity and
deferred taxation balances to change by $ (640) $ (314) $ -- $ --
</TABLE>
F-17
<PAGE> 63
17. RECONCILIATION OF NET INCOME (LOSS) AND SHAREHOLDERS'
EQUITY FROM AUSTRALIAN GAAP TO US GAAP
The company prepares separate Australian dollar financial statements in
conformity with Australian generally accepted accounting principles ("AUS
GAAP"), as its primary listing is on the Australian Stock Exchange. The purpose
of this note is to reconcile net income (loss) and shareholders' equity,
utilizing the US dollar as the reporting currency for both AUS GAAP and US GAAP,
and list the principal differences between AUS GAAP and US GAAP.
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net income (loss) in accordance with US GAAP $ 7,755 $ 10,953 $ 10,280 $ (96,505)
Adjustments for:
Climax Mining Ltd 623 1,326 1,596 --
Deconsolidation of Climax Mining Ltd (5,126) -- -- --
Oil and gas exploration expenditure 1,829 2,418 6,316 2,714
Oil and gas exploration amortized (667) (214) (1,378) (1,609)
Dry hole costs and impairments -- -- -- (5,010)
Sale of investment -- 2,737 -- --
Rehabilitation expenses (129) (114) (56) 16
Deferred compensation expense 202 (117) (280) 37
Stock compensation expense 1,749 677 1,461 937
Interest income on subscriptions receivable (196) (102) (190) (242)
Other 39 -- -- --
Tax effect of AUS GAAP adjustments (833) (2,665) (2,345) 5,132
--------- --------- --------- ---------
Net income (loss) in accordance with Australian GAAP $ 5,246 $ 14,899 $ 15,404 $ (94,530)
========= ========= ========= =========
Shareholders' equity in accordance with US GAAP at
period end $ 47,479 $ 91,401 $ 101,155 $ 4,355
Adjustments for:
Equity in Climax Mining Ltd 2,356 6,125 5,678 5,166
Oil and gas exploration expenditure 7,592 10,011 16,327 14,599
Oil and gas exploration amortized (752) (966) (2,344) (4,468)
Rehabilitation expenses 310 196 140 104
Deferred compensation expense 603 485 205 206
Additional share capital in respect of employee shares 870 882 882 882
Subscriptions receivable in respect of employee shares 2,074 3,084 2,406 1,620
Cumulative effect of AUS GAAP adjustments on foreign
currency translation reserve 213 (20) (655) (1)
Other -- -- 20 23
--------- --------- --------- ---------
Cumulative tax effect of AUS GAAP adjustments (1,614) (5,528) (6,410) (998)
Shareholders' equity excluding minority interests in
--------- --------- --------- ---------
accordance with Australian GAAP at period end $ 59,131 $ 105,670 $ 117,404 $ 21,488
========= ========= ========= =========
</TABLE>
PRINCIPAL DIFFERENCES BETWEEN AUS GAAP AND US GAAP
The principal differences between AUS GAAP and US GAAP which are material to the
preparation of the consolidated financial statements of the Group are set out
below in this note. See note 1 for a description of US GAAP policies related to
the discussion below.
EXPLORATION AND DEVELOPMENT EXPENDITURE
Under AUS GAAP, all exploration and development expenditure is capitalized to
the extent that it is expected to be recouped through successful exploitation of
an area or sale, or where exploration and evaluation activities have not yet
reached a stage which permits a reasonable assessment of the existence of
economically recoverable reserves, and significant activities are continuing.
The main difference from AUS GAAP is that under US GAAP all general, geological
and geophysical costs are expensed as incurred. Under both US GAAP and AUS GAAP
drilling costs of successful wells are capitalized and drilling costs relating
to unsuccessful exploration wells are written off.
F-18
<PAGE> 64
CONSOLIDATED ENTITIES
Under AUS GAAP, the Company was required to consolidate Climax Mining Ltd
("Climax") until it ceased to be a "controlled entity" on April 23 1996. AUS
GAAP requires an entity to be consolidated when certain tests relating to the
substance and the form of control indicate the existence of control by one
entity over another. Under US GAAP the investment in Climax, as an affiliate, is
accounted for under the equity method of accounting. Until June 1996, the
Company also had a 50% beneficial interest in two unit property trusts, which
were consolidated under AUS GAAP but equity accounted under US GAAP.
INVESTMENTS IN AFFILIATES
Under AUS GAAP investments in affiliates are initially recorded at cost.
Investments in affiliates may be revalued. Income from investments in affiliates
is recognized only to the extent of dividends received or receivable from
post-acquisition profits of the investee.
TRADING AND INVESTMENT SECURITIES
Under AUS GAAP investment securities held for trading purposes are stated at the
lower of aggregate cost and net realizable value. Investment securities are
stated at cost or at a directors' valuation.
ASSET REVALUATION
Under AUS GAAP non-current assets may be revalued both upwards and downwards
based on directors' valuations. An upwards revaluation is recorded by an
increase in the asset revaluation reserve as a component of shareholders' equity
and is not taken through the statement of operations except where a previous
revaluation decrement has been recorded for that class of assets through the
statement of operations. An impairment or downwards revaluation is taken through
the statement of operations except where there is a revaluation reserve for that
particular class of assets, in which case the decrement decreases the asset
revaluation reserve, to the extent it exists. US GAAP does not permit the upward
revaluation of assets.
FOREIGN CURRENCY TRANSACTION GAINS AND LOSSES
Under AUS GAAP certain foreign exchange translation gains and losses are
capitalized to exploration expenditure while projects are in the exploration
phase.
INCOME TAXES
Accounting under AUS GAAP is under the liability method and is equivalent in
most major respects to SFAS No. 109, "Accounting for Income Taxes". However for
AUS GAAP, deferred tax assets related to temporary differences are brought to
account when they are "assured beyond a reasonable doubt" and net operating
losses pass a "virtually certain" threshold. For AUS GAAP, the effect of a
change in tax rate is recorded in the period the government approves the budget
which in fiscal 1995 preceded the enactment date which occurred in fiscal 1996.
Accordingly, the effect of the increase in the Australian tax rate from 33% to
36% is recognized for AUS GAAP purposes in fiscal 1995 and for US GAAP purposes
in fiscal 1996.
EMPLOYEE COMPENSATION
Under AUS GAAP employee options issued under the Employee Option Plan do not
result in compensation expense. The options are issued at the current market
price on the grant date. The options have a vesting period of at least six
months and may require the market price of the Company's shares to have
appreciated to a certain level ("hurdle price") before the options become
exercisable.
Similarly, under AUS GAAP the employee shares issued under the Employee Share
Plan do not result in compensation expense. Under the Employee Share Plan shares
are issued at the current market price on the issue date. The shares are funded
by interest free loans, generally for five years. The shares cannot be sold for
a minimum restricted period of at least six months and may require the market
price of the Company's shares to have appreciated to a certain level before the
shares become unrestricted.
Under AUS GAAP deferred compensation is brought to account when there is an
obligation to pay. Under US GAAP deferred compensation is accrued over the
period of service to which it relates based on an estimate of final costs.
ADJUSTMENTS TO RESTORATION AND RECLAMATION PROVISIONS
Under both AUS GAAP and US GAAP, restoration and reclamation provisions are
accrued on a unit of production basis. Under AUS GAAP, when a revised assessment
of the final reclamation costs results in the accrual previously provided being
in excess of the amount required, the provision may be reduced in the current
year to a cumulative amount based on the revised estimate and consequently a
cumulative reduction may be recognized in the statement of operations.
Subsequent charges for reclamation provisions are calculated from the reduced
provision on the balance sheet. Under US GAAP changes in estimated restoration
provisions are accounted for on a prospective basis and affect future
provisions.
OTHER
Under AUS GAAP, the Company does not record depreciation expense on buildings
held as investment properties.
F-19
<PAGE> 65
18. SELECTED CONSOLIDATED FINANCIAL DATA UNDER US GAAP
FOR CLIMAX MINING LTD AND ITS SUBSIDIARIES
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
(US dollars, in thousands)
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $ 7,866 $ -- $ -- $ 631
--------- -------- --------- --------
Income (loss) from operations before interest and taxation 5,174 35,451 (9,569) (8,049)
--------- -------- --------- --------
Net income (loss) $ 1,349 $ 36,638 $ (9,063) $ (9,276)
--------- -------- --------- --------
</TABLE>
<TABLE>
<CAPTION>
December 31, December 31,
1997 1998
(US dollars, in thousands)
-------------------------
<S> <C> <C>
Current assets $ 17,344 $ 4,958
--------- --------
Non-current assets
Investment securities 2,073 1,207
Other non-current assets 20,831 19,033
--------- --------
22,904 20,240
--------- --------
Total assets 40,248 25,198
--------- --------
Current liabilities 4,495 559
Non-current liabilities 373 184
Shareholders' equity 35,380 24,455
--------- --------
Total liabilities and shareholders' equity $ 40,248 $ 25,198
--------- --------
Included in shareholders' equity are the following unrealized gains
(losses) on investment securities, net of tax effect $ (107) $ --
</TABLE>
19. 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.
Estimates of proved and proved developed reserves at June 30, 1996 and December
31, 1996, 1997 and 1998 were based on studies performed by Ryder Scott Company.
No major discovery or other favourable or adverse event subsequent to December
31, 1998 is believed to have caused a material change in the estimates of proved
or proved developed reserves as of that date. For the purposes of the disclosure
below, the effect of the sale of interests in certain oil and gas properties
(see note 15) effective January 1, 1999 are reflected as if sold December 31,
1998.
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) at
the end of each of the four fiscal periods in the period ended December 31,
1998, as estimated by Ryder Scott Company. The table excludes estimates of
proved reserves for the Company's interest in the EP 129 joint venture in
Australia as the effect is immaterial. The Company's share of oil production
from the EP 129 joint venture for the twelve month period ended June 30, 1996
was 22 Mbbls. The interest in EP129 was disposed of in the period ended June 30,
1996.
F-20
<PAGE> 66
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(MBbl) (MMcf)
- ----------------------------------------------------------------------------------
<S> <C> <C>
Proved developed and undeveloped reserves:
June 30, 1995 6,881 20,327
Revisions of previous estimates 809 (175)
Extensions, discoveries and other additions 4,185 53,196
Production (1,658) (11,468)
------ ------
June 30, 1996 10,217 61,880
Revisions of previous estimates (1,312) 5,561
Extensions, discoveries and other additions 558 11,877
Production (1,145) (6,027)
------ ------
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
Revisions of previous estimates (66) (18,985)
Extensions, discoveries and other additions 1,168 4,738
Sales of reserves in place* (4,053) (25,700)
Purchase of reserves in place -- 1,440
Production (2,353) (25,390)
------ ------
December 31, 1998 5,337 58,252
====== ======
Proved developed reserves:
June 30, 1996 8,084 31,043
December 31, 1996 6,670 43,133
December 31, 1997 8,430 88,199
December 31, 1998 3,054 26,965
</TABLE>
* relates to sale to Apache Corporation of a 50% working interest in certain
properties effective January 1, 1999.
<TABLE>
<CAPTION>
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Capitalized costs for oil and gas producing activities
consist of the following:
Proved properties $ 118,462 $ 169,982 $ 294,005 $ 199,586
Unproved properties 10,890 7,276 20,759 31,984
--------- --------- ---------- ---------
Total capitalized costs 129,352 177,258 314,764 231,570
Accumulated depletion, depreciation and amortization (29,303) (44,349) (106,392) (132,739)
--------- --------- ---------- ---------
Net capitalized costs $ 100,049 $ 132,909 $ 208,372 $ 98,831
--------- --------- ---------- ---------
</TABLE>
F-21
<PAGE> 67
19. SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)
<TABLE>
<CAPTION>
Twelve months ended Six months ended Twelve months ended
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Costs incurred for oil and gas property acquisition, exploration
and development activities are as follows:
Lease acquisition $ 7,577 $ 44 $ 8,437 $ 7,836
Exploration 53,974 46,147 115,523 107,111
Development 15,345 6,966 31,327 10,301
-------- -------- -------- --------
Total costs incurred $ 76,896 $ 53,157 $155,287 $125,248
-------- -------- -------- --------
</TABLE>
Standardized measure of discounted future net cash flows relating to proved oil
and gas reserves
The following information has been developed utilizing procedures prescribed by
Statement of Financial Accounting Standards No. 69 (SFAS No. 69) "Disclosures
about Oil and Gas Producing Activities" 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% annual 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, 1998 approximately 14.3 million MMbtu of the
Company's future gas production and 517,000 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 pre-tax net cash
flows, reduced by the tax basis of the properties involved and tax carry
forwards. Use of a 10% annual 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.
The standardized measure of discounted future net cash flows relating to proved
oil and gas reserves is as follows. For the purpose of this disclosure below,
the effect of the sale of interest in ceratin oil and gas properties (see note
15) effective January 1, 1999 are reflected as if sold on December 31, 1998.
<TABLE>
<CAPTION>
June 30, December 31, December 31, December 31,
1996 1996 1997 1998
(US dollars, in thousands)
------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Future cash inflows $ 369,921 $ 479,220 $ 472,470 $ 183,371
Future production costs (51,244) (58,367) (101,765) (55,456)
Future development and abandonment costs (55,610) (47,873) (53,851) (44,783)
Future income tax expense (61,956) (102,669) (64,064) --
--------- --------- --------- ---------
Future net cash flows after income taxes 201,111 270,311 252,790 83,132
10% annual discount for estimated timing of cash flows (40,569) (46,930) (48,676) (16,079)
--------- --------- --------- ---------
Standardized measure of discounted future net cash flows $ 160,542 $ 223,381 $ 204,114 $ 67,053
--------- --------- --------- ---------
</TABLE>
F-22
<PAGE> 68
<TABLE>
<CAPTION>
June 30, December 31, December 31, December 31,
(US dollars, in thousands) 1996 1996 1997 1998
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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:
Beginning of the period $ 65,136 $ 160,542 $ 223,381 $204,114
--------- --------- --------- --------
Sales and transfers of oil and gas produced, net of
production costs (44,469) (34,180) (113,462) (77,028)
Net changes in prices and production costs 19,569 75,645 (142,243) (86,433)
Extensions, discoveries and improved recoveries, net of
future production and development costs 161,906 43,031 134,467 13,422
Net changes due to revision in quantity estimates 9,697 6,532 40,994 (21,677)
Development costs incurred during the financial period 14,820 3,728 1,050 2,251
Sales of reserves in place* -- -- -- (57,164)
Purchase of reserves in place -- -- -- 1,646
Change in estimated future development costs (40,578) (3,313) (5,674) 5,499
Accretion of discount 12,423 6,783 32,481 30,749
Net change in income taxes (37,962) (35,387) 33,120 51,674
--------- --------- --------- --------
Net increase (decrease) 95,406 62,839 (19,267) 137,061)
--------- --------- --------- --------
End of the period $ 160,542 $ 223,381 $ 204,114 $ 67,053
</TABLE>
The computation of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves at December 31,1998 was based on average
natural gas prices of approximately $2.04 per mcf and on average liquids of
approximately $11.98 per barrel.
* Relates to sale to Apache Corporation of a 50% working interest in certain
properties effective January 1, 1999.
F-23
<PAGE> 69
PETSEC ENERGY LTD Petsec Energy Ltd and subsidiaries
INDEPENDENT AUDITORS' REPORT TO THE BOARD OF
DIRECTORS AND STOCKHOLDERS OF PETSEC ENERGY LTD
We have audited the accompanying consolidated balance sheets of Petsec Energy
Ltd (a company incorporated in New South Wales, Australia) and subsidiaries as
of December 31, 1997 and 1998 and the related consolidated statements of
operations, consolidated statements of comprehensive income (loss), and
consolidated statements of cash flows for the year ended June 30, 1996, the six
month period ended December 31, 1996 and each of the years in the two year
period ended December 31, 1998, expressed in US dollars. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in Australia, which do not differ in any significant respect from auditing
standards generally accepted in the United States. Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Petsec Energy Ltd
and subsidiaries as of December 31, 1997 and 1998 and the results of their
operations and cash flows for the year ended June 30, 1996, the six month period
ended December 31, 1996 and each of the years in the two year period ended
December 31, 1998, in conformity with generally accepted accounting principles
in the United States.
/s/ KPMG
KPMG
Sydney, Australia
March 31, 1999
F-24
<PAGE> 70
EXHIBIT INDEX
23.1 Consent of KPMG
23.2 Consent of Ryder Scott Company
<PAGE> 1
EXHIBIT 23.1
The Board of Directors
Petsec Energy Ltd
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statement on
Form S-8 (No. 333-6128) of Petsec Energy Ltd of our report dated March 31,
1999, relating to the consolidated balance sheets of Petsec Energy Ltd and
subsidiaries as of December 31, 1997 and 1998 and the related consolidated
statements of operations, comprehensive income (loss) and cash flows for the
year ended June 30, 1996, the six month period ended December 31, 1996 and for
each of the years in the two year period ended December 31, 1998, which report
appears in the December 31, 1998 annual report on Form 20-F of Petsec Energy
Ltd.
KPMG
Sydney, Australia
June 10, 1999
<PAGE> 1
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
As independent petroleum engineers, we hereby consent to the use of our name
in the Annual Report and Form 20-F of Petsec Energy Ltd, parent of Petsec
Energy Inc, for the period ended December 31, 1998. We further consent to the
inclusion of our estimate of reserves and present value of future net reserves
in such Annual Report.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
May 12, 1999
