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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
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(Mark One)
[ ] REGISTRATION STATEMENT PURSUANT TO SECTION
12(B) OR (G) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
OR
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the twelve months ended December 31, 1997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from...............TO.....................
Commission file number 0-28608
PETSEC ENERGY LTD
(PREVIOUSLY: PETROLEUM SECURITIES AUSTRALIA LIMITED)
(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 2000, 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
Page
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Introduction.................................................................... 3
Glossary of Certain Industry Terms.............................................. 4 - 5
PART I
Item 1. Description of Business............................................... 6 - 19
Item 2. Description of Properties............................................. 19
Item 3. Legal Proceedings..................................................... 19
Item 4. Control of Registrant................................................. 20
Item 5. Nature of Trading Market.............................................. 21 - 22
Item 6. Exchange Controls and Other Limitations Affecting Security Holders.... 22 - 23
Item 7. Taxation.............................................................. 23 - 24
Item 8. Selected Financial Data.................................. 24 - 26
Item 9. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................... 26 - 33
Item 9A. Quantitative and Qualitative Disclosure about Market Risk 34
Item 10. Directors and Officers of Registrant.................................. 35 - 36
Item 11. Compensation of Directors and Officers................................ 37
Item 12. Options to purchase Securities from Registrant or Subsidiaries........ 37
Item 13. Interest of Management in Certain Transactions........................ 37
PART II
Item 14. Description of Securities to be Registered............................ 38
PART III
Item 15. Defaults Upon Senior Securities....................................... 38
Item 16. Changes in Securities and Changes in Security for
Registered Securities............................................... 38
PART IV
Item 17. Financial Statements.................................................. 38
Item 18. Financial Statements.................................................. 38
Signatures...................................................................... 39
Item 19. Financial Statements and Exhibits..................................... F1 - F36 and
Ex-23.1 and Ex-23.2
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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 (formerly Petroleum
Securities Australia Limited), an Australian public limited company (Australian
Company Number 000 602 700), 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") and it also publishes consolidated financial statements in
US dollars and under US generally accepted accounting principles ("US GAAP") as
set out in Notes 29 and 30 of the US Dollar Financial Statements included under
Item 18 in this Form 20-F.
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 year ended December 31, 1997. The Company's fiscal year end
changed in 1996 from June 30 to December 31 and this report covers fiscal years
ended June 30, 1995 and June 30, 1996, the six month period ended December 31,
1996 and the fiscal year ended December 31, 1997.
References to "US dollars" or "US$" or "$" are to United States dollars
and references to "A$" are to Australian dollars. The US Dollar Financial
Statements contain translations of certain Australian dollar amounts into US
dollars at specified rates. The translations in the financial statements have
been made at the exchange rates set out in the notes to the US Dollar Financial
Statements.
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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 or
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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ITEM 1 - DESCRIPTION OF BUSINESS
GENERAL
Petsec Energy Ltd is an independent exploration and production company
operating in the shallow waters of the Gulf of Mexico. The Company established
its Gulf of Mexico operations in 1990. Through December 1997, by following a
focussed, integrated strategy of exploration and development, the Company has
found or acquired 284 Bcfe of estimated net proved reserves, 98 Bcfe of which
have been produced by the Company and 186 Bcfe of which were remaining net
proved reserves at December 1997. Nearly all of this 284 Bcfe has been
discovered by the Company through drilling. The Company drilled 42 wells through
December 1997 with an average finding and development cost of $1.22 per Mcfe.
Over the previous three and a half years the reserve growth has averaged 70% per
annum. Approximately 66% of the remaining proved reserves were natural gas.
Currently, the Company owns 100% of the working interest in all but
one of its 34 leasehold blocks in the Gulf of Mexico, 18 of which are
productive.
BUSINESS STRATEGY
The Company's objective is to expand its oil and gas reserves and
increase its profits and cash flow through drilling. The Company pursues this
objective by following a focussed, integrated strategy which incorporates the
following elements:
O geographic focus in the shallow waters of the Gulf of Mexico;
O where possible, a 100% working interest ownership in its leases in
order to control exploration, development and marketing decisions;
O extensive use of 3-D seismic and other advanced geophysical
technologies; and
O active lease acquisition program to increase its inventory of
exploration prospects.
Focussing in the shallow waters of the Gulf of Mexico. The Company's
activities are focussed in the shallow waters of the Gulf of Mexico, primarily
offshore Louisiana. The Company believes that this region has significant
remaining undiscovered reserves, in both unexplored and previously explored
areas. The Gulf of Mexico's substantial and expanding infrastructure permits the
Company to lower its operating costs compared to other geologic regions and
facilitates the timely development of its oil and gas discoveries. The Company's
team of geologists, geophysicists and production engineers has substantial
experience in the shallow waters of the Gulf of Mexico, and the Company believes
that it is well-positioned to evaluate, explore and develop properties in this
area.
Controlling operations and costs. The Company holds 100% of the working
interest in all but one of its Gulf of Mexico properties, unlike many other
independent energy companies that conduct business through fractional working
interests and non-operated joint ventures. The holding of 100% interests enables
the Company to effectively control expenses, capital allocation and the timing
and method of exploration and development of its properties.
The Company currently operates production facilities covering 18 lease
blocks and 46 wells in the Gulf of Mexico. A significant portion of the
prospects the Company intends to drill during the next three years is in close
proximity to production facilities currently operated by the Company. By
maximizing the use of its existing infrastructure, the Company is able to lower
its operating costs. The Company also pursues cost savings through the use of
outside contractors for much of its field operations and permitting work. For
the twelve months to December 31, 1997 the Company's lease operating expenses
averaged $0.25 per Mcfe.
Applying advanced technologies. The Company uses advanced exploration
and other technologies, such as 3-D seismic and time-depth migration, in its
lease acquisition assessment and in its exploration and development activities
to evaluate and prioritize drilling prospects and to attempt to reduce risks and
lower costs. Analyzing and interpreting 3-D seismic data, which is available for
the shallow waters of the Gulf of Mexico at reasonable costs, has enabled the
Company
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to identify multiple exploratory and development prospects in both mature
producing fields and in unexplored areas that were not identified through
earlier technologies.
Expansion of exploration and development prospects. The Company's
strategy in building its inventory of prospects is to bid on blocks on which it
has identified prospects at OCS and state lease sales. The Company has acquired
30 of its 34 lease blocks at such sales. As of December 31, 1997, the Company
had not yet conducted drilling operations on 16 of these lease blocks, many of
which have multiple prospects. The Company anticipates drilling most of these
prospects in the next three to five years. At the March 18, 1998 OCS Louisiana
offshore sale the Company was the highest bidder on seven further lease blocks,
five of which are in close proximity to the Company's existing producing leases.
The cost of these blocks, if they are all awarded, will be $7.8 million.
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 March 13, 1998 was A$0.33 per share ($0.22 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, 1993, 1994, 1995 and 1996 and December
31, 1996 and 1997. 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.
AS OF JUNE 30 AS OF DECEMBER 31
---------------------------------------------- -------------------
1993 1994 1995 1996 1996 1997
---- ---- ---- ---- ---- ----
TOTAL NET PROVED:
Oil (MBbls) 1,136 2,650 6,881 10,217 8,318 10,641
Gas (MMcf) 11,755 12,830 20,327 61,880 73,291 122,149
Total (MMcfe) 18,571 28,730 61,613 123,182 123,199 185,995
NET PROVED DEVELOPED:
Oil (MBbls) 1,136 2,650 4,076 8,084 6,670 8,430
Gas (MMcf) 11,755 12,830 12,003 31,043 43,133 88,199
Total (MMcfe) 18,571 28,730 36,459 79,547 83,153 138,779
Estimated future net revenues before income
taxes (in thousands) $29,387 $44,480 $102,517 $263,067 $372,980 $316,855
Present value of estimated future net revenues
before income taxes (in thousands) (1) $24,653 $34,990 $ 76,632 $210,000 $308,226 $255,839
Standardized measure of discounted future net
cash flows (in thousands) (2) $21,509 $30,122 $ 65,136 $160,542 $223,381 $204,114
Average prices used in calculating the net
present values:
Oil ($ per bbl) $16.17 $17.92 $17.43 $19.73 $25.09 $17.00
Gas ($ per Mcf) $2.04 $2.03 $1.62 $2.70 $3.68 $2.39
(1) The present value of estimated future net revenues attributable to the
Company's reserves was prepared using constant prices as of the
calculation date, discounted at 10% per annum on a pre-tax basis. 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 and
the Paradox Basin during the period indicated. This table does not include costs
incurred in other areas in the United States or in Australia.
FISCAL YEARS SIX MONTHS FISCAL YEAR
ENDED TO ENDED
JUNE 30 DECEMBER 31 DECEMBER 31
------- ----------- -----------
1994 1995 1996 1996 1997
---- ---- ---- ---- ----
Acquisition costs $ 2,717 $ 2,422 $ 7,577 $ 44 $ 8,437
Exploration costs 10,170 18,279 53,974 46,147 115,523
Development costs 2,968 10,148 15,345 6,966 31,327
------ ------ ------ ------ -------
Total costs incurred $15,855 $30,849 $76,896 $53,157 $155,287
------ ------ ------ ------ -------
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Productive well and acreage data. The following table sets forth
certain statistics for the Company regarding the number of productive wells and
developed and undeveloped acreage in the Gulf of Mexico as of December 31, 1997.
GROSS NET
----- ---
Productive wells (1):
Oil (2) 16 16.0
Gas (3) 30 28.7
------ ------
Total 46 44.7
====== ======
Developed Acreage (1) 46,654 43,804
Undeveloped Acreage (1) (4) 64,680 64,680
------ ------
Total 111,334 108,484
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(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 interest in gross acres equals one. The number of net acres is
the sum of the fractional interests owned in gross acres expressed as whole
numbers and fractions thereof.
(2) Two gross oil wells each have dual completions.
(3) Nine gross gas wells each have dual completions.
(4) Leases covering 15% of the Company's undeveloped acreage will expire in
1998, 8% in 1999, 23% in 2000, 37% in 2001, and 17% in 2002.
Drilling activity. The following table sets forth the Company's
drilling activity for the periods indicated.
Fiscal years ended Six months to Fiscal year ended
June 30 December 31 December 31
------- ----------- -----------
1994 1995 1996 1996 1997
---- ---- ---- ---- ----
Gross Net Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- --- ----- ---
Gulf of Mexico
Exploratory wells 2 2 3 3 4 4 1 1 13 13
Development wells 0 0 1 1 4 4 3 3 4 4
Dry holes 0 0 0 0 0 0 0 0 3 2.4
Other USA
Exploratory wells 0 0 0 0 0 0 0 0 0 0
Development wells 0 0 0 0 0 0 0 0 0 0
Dry holes 6 2.3 0 0 0 0 0 0 0 0
Australia
Exploratory wells 0 0 0 0 0 0 0 0 0 0
Development wells 2 0.6 0 0 0 0 0 0 0 0
Dry holes 3 1.5 0 0 0 0 0 0 0 0
--- --- --- --- --- --- --- --- --- ---
Total 13 6.4 4 4 8 8 4 4 20 19.4
--- --- --- --- --- --- --- --- --- ---
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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 "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Hedging
Transactions."
Despite the measures taken by the Company to attempt to control price
risk, the Company remains subject to price fluctuations for oil and natural gas
sold in the spot market due primarily to seasonality of demand and other factors
beyond the Company's control. Domestic oil prices generally follow worldwide oil
prices, which are subject to price fluctuations resulting from changes in world
supply and demand. The Company continues to evaluate the potential for reducing
these risks, and expects to enter into additional hedge transactions in future
years. In addition, the Company also may close out any portion of the existing,
or yet to be entered into, hedges as determined to be appropriate by management.
PRODUCTION SALES CONTRACTS
The Company markets all of the oil and gas production from its
properties. All of the Company's crude oil and gas production is sold to a
variety of purchasers under short-term (less than twelve months) contracts or
thirty-day spot purchase contracts. Natural gas and crude oil sales contracts
are based upon field posted prices plus negotiated bonuses. During fiscal 1997,
Duke Energy Trading & Market Services, L.L.C. (formerly Pan Energy Trading &
Marketing Services L.L.C.), P G & E Energy Trading Corporation and Natural Gas
Clearinghouse each purchased in excess of 10% of the gas sold by the Company and
Vision Resources, Inc. purchased in excess of 10% of the oil sold by the
Company. Based upon current demand for oil and gas, the Company does not believe
the loss of any of these purchasers would have a material adverse effect on the
Company.
Most of the Company's oil and all of the Company's gas is transported
through gathering systems and pipelines that are not owned by the Company.
Transportation space on such gathering systems and pipelines is occasionally
limited, and at times unavailable, due to repairs or improvements being made to
such facilities or due to such space being utilized by other oil or gas shippers
with priority transportation agreements. While the Company has not experienced
any inability to market its natural gas and oil, if transportation space is
restricted or unavailable, the Company's cash flow could be adversely impacted.
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 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
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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.
The Company has operations located on federal oil and gas leases, which
are administered by the MMS. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency (the "EPA")), lessees must
obtain a permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering and construction specifications. The MMS
proposed additional safety-related regulations concerning the design and
operating procedures for OCS production platforms and pipelines. These proposed
regulations were withdrawn pending further discussions among interested federal
agencies. The MMS also has regulations restricting the flaring or venting of
natural gas, liquid hydrocarbons and oil without prior authorization. Similarly,
the MMS has promulgated other regulations governing the plugging and abandonment
of wells located offshore and the removal of all production facilities. To cover
the various obligations of lessees on the OCS, the MMS generally requires that
lessees post substantial bonds or other acceptable assurances that such
obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases. Under certain circumstances, the MMS may require Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations.
The MMS issued a notice of proposed rulemaking in which it proposed to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. The proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on posted prices and assign a value to crude
oil that better reflects market value, establish a new MMS form for collecting
value differential data, and amend the valuation procedure for the sale of the
federal royalty oil. The Company cannot predict at this stage of the rulemaking
proceeding how is might be affected by this amendment to the MMS' regulations.
In April 1997, after two years of study, the MMS withdrew proposed
changes to the way it values natural gas for royalty payments. These proposed
changes would have established an alternative market-based method to calculate
royalties on certain natural gas sold to affiliates or pursuant to non-arm's
length sales contracts.
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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. The FERC has issued final orders in virtually all pipeline
restructuring proceedings, and has now completed a series of one year reviews to
determine whether refinements are required regarding individual pipeline
implementations of Order No. 636.
Although Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. The United States Court of Appeals for the District of
Columbia Circuit (the "Court") recently issued its decision in the appeals of
Order No. 636. The Court largely upheld the basic tenets of Order No. 636,
including the requirements that interstate pipelines "unbundle" their sales of
gas from transportation and that pipelines provide open-access transportation on
a basis that is equal for all gas suppliers. The Court remanded several
relatively narrow issues for further explanation by the FERC. In doing so, the
Court made it clear that the FERC's existing rules on the remanded issues would
remain in effect pending further consideration. The Company believes that the
issues remanded for further action do not appear to materially affect it. The
United States Supreme Court has decided not to review the Court's decision
regarding Order No. 636. In February 1997, the FERC issued Order No. 636-C, its
order on remand from the Court. Order 636-C is currently pending on rehearing
before the FERC. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violations of those
tolerances. The Company does not believe, however, that it will be affected by
an action taken with respect to Order No. 636 materially differently than other
natural gas producers and marketers with which it competes.
The FERC has issued a statement of policy and a request for comments
concerning alternatives to its traditional cost-of-service ratemaking
methodology. This policy statement articulates the criteria that the FERC will
use to evaluate proposals to change market-based rates for the transportation of
natural gas. The policy statement also provides that the FERC will consider
proposals for negotiated rates for individual shippers of natural gas, so long
as a cost-of-service-based rate is available as a recourse rate. The FERC also
has requested comments on whether it should allow gas pipelines the flexibility
to negotiate the terms and conditions of transportation service with prospective
shippers. The Company cannot predict what further action the FERC will take on
these matters, however, the Company does not believe that it will be affected by
any action taken materially differently than other natural gas producers and
marketers with which it competes.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market. While any resulting FERC action would affect
the Company only indirectly, the FERC's current rules and policies may have the
effect of enhancing competition in natural gas markets by, among other things,
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encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.
The FERC has issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While the FERC's
policy statement on new construction cost recovery affects the Company only
indirectly, in its present form, the new policy should enhance competition in
natural gas markets and facilitate construction of gas supply laterals. The FERC
has denied requests for rehearing of this policy statement. The FERC has issued
numerous orders approving the spin-down or spin-off by interstate pipelines of
their gathering facilities. A "spin-off" is a FERC-approved sale of gathering
facilities to a non-affiliate. A "spin-down" is a transfer of gathering
facilities to an affiliate. These approvals were given despite the strong
protests of a number of producers concerned that any diminution in FERC's
oversight of interstate pipeline-related gathering services might result in 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.
Commencing in October 1993, the FERC issued a series of rules (Order
Nos. 561 and 561-A) establishing an indexing system under which oil pipelines
will be able to change their transportation rates, subject to prescribed ceiling
levels. The indexing system, which allows or may require pipelines to make rate
changes to track changes in the Producer Price Index for Finished Goods, minus
one percent, became effective January 1, 1995. The FERC's decision in this
matter was recently affirmed by the Court. The Company is not able at this time
to predict the effects of Order Nos. 561 and 561-A, if any, on the
transportation costs associated with oil production from the Company's oil
producing operations.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company does not anticipate that compliance
with existing federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon the capital expenditures, earnings
or competitive position of the Company.
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.
The Company generates wastes, including hazardous wastes, that are
subject to the federal Resource Conservation and Recover 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
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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 Company believes that it currently has established adequate proof
of financial responsibility for its offshore facilities at no significant
increase in expense over recent prior years. However, the Company cannot predict
whether these financial responsibility requirements under the OPA amendments or
proposed rule will result in the imposition of substantial additional annual
costs to the Company in the future or otherwise materially adversely affect the
Company. The impact, however, should not be any more adverse to the Company than
it will be to other similarly situated or less capitalized owners or operators
in the Gulf of Mexico. OPA also imposes other requirements on facility
operators, such as the preparation of an oil spill contingency plan. The Company
has such plans in place. The failure to comply with ongoing requirements or
inadequate cooperation in a spill event may subject a responsible party to civil
or even criminal liability.
OPERATING HAZARDS AND INSURANCE
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled as a result
of title problems, weather conditions, compliance with governmental
requirements, mechanical difficulties or shortages or delays in the delivery of
equipment and that the availability or capacity of gathering systems, pipelines
or processing facilities may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
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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 and its subsidiaries carry
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 65 full-time staff, primarily professionals,
including geologists, geophysicists and engineers. 53 of the staff are in
Lafayette, Louisiana, USA and 12 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 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, increases
in oil and gas production, the number of anticipated wells to be drilled in 1998
and thereafter, the Company's financial position, business strategy and other
plans and objectives for future 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, 1997, the Company's long-term debt was $99.6 million
of senior subordinated notes maturing on 15 June 2007. In addition the Company
had $50 million undrawn under the Company's committed bank credit facility.
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."
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UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES
This Annual Report contains estimates of the Company's proved oil and
gas reserves and the estimated future net revenues therefrom based upon the
Ryder Scott reports that rely upon various assumptions, including assumptions
required by the Commission as to oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The process of
estimating oil and gas reserves is complex, requiring significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data for each reservoir. As a result, such estimates are inherently
imprecise. Actual future production, oil and gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves may vary substantially from those estimated in the Ryder Scott
reports. Any significant variance in these assumptions could materially affect
the estimated quantity and value of reserves set forth in this Annual Report. In
addition, the Company's proved reserves may be subject to downward or upward
revision based upon production history, results of future exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond the Company's control. Actual production, revenues, taxes, development
expenditures and operating expenses with respect to the Company's reserves will
likely vary from the estimates used, and such variances may be material.
Approximately 25% of the Company's total proved reserves at December
31, 1997 were undeveloped, which are by their nature less certain. Recovery of
such reserves will require significant capital expenditures and successful
drilling operations. The reserve data set forth in the Ryder Scott report
assumes that substantial capital expenditures by the Company will be required to
develop such reserves. Although cost and reserve estimates attributable to the
Company's oil and gas reserves have been prepared in accordance with industry
standards, no assurance can be given that the estimated costs are accurate, that
development will occur as scheduled or that the results will be as estimated.
See "Item 1 - 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. Management believes that the Company will
have sufficient cash provided by
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operating activities and borrowings under the Bank credit facility to fund
future capital expenditures. However, if revenues or cash flows from operations
decrease as a result of lower oil and natural gas prices or operating
shortfalls or 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."
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."
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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."
RISKS OF HEDGING TRANSACTIONS
In order to manage its exposure to price risks in the marketing of its
oil and natural gas, the Company has in the past and expects to continue to
enter into oil and natural gas price hedging arrangements with respect to a
portion of its expected production. These arrangements may include futures
contracts on the New York Mercantile Exchange (NYMEX), fixed price delivery
contracts and financial swaps. While intended to reduce the effects of
volatility of the price of oil and natural gas, such transactions may limit
potential gains by the Company if oil and natural gas prices were to rise
substantially over the price established by the hedge. In addition, such
transactions may expose the Company to the risk of financial loss in certain
circumstances, including instances in which (i) production is less than
expected, (ii) if there is a widening of price differentials between delivery
points for the Company's production and the delivery point assumed in the hedge
arrangement, (iii) the counterparties to the Company's future contracts fail to
perform the contract or (iv) a sudden, unexpected event materially impacts oil
or natural gas prices. See "Item 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.
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 OCS lease sales. At December 31, 1997 the Company had 34 lease blocks
in the Gulf of Mexico. All of the Company's proved oil and gas reserves at
December 31, 1997 were in these blocks.
ITEM 2 (B) - RESERVES
The information on the Company's oil and gas reserves is set out under
Item 1 on page 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
March 13, 1998 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 107,601,041 Ordinary Shares outstanding on March 13,
1998.
NUMBER OF
NAME ORDINARY SHARES PERCENTAGE BENEFICIALLY OWNED
- ---- --------------- -----------------------------
All Directors and executives as a group
(12 persons) (1) (2) (3) (4) 30,385,539 28.2%
Terrence N. Fern (2) (4) 28,386,498 26.4%
Adrian J. Fletcher (3) (4) 25,042,523 23.3%
Den Duyts Corporation Pty Limited (4) 18,344,639 17.1%
(1) Includes Ordinary Shares held by family-controlled entities or
companies associated with such individuals. Also includes Ordinary
Shares reflected for Adrian J. Fletcher, Chairman of the Company, and
Terrence N. Fern, Managing Director of the Company. See Notes (2), (3)
and (4) 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 director 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
director and a shareholder; 18,344,639 Ordinary Shares held by 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 4,000 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 (4) below.
(3) Includes 127,223 Ordinary Shares held by a trust and superannuation
fund, of which Mr. Fletcher is a director and shareholder of the
corporate trustee and the beneficiaries of which include Mr. Fletcher's
family; 100,000 Ordinary Shares held by Mr Fletcher pursuant to the
Company's Employee Share Plan; 6,470,661 Ordinary Shares held by a
trust of which Mr. Fletcher is a director and shareholder of the
corporate trustee; and the 18,344,639 Ordinary Shares held by a trust,
the trustee of which is Den Duyts. Excludes 12,000 Ordinary Shares held
by his three children, of which he disclaims that he is the Beneficial
Owner. See Note (4) below.
(4) 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. Because Mr.
Fletcher currently serves as one of two directors of Den Duyts, he also
is deemed to be the Beneficial Owner of such Ordinary 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 March 13, 1998 were 28,613,721
Ordinary Shares and the "relevant" interests of Mr. Fern and Mr.
Fletcher were 28,386,498 Ordinary Shares and 28,613,721 Ordinary
Shares, respectively.
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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).
As at March 13, 1998 the Company represented 2.98% of the Energy Index of the
ASX. The Company's symbol on the ASX is "PSA".
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. 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"). The Company's symbol on the Nasdaq National Market is "PSALY".
As at March 13, 1998 4,905,251 ADRs were on issue. These were
equivalent to 24,526,255 Ordinary Shares or approximately 23% 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.
A$ US$
---------------- ---------------
High Low High Low
---- --- ---- ---
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 to March 13, 1998 4.91 4.07 3.28 2.67
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The following table sets forth for the periods indicated the high and
low closing prices per ADR on the Nasdaq National Market in US dollars:
US$
---
High Low
---- ---
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 to March 13, 1998 16.50 13.50
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 that 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.
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.
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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.
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
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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.
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 each of the four fiscal years ended
June 30, 1996, the six months ended December 31, 1996 and the fiscal year ended
December 31, 1997 is derived from the Company's US Dollar Financial Statements,
which were prepared under Australian GAAP and contain reconciliation to, and
presentation under, US GAAP. The following data should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements and notes thereto included under Item
18.
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Six months to Fiscal year
Fiscal years ended June 30 December 31 ended
-------------------------- ----------- December 31
-----------
1993 1994 1995 1996 1996 1997
---- ---- ---- ---- ---- ----
(In thousands, except per share data)
INCOME STATEMENT DATA:
Oil and gas sales (net of royalties) $ 10,174 $ 13,919 $ 17,031 $ 51,150 $ 37,521 $ 125,139
--------- --------- --------- --------- --------- ---------
Lease operating expenses 3,051 3,714 3,808 6,892 3,279 11,527
Depletion, depreciation and amortization 2,586 4,736 5,661 21,098 15,368 63,903
Exploration expenditure (including dry
hole costs) 2,886 2,921 2,697 3,320 5,249 17,782
General, administrative and other expenses 2,167 2,558 4,543 7,001 3,339 9,001
Stock compensation expense - - 102 1,749 677 1,461
--------- --------- --------- --------- --------- ---------
Total operating expenses 10,690 13,929 16,811 40,060 27,912 103,674
--------- --------- --------- --------- --------- ---------
Income (loss) from operations (516) (10) 220 11,090 9,609 21,465
Other income (expense) (61) 117 52 223 - 132
Profit (loss) on sale of assets (6) (14) 4,296 257 7,208 31
Interest expense (398) (745) (1,725) (3,687) (1,472) (6,022)
Interest income 212 115 210 485 822 1,685
Equity in income (loss) of affiliates 620 709 (3,864) 282 (1,326) (1,595)
--------- --------- --------- --------- --------- ---------
Income (loss) before tax (149) 172 (811) 8,650 14,841 15,696
Income tax benefit (expense) (264) 138 465 (895) (3,888) (5,416)
--------- --------- --------- --------- --------- ---------
Net income (loss) $ (413) $ 310 $ (346) $ 7,755 $ 10,953 10,280
--------- --------- --------- --------- --------- ---------
BASIC AND DILUTED EARNINGS PER SHARE:
Earnings (loss) per ordinary share $ (0.01) $ 0.00 $ (0.01) $ 0.09 $ 0.10 $ 0.10
Earnings (loss) per ADR (1) $ (0.03) $ 0.02 $ (0.02) $ 0.45 $ 0.52 $ 0.48
Weighted average number of ordinary
shares outstanding 74,626 74,773 75,874 86,297 104,977 107,320
CASH FLOW DATA:
Net cash provided by operating activities $ 5,345 $ 6,676 $ 9,572 $ 38,601 $ 26,454 $ 93,436
Net cash used in investing activities (11,959) (15,724) (24,559) (73,228) (33,227) (148,420)
Net cash provided by financing activities 6,563 7,891 15,291 37,734 15,760 61,512
BALANCE SHEET DATA:
Total assets $ 30,040 $ 43,338 $ 63,857 $ 125,690 $ 161,083 $ 247,962
Long-term debt, less current maturities 8,546 8,700 14,900 52,000 37,000 99,630
Shareholders' equity 17,604 19,967 20,904 47,479 91,401 101,155
(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)
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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.
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:
US Dollar Per Australian Dollar
------------------------------------------
Period Average* High Low End of Period
- ------ -------- ---- --- -------------
Year ended June 30, 1993 0.6980 0.7481 0.6655 0.6663
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
January 1, 1998 through March 13, 1998 0.6666 0.6868 0.6347 0.6760
* 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.
ITEM 9 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in the understanding of
the Company's financial position for the two fiscal years ended June 30, 1996,
the six month period ended December 31, 1996 and the fiscal year ended December
31, 1997. The US dollar Financial Statements for these periods are set out under
Item 18 and should also be referred to in conjunction with the following
discussion. In particular, Note 29 to the US dollar Financial Statements shows
the statements of operations, balance sheets and statements of cash flows
prepared under US GAAP, even though the Company is Australian and prepares its
primary financial statements under Australian GAAP. The amounts discussed below
are in US dollars and are under US GAAP, except where stated otherwise.
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 accounts for its oil and gas operations under the
successful efforts method of accounting.
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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 following table sets forth certain operating information with
respect to the oil and gas operations of the Company.
Fiscal years ended Six months to Years ended
June 30 December 31 December 31
------- ----------- -----------
1995 1996 1995 1996 1996 1997
---- ---- ---- ---- ---- ----
NET PRODUCTION:
Oil (MBbls) 612 1,680 670 1,145 2,155 3,078
Gas (MMcf) 3,556 11,529 5,881 6,074 11,722 27,940
Total (MMcfe) 7,228 21,609 9,901 12,944 24,652 46,408
NET SALES DATA (IN THOUSANDS):
Oil $10,157 $29,937 $10,674 $24,904 $44,168 $60,369
Gas 6,874 21,213 10,773 12,617 23,056 64,770
------- ------- ------- ------- ------- -------
Total 17,031 51,150 21,447 37,521 67,224 125,139
------- ------- ------- ------- ------- -------
AVERAGE SALES PRICES (1):
Oil (per Bbl) $16.60 $17.82 $ 15.93 $ 21.75 $ 20.50 $ 19.61
Gas (per Mcf) 1.93 1.84 1.83 2.08 1.97 2.32
Total (per Mcfe) 2.36 2.37 2.17 2.90 2.73 2.70
AVERAGE COSTS (PER MCFE):
Lease operating expenses $0.53 $0.32 $ 0.36 $ 0.25 $ 0.26 $0.25
Depletion, depreciation and amortization 0.78 0.98 0.72 1.19 1.20 1.38
General, administrative and other expenses 0.63 0.32 0.31 0.26 0.29 0.19
(1) Includes results of hedging activities.
RESULTS OF OPERATIONS
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
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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 and impairment costs
and $7.3 million for seismic, geological and geophysical expenditures were
expensed as incurred in 1997. There were no dry hole and impairment costs in
1996 while seismic, geological and geophysical expenditures in 1996 totaled $7.1
million.
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
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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.
FISCAL 1996 COMPARED TO FISCAL 1995
General. As a result of a full twelve months of production at West
Cameron 543/544, the successful completion of two additional wells and the
setting of a larger production facility at Ship Shoal 193, the Company's net
production increased 199% in fiscal 1996 compared to fiscal 1995.
Net oil and gas revenues. Net oil and gas revenues for fiscal 1996
increased by $34.1 million (200%) to $51.2 million, compared with fiscal 1995.
Net production increased by 14.4 Bcfe (199%) from 7.2 Bcfe for fiscal 1995 to
21.6 Bcfe for fiscal 1996. The average sales price for oil increased by 7% while
gas prices decreased by 5%.
For fiscal 1996 gas hedging activities resulted in an average realized
price of $1.84 per Mcf, or 14% below the $2.15 per Mcf price that would
otherwise have been received. Over the same period, oil price hedging resulted
in an average realized price of $17.82 per Bbl, or 2% below the $18.16 per Bbl
price that would otherwise have been received. Hedging activities resulted in a
$4.2 million decrease in oil and gas revenues. For fiscal 1995 gas hedging
activities resulted in an average realized price of $1.93 per Mcf, or 23% above
the $1.57 per Mcf that would otherwise have been received. The Company did not
enter into any oil hedging activities in fiscal 1995.
Lease operating expenses. Lease operating expenses increased by $3.1
million (81%) to $6.9 million for fiscal 1996, compared to fiscal 1995. The
increase was primarily due to costs associated with increased production from
West Cameron 543/544 and Ship Shoal 193. Lease operating expenses per Mcfe
decreased $0.21 for the fiscal 1996 as compared to fiscal 1995, continuing the
trend of previous years reflecting economies of scale from higher rates of
production. The oil and gas industry generally experiences higher operating
expenses for oil production as compared to gas production. With oil representing
more than 40% of the Company's net production for fiscal 1996, the Company's
operating expenses per Mcfe may be higher than those of other energy companies
with lower proportions of oil production.
Depletion, depreciation and amortization ("DD&A"). DD&A expense for
fiscal 1996 increased to $21.1 million (273%) from $5.7 million, compared to
fiscal 1995. The increase was principally attributable to the increase in oil
and gas production in the 1996 period. The depletion rate per unit of $0.98 per
Mcfe for fiscal 1996 increased from $0.78 per Mcfe for fiscal 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 $3.3 million of seismic, geological and
geophysical expenditures were expensed as incurred during fiscal 1996. This was
an increase of $0.6 million, or 22%, over the expenditure of $2.7 million in
1995, reflecting the Company's increasing exploration activity.
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. These operations contributed sales revenue of
$1.1 million in fiscal 1995. The interests were sold for $5.5 million, effective
January 1, 1995, generating a pre-tax profit for the Company of $4.3 million.
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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 1995 and $0.5
million in fiscal 1996. The Company sold these Australian interests for
approximately $0.3 million on June 24, 1996.
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
and $9.0 million in fiscal 1997.
The increases in general and administrative costs, mainly due to
increased expenditure in its Lafayette office, have been lower than the
increases in production. The Company has controlled its increases in general and
adminstrative costs and has achieved the economies of scale. In fiscal 1997
general and administrative costs, excluding stock compensation expenses, were
$0.19 per Mcfe, while 18 months previously, in fiscal 1995, they were $0.63 per
Mcfe.
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 sale of assets in fiscal 1997.
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. Details of the
interest rates are set out in Note 17 of the US Dollar Financial Statements.
Equity investments. The equity-accounted income and loss now relates
only to the Company's 44% holding in Climax. In the fiscal 1997, Climax's
principal activity was the continuation 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 loss before tax of $1.6 million recognized in fiscal 1997 by the
Company from its investment in Climax mainly reflected expensing the costs of
the Didipio study and other exploration, offset by the income from Climax's cash
deposits.
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, an evaluation of different mining
plans (open pit, underground, etc.), metallurgical testwork, ore processing
studies and environmental studies. Pre-development work is continuing, with the
most likely mining method being block-caving.
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.
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
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carrying value is nil. No equity income from the Company's investment in Climax
will be recognised until all unrecognized equity losses of Climax are recouped.
Tax matters. In fiscal 1997, the six months to December 31, 1996 and in
fiscal 1996 the Company brought to account $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 Company's accumulated losses in the United States (which were
recovered during fiscal 1995), the tax on the profit upon the sale of the
Company's interest in the Didipio project and the fact that the Company's
equity-accounted share of its expenditure at Didipio in the Philippines had not
been tax effected.
Net operating losses and other carryforwards. For US federal income tax
purposes, at December 31, 1997 the Company had net operating losses ("NOLs") of
approximately $45.3 million. In addition, at December 31, 1997 the Company had
an interest expense carryover of $1.4 million. The United States Internal
Revenue Code of 1986, as amended, permits a corporation to carryback NOLs from
the year in which they are incurred to the immediately preceding three years and
then carry forward any unused portion of the NOLs up to 15 years. The Company's
NOLs accumulated through 1996 will expire principally in 2005 through 2012.
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, the Company received net proceeds of $18.4
million from an Australian offering of 8.3 million Ordinary Shares in September
1995. In July 1996 the Company made a 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. $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.
The Company anticipates spending in the order of $160 million on
exploration and development drilling and other capital projects in the twelve
month period to December 31, 1998. This amount may be increased or decreased
based on actual drilling results. The Company currently intends to finance these
expenditures principally with cash flow from operations, bank borrowings and
its cash resources. See "Item 1 - Description of Business - Substantial
Leverage - Substantial Capital Requirements."
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 $93.4 million in fiscal 1997. Net cash used in investing activities for the
fiscal 1997 was $148.4 million, which almost entirely represented 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 milllion) 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,
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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.
As a result of the Company's rapid expansion and growth, the Company
has historically experienced working capital deficits. 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.
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 credit agreement with Chase Manhattan
Bank NA ("the Credit Agreement"), under which the borrowing base at December 31,
1997 was $60 million, with a sub-limit of $15 million for letter of credit
purposes to support the bonding requirements of the MMS and commodity swap
transactions. At December 31, 1997, there were no borrowings outstanding under
the Credit Agreement. The Credit Agreement is a two-year revolving credit
facility followed by a two-year term period with equal quarterly amortization
payments and the facility matures in April 2001. The Credit Agreement 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 2.75
to 1.0 and a coverage ratio of earnings before interest, taxes and depletion,
depreciation and amortization to total interest of not less than 3.0 to 1.0. PEI
is currently in compliance with all financial covenants under the Credit
Agreement. Outstanding borrowings currently accrue interest at the rate of LIBOR
plus a margin of 1.25% to 1.50% per annum, depending upon the total amount
borrowed. PEI also pays a fee equal to 0.3% to 0.35% per annum of the unused
portion of the borrowing base under the facility depending upon the utilization
of the facility.
The Company's ability to borrow under the Credit Agreement is dependent
upon the reserve value of its oil and gas properties, as determined by Chase. If
the reserve value of the Company's borrowing base declines, the amount available
to the Company under the Credit Agreement will be reduced and, to the extent
that the borrowing base is less than the amount then outstanding (including
letters of credit) under the Credit Agreement, the Company will be obligated to
repay such excess amount upon ninety days' notice from Chase or to provide
additional collateral.
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.
On June 13, 1997 PEI, a wholly owned subsidiary, issued $100 million of
9.5% senior subordinated notes due June 15, 2007 under a Rule 144A offering. A
portion of the proceeds was used to repay its then outstanding borrowings under
the Credit Agreement ($58 million) and the borrowing base under the Credit
Agreement was simultaneously reduced to $50 million. This has since been
increased to $60 million.
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 Petsec. Later in
1997 PEI completed a registered exchange offer pursuant to which the holders of
the notes to exchanged the notes for new notes which are identical in all
material respects but which can be offered and sold by holders without
restrictions or limitations under the Securities Act.
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
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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 the
Company.)
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, amongst 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 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. All of
the Company's hedging transactions to date have been carried out with large
banks and some of the Company's obligations have been secured by letters of
credit. 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.
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 operation 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.
The Company is aware of the issues associated with the programming code in
existing computer systems as the year 2000 approaches. The Company is utilizing
both internal and external resources to identify, correct or reprogram, and test
the systems for the year 2000 compliance. It is anticipated that all
reprogramming efforts will be complete by December 31, 1998, allowing adequate
time for testing. To date, confirmations have been received from the Company's
primary processing vendors that plans are being developed to address processing
of transactions in the year 2000. Management has not yet assessed the year 2000
compliance expense and related potential effect on the Company's financial
position, results of operations or liquidity.
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ITEM 9A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not applicable for the year ended December 31, 1997.
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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.
NAME AGE POSITION *
Directors:
Terrence N. Fern ...... 50 Managing Director and Chief Executive Officer
Adrian J. Fletcher .... 54 Chairman
R. Bruce Corlett ...... 53 Director
David A. Mortimer ..... 53 Director
Executives:
Douglas G. Battersby... 55 Technical Director - Oil and Gas
Maynard V. Smith ...... 47 General Manager - Exploration and Production
Robin A. Cumming ...... 53 Chief Financial Officer
Howard H. Wilson, Jr... 39 Vice President - Operations*
Mark A. Gannaway ...... 42 Exploration Manager*
Prent H. Kallenberger.. 43 Geophysical Manager*
Ross A. Keogh ......... 38 Financial Controller and Treasurer*
James E Slatten III ... 39 Manager - Land and Legal*
* Messrs. Fern, Fletcher 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, Gannaway, Kallenberger, Keogh and
Slatten are positions held with the Company's wholly-owned subsidiary,
Petsec Energy Inc.
The following biographies describe the business experience of the
directors and executives of the Company and Petsec Energy Inc and the expiration
dates of the directors' terms.
TERRENCE N. FERN has over 25 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.
ADRIAN J. FLETCHER has wide international experience in banking,
natural resources and manufacturing. He has also been involved in a number of
major advisory roles. He was Chief Financial Officer of Westpac Banking
Corporation in the mid-eighties, and later established its successful Global
Financial Markets Group from London. Mr Fletcher has had an ongoing interest in
the development and implementation of leadership and governance practices and
for three years directed the business policy course for the MBA program at The
University of New South Wales. He holds degrees in physics and engineering from
Imperial College, London. Mr Fletcher is also Chairman of Climax Mining Ltd.
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 non-executive director of a
number of public companies including Australian Food & Fibre Limited, Adsteam
Marine Limited, The Australian Maritime Safety Authority (Chairman), 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.
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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
Ascham Foundation Limited, Ascham School Limited, Australian Graduate School of
Management at The University of New South Wales, Ci Technologies Group Limited,
F.H. Faulding & Co Limited, GIO Australia Holdings Limited and Leighton Holdings
Limited. Mr Mortimer holds a Bachelor of Economics degree from The University of
Sydney.
DOUGLAS G. BATTERSBY has served as the Technical Director - Oil and Gas
of the Company since 1990. Mr Battersby has over 30 years of experience in oil
and gas exploration and production serving in various senior technical and
executive positions with Exxon, Inc., Hartogen Energy Limited and Delhi Oil
Company in Australia, Southeast Asia and the United States. Mr Battersby holds a
Master of Science degree in Petroleum Geochemistry from The University of
Melbourne.
MAYNARD V. SMITH has served as General Manager - Exploration and
Production since 1990. Mr Smith has over 20 years of oil and gas exploration
experience and has served in various technical and executive positions with Gulf
Oil Corporation, Tenneco Oil Company, Natomas Oil Company, and Barcoo Petroleum
Company in the United States, Australia and Southeast Asia. Mr Smith holds a
Bachelor of Science degree in Geology from the California State University at
San Diego.
ROBIN A. CUMMING has served as Chief Financial Officer of the Company
since early 1994. He has had 25 years of experience in senior financial and
treasury roles in a range of industries and has worked in Australia, the United
Kingdom and the United States. Prior to joining the Company he held positions
with Telstra Corporation Limited, Elders Finance Group Limited, James Hardie
Industries Limited and Coopers & Lybrand. Mr Cumming is also Chief Financial
Officer of Climax. He holds a masters degree in engineering from Cambridge
University, England, and a Masters degree in Business Administration from the
Wharton School at the University of Pennsylvania. He is a fellow of the
Chartered Institute of Management Accountants in the United Kingdom.
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.
MARK A. GANNAWAY is the Exploration Manager of Petsec Energy Inc. Mr
Gannaway joined Petsec Energy in July 1991. Between 1979 and 1988, Mr Gannaway
worked for Tenneco Oil Company in various technical and supervisory positions
and his career with Tenneco involved working in the Midcontinent and Eastern
Gulf of Mexico regions. From 1988 to 1990 Mr Gannaway was a geologic consultant
in Lafayette, Louisiana. Mr Gannaway holds a Bachelor of Science degree in
Geological Engineering from the University of Oklahoma.
PRENT H. KALLENBERGER is the Geophysical Manager of Petsec Energy Inc.
He joined Petsec Energy in September 1992. Between 1982 and 1992, Mr
Kallenberger worked in various technical and supervisory positions with Tenneco
Oil Company, Union Pacific Resources, Inc., and Unocal Corporation in California
and Texas. Mr Kallenberger holds a Bachelor of Science degree in Geology from
Boise State University and a Master of Science degree in Geophysics from the
Colorado School of Mines.
ROSS A. KEOGH has served as Financial Controller and Treasurer of
Petsec Energy Inc since 1990 and has 15 years experience in the oil and gas
industry. Between 1979 and 1989, Mr Keogh worked in the financial accounting and
budgeting divisions of Total Oil Company and as Joint Venture Administrator for
Bridge Oil Limited in Australia. Mr Keogh is also the Financial Controller -
International of Climax. Mr Keogh Holds a Bachelor of Economics degree, with a
major in Accounting, from Macquarie University in Sydney.
JAMES E SLATTEN III was appointed as Manager - Land and Legal in
January 1998. He has over 14 years experience in corporate and energy law. Prior
to joining the Company he was a partner in the Louisiana law firm of Gordon,
Arata, McCollam & Duplantis. Mr Slatten holds a 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.
36
37
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 1997 was $137,000. The total compensation
received by the seven highest compensated executive officers of the Company and
its controlled and related companies for fiscal 1997 was $1,410,000. In
addition, the Company made payments in the fiscal 1997 of $290,000 to a company
controlled by Mr Fern's family and which provides management services to the
Company, of $274,000 to a company controlled by Mr Smith's family and which
provides management and geological services to the Company, and of $18,000 to a
company associated with Mr Fletcher and which provides management consulting
services to the Company. Three executives, Messrs Gannaway, Kallenberger and
Smith, 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 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, Fletcher 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 350,000 Ordinary Shares to a company
controlled by Mr Smith's family: these are at an exercise price of A$7.00 per
Ordinary Share and expire in July 2001.
Certain officers and directors of the Company own 2,758,800 ordinary
shares of Climax, representing less than 3% of the outstanding capital of
Climax. In addition, Mr Fletcher serves as Chairman of Climax, Mr Fern serves as
Managing Director of Climax, Mr Cumming serves as Chief Financial Officer of
Climax and Mr Keogh serves as Financial Controller - International 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 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 March 13, 1998, all employees and
directors of the Company, in the aggregate, owned 1,875,000 Ordinary Shares
subject to the terms of this Share Plan. As of March 13, 1998, 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, Mr Fletcher had a Company loan
of A$560,000 ($379,000) in connection with grants of 100,000 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 March 13, 1998 all directors and employees of the Company, in the
aggregate, held options to purchase an aggregate of 2,531,000 Ordinary Shares
pursuant to the Option Plan.
37
38
PART II
ITEM 14 - DESCRIPTION OF SECURITIES
Not applicable
PART III
ITEM 15 - DEFAULTS
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 Auditor's
Report are included on pages F-1 through F-36 of this Form 20-F.
ITEM 19 - FINANCIAL STATEMENTS AND EXHIBITS
(a) Financial Statements, including
. Statement of Operations for the three and a half year period
. ended December 31, 1997 Balance Sheets as of December 31, 1996
. and 1997 Statements of Cash Flows for the three and a half year
. period ended December 31, 1997 Notes to Financial Statements
. Independent Auditors' Report
(b) Exhibits
. Consent of KPMG
. Consent of Ryder Scott Company
38
39
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 filing
to be signed on its behalf by the undersigned, thereunto duly authorized.
By: /s/ Robin A Cumming
Chief Financial Officer
Petsec Energy Ltd
April 7, 1998
39
40
================================================================================
ACN 000 602 700
Petsec Energy Ltd
-----------------
US Dollar Financial Statements
Including US GAAP Statements on pages F-29 to F-32
31 December 1997
================================================================================
CONTENTS PAGES
- -------- -----
Financial statements under
Australian accounting F-2 - F-25
- -------------------------------------------------------------------------------
Differences between Australian
and US accounting F-26 - F-28
- -------------------------------------------------------------------------------
Financial statements under
US accounting F-29 - F-32
- -------------------------------------------------------------------------------
Additional disclosures under
US accounting F-32 - F-33
- -------------------------------------------------------------------------------
Supplementary oil and
gas disclosures F-33 - F-35
- -------------------------------------------------------------------------------
Independent Auditors' Report F-36
===============================================================================
F-1
41
================================================================================
Petsec Energy Ltd and its controlled entities
================================================================================
================================================================================
Profit and Loss Accounts
================================================================================
Twelve
Note Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands, except per share amounts)
- ------------------------------------------------------------------------------------------------------------------------
Oil and gas sales (before deducting royalties) $ 21,015 $ 64,614 $ 47,592 $ 155,338
Gold sales (before deducting royalties) 6,484 7,866 -- --
Other revenue 2 5,173 3,072 840 2,454
--------- --------- --------- ---------
Total revenue 32,672 75,552 48,432 157,792
Operating expenses 3 (32,604) (63,895) (36,919) (124,173)
--------- --------- --------- ---------
Operating profit before abnormal items and
income tax 68 11,657 11,513 33,619
Abnormal items before income tax 4 2,422 6,499 9,939 (10,453)
Operating profit before income tax 2,490 18,156 21,452 23,166
Income tax attributable to operating profit 7 (1,323) (6,030) (6,553) (7,762)
========= ========= ========= =========
Operating profit after income tax 1,167 12,126 14,899 15,404
Extraordinary item (no income tax effect) 5 -- (5,126) -- --
--------- --------- --------- ---------
Operating profit and extraordinary item after
income tax 1,167 7,000 14,899 15,404
Outside equity interests in operating (profit)
loss after income tax 26 1,289 (1,754) -- --
--------- --------- --------- ---------
Operating profit after income tax attributable
to members of the Company 2,456 5,246 14,899 15,404
Retained earnings (accumulated losses) at the
beginning of the financial period (577) 1,879 7,125 (17,497)
--------- --------- --------- ---------
Total available for appropriation 1,879 7,125 22,024 (2,093)
Adjustment to retained earnings upon the
buy-back of shares in the Company -- -- (39,521) --
--------- --------- --------- ---------
Retained earnings (accumulated losses) at the
end of the financial period $ 1,879 $ 7,125 $ (17,497) $ (2,093)
--------- --------- --------- ---------
Basic earnings per share 8 $ 0.03 $ 0.12 $ 0.14 $ 0.14
Basic and diluted earnings per share are not materially different.
The profit and loss accounts are to be read in conjunction with the notes to
these financial statements.
F-2
42
================================================================================
PETSEC ENERGY LTD AND ITS CONTROLLED ENTITIES
================================================================================
================================================================================
BALANCE SHEETS
================================================================================
Note 31 December 31 December
1996 1997
(US dollars, in thousands)
- -----------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash $ 12,528 $ 19,171
Receivables 9 12,200 14,525
Inventories 10 46 43
Investments 11 -- 195
--------- ---------
Total current assets 24,774 33,934
--------- ---------
NON-CURRENT ASSETS
Receivables 9 3,841 2,676
Investments 11 6,852 5,528
Property, plant and equipment 12 21,623 37,954
Exploration and development expenditure 13 121,358 185,606
Note issue costs 14 -- 3,000
Future income tax benefit 7(c) 22,276 22,656
--------- ---------
Total non-current assets 175,950 257,420
--------- ---------
Total assets 200,724 291,354
--------- ---------
CURRENT LIABILITIES
Creditors and accruals 15 24,593 27,762
Provisions 16 316 306
--------- ---------
Total current liabilities 24,909 28,068
--------- ---------
NON-CURRENT LIABILITIES
Borrowings 15 37,000 99,630
Deferred income tax provision 7(b) 31,603 43,103
Restoration and reclamation provision 1,542 3,149
--------- ---------
Total non-current liabilities 70,145 145,882
--------- ---------
Total liabilities 95,054 173,950
--------- ---------
Net assets 105,670 117,404
--------- ---------
SHAREHOLDERS' EQUITY
Share capital 18 16,345 16,491
Reserves 19 106,822 103,006
Retained earnings (accumulated losses) (17,497) (2,093)
--------- ---------
Total shareholders' equity $ 105,670 $ 117,404
--------- ---------
The balance sheets are to be read in conjunction with the notes to these
financial statements.
F-3
43
================================================================================
PETSEC ENERGY LTD AND ITS CONTROLLED ENTITIES
================================================================================
================================================================================
STATEMENTS OF CASH FLOWS
================================================================================
Twelve
Note Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands, except per share amounts)
- --------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Cash receipts in the course of operations $ 27,899 $ 68,235 $ 43,340 $ 153,794
Cash payments in the course of operations (22,555) (30,350) (14,369) (52,543)
Interest received 462 568 721 1,495
Interest paid (1,575) (3,704) (1,472) (6,022)
Income taxes paid -- (493) (306) (136)
--------- --------- --------- ---------
Net cash provided by operating activities 27 4,231 34,256 27,914 96,588
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Property rentals received 869 1,019 -- --
Dividends received 2 -- -- --
Proceeds from sale of:
- property, plant and equipment 40 3,666 6 60
- marketable equity securities held for trading 246 35 -- --
- investments 4 -- 9,780 --
- oil and gas property 5,686 229 11 --
Loans to related entities (755) (1,846) 3,923 1
Restricted deposit -- (1,501) 1,501 --
Changes in loans to related party -- 1,333 --
Payments for:
- property, plant and equipment (6,171) (7,764) (8,932) (29,403)
- investments (341) (11) (32) --
- exploration, development and permits (27,927) (66,476) (40,898) (122,098)
Decrease in cash from deconsolidation of
Climax Mining Ltd -- (499) -- --
--------- --------- --------- ---------
Net cash used in investing activities (28,347) (71,815) (34,641) (151,440)
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issue of shares (net of issue costs) 35 18,565 71,944 2,066
Share buy-back -- -- (41,184) --
Proceeds from borrowings - secured loans 14,165 27,846 7,000 21,000
Proceeds from note issue - unsecured (net of issue costs) -- -- -- 96,446
Repayment of borrowings - secured loans -- (6,498) (22,000) (58,000)
Borrowings - unsecured loans 391 (378) -- --
--------- --------- --------- ---------
Net cash provided by financing activities 14,591 39,535 15,760 61,512
--------- --------- --------- ---------
Net increase (decrease) in cash held (9,525) 1,976 9,033 6,660
Cash at the beginning of the financial period 10,744 1,339 3,541 12,528
Effects of exchange rate changes on the balances
of cash held in foreign currencies at the
beginning of the financial period 120 226 (46) (17)
--------- --------- --------- ---------
Cash at the end of the financial period 27 $ 1,339 $ 3,541 $ 12,528 $ 19,171
--------- --------- --------- ---------
The statements of cash flows are to be read in conjunction with the notes to
these financial statements.
F-4
44
================================================================================
PETSEC ENERGY LTD AND ITS CONTROLLED ENTITIES 31 DECEMBER 1997
================================================================================
================================================================================
Notes to and Forming Part of the Financial Statements
================================================================================
1. STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies which have been adopted in the preparation
of these financial statements are:
(a) Basis of preparation
These financial statements are a general purpose financial report which has been
prepared in United States dollars under the principles set out in Note 1(o)
below.
Note 29 shows the statements of operations, balance sheets and statements of
cash flows drawn up under United States generally accepted accounting principles
("US GAAP"), which are consolidated accounts of Petsec Energy Ltd (the
"Company") and its controlled entities. Petsec Energy Ltd was formerly Petroleum
Securities Australia Limited which changed its name to Petsec Energy Ltd on 24
February 1997. The unconsolidated accounts of the Company are not included. Note
28 sets out the principal differences between US GAAP and Australian generally
accepted accounting principles ("AUS GAAP"). Notes 30 and 31 provide additional
disclosures required under US GAAP, including the reconciliations of net income
(loss) and shareholders' equity between AUS GAAP and US GAAP in Note 30(a) and
US Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and
Gas Producing Activities" (SFAS No.69) information in Note 31.
Except as stated above, the financial statements have been drawn up in
accordance with AUS GAAP, which arise from the applicable Australian Accounting
Standards, the Australian Corporations Law and other mandatory Australian
professional reporting requirements (Urgent Issues Group Consensus Views). The
financial statements have been prepared on the basis of historical costs and,
except where stated, do not take into account changing money values or current
valuations of non-current assets.
The accounting policies have been consistently applied and except where stated,
are consistent with those of the previous year. The profit and cash flow
statements are presented for the years ended 30 June 1995 and 1996 and for the
six months ended 31 December 1996 and for the twelve months ending 31 December
1997. Balance sheets are presented for 31 December 1996 and 31 December 1997.
The preparation of the financial statements in conformity with AUS GAAP and US
GAAP 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.
(b) Principles of consolidation
The financial statements of the Economic Entity comprise the financial
statements of the Company (being the chief entity) and its controlled entities.
Where a controlled entity began or ceased to be controlled during the period,
its results are included only from the date control commenced or up to the date
control ceased. Under AUS GAAP, Climax Mining Ltd and its subsidiaries ceased to
be controlled entities of the Company on 23 April 1996, when they became
affiliated companies.
All balances and effects of transactions between controlled entities included in
the consolidated accounts have been eliminated.
Outside interests in the equity and results of the entities which are controlled
by the Company are shown as a separate item in the consolidated accounts.
(c) Exploration leases, permits and titles
Exploration leases, permits and titles relating to an area of interest are
included in the financial statements at cost or at directors' valuation, but are
carried forward only to the extent that they are expected to be recouped through
successful exploitation of the 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 active and significant
exploration operations are continuing. The values of exploration leases, permits
and titles are reviewed at balance date to determine whether any write-down is
necessary. 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.
(d) Exploration and development expenditure
Exploration and development expenditure including drilling on an area of
interest is capitalized until such time as the area is abandoned or has proved
commercial. Exploration and development expenditure relating to an area of
interest is carried forward only to the extent that it is expected to be
recouped through successful exploitation of the 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 active and significant exploration operations are continuing. At balance
date, the amounts of exploration and development expenditure carried forward is
reviewed to determine whether any writedown is necessary. For an area of
interest the assessment is based on the undiscounted pre-tax cash flow estimates
for that area of interest. 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.
F-5
45
================================================================================
PETSEC ENERGY LTD AND ITS CONTROLLED ENTITIES
================================================================================
Interest costs on the borrowings incurred in financing exploration and
development assets in the period before they are brought into production (see
Note 3) are capitalized where material and are amortized on the same unit of
production basis as the asset to which the interest relates. In periods prior to
1997 the amounts were not considered material.
(e) Other non-current assets
The carrying amounts of non-current assets, other than exploration and
evaluation expenditure carried forward (see Notes 1(c) and 1(d)), are reviewed
to determine whether they are in excess of their recoverable amount at balance
date. If the carrying amount of a non-current asset exceeds the recoverable
amount, the asset is written down to the lower amount. In assessing recoverable
amounts the relevant cash flows have not been discounted to their present value.
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.
(f) Restoration and reclamation
At balance date, the liabilities with regard to restoration and reclamation,
including rehabilitation, platform removals, plant closures, waste site closures
and monitoring are reviewed. The assessment is based on undiscounted estimates
of future costs under current legal requirements and technology. The estimated
expense is recognized progressively over the life of each production facility
taking into account production output and the amount of economically recoverable
reserves. Further information is set out in Note 20.
(g) Expenditure amortized
Accumulated lease costs, exploration, evaluation and development expenditure on
an area of interest where commercial operations have commenced is amortized over
the estimated life of the field having regard to economically recoverable
reserves.
(h) Depreciation
i) Oil and gas production facilities and mining facilities
Depreciation is provided on all property, plant and equipment so as to write off
the assets progressively over their estimated economic life using a production
output basis which takes account of economically recoverable reserves.
ii) 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.
(i) Investments, marketable equity securities held for trading and investment
properties
i) Affiliated companies
Investments in affiliated companies are valued at cost or at directors'
valuation which considers amongst other matters the share of the net assets of
the affiliated company and its market value. Dividends are brought to account
when they are received. An affiliated company is one in which the Economic
Entity exercises significant influence and the investment is long term.
Information prepared on an equity accounting basis is set out in Note 25.
ii) Other companies, including marketable equity securities held for
trading
Investments in other companies are carried at directors' valuations which takes
into account market values at the time of the valuation and do not exceed the
expected recoverable amount of the investments. Dividends are brought to account
when they are received. Marketable equity securities held for trading are
carried at fair value with resulting changes in fair value being included in the
profit and loss account.
iii) Investment property
The investment property consists of a realisable investment interest in land and
buildings held for the purpose of letting to produce rental income. The carrying
value of the investment property is assessed at balance date to determine
whether the property should be written down. Accordingly, depreciation is not
charged on the investment property.
(j) Inventories
Inventories are valued at the lower of cost and net realizable value. Absorption
costing is used whereby fixed and variable production costs are included in
determining the cost of inventories.
(k) Joint ventures
The Economic Entity's interest in unincorporated joint ventures is brought to
account by including in the respective balance sheet classes the amount of:
- - the Economic Entity's interest in each of the individual assets employed
in the joint ventures;
- - the liabilities of the Economic Entity in relation to the joint ventures;
and
- - the Economic Entity's interest in the expenses incurred in relation to the
joint ventures.
F-6
46
================================================================================
PETSEC ENERGY LTD AND ITS CONTROLLED ENTITIES
================================================================================
(l) Revenue recognition and derivatives
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.
The Economic Entity 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 Economic Entity'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
Economic Entity's exposure to the effects of commodity price changes is reduced.
Gains and losses on crude oil and natural gas hedging transactions are brought
to account when realized, matching the physical sales to which they relate. At
inception, the contract premiums paid on hedging transactions are recorded as
prepaid expenses and, upon settlement of the hedged production transaction, 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 at
nominal amounts based on current wage and salary rates and includes related
on-costs. Employer contributions to superannuation funds are charged against
income. Further information is set out in Note 20.
(n) Taxation
The liability method of tax effect accounting has been adopted.
Income tax expense is calculated on operating profit adjusted for permanent
differences between taxable and accounting income. The tax effect of timing
differences, which arise from items being brought to account in different years
for income tax and accounting purposes, is carried forward in the balance sheet
as a future income tax benefit or a deferred income tax provision.
Future income tax benefits are not brought to account unless realization of the
asset is assured beyond reasonable doubt. Future income tax benefits relating to
tax losses are only brought to account when their realization is virtually
certain.
(o) Foreign currency
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 the profit and loss account 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 profit and loss accounts
are translated at a weighted average rate for the period. Exchange differences
arising on translation are taken directly to the foreign currency translation
reserve. The income tax effect of exchange differences in respect of US dollar
balances held by the Company and certain subsidiaries have been taken to the
foreign currency translation reserve on consolidation.
The exchange rates (US dollars for one Australian dollar) used in the
preparation of these financial statements are:
================================================================================
Twelve months Six months Twelve months
ended ended ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
================================================================================
Weighted average
exchange rate 0.7341 0.7619 0.7918 0.7325
Exchange rate at
period end 0.7100 0.7839 0.7962 0.6514
--------- --------- --------- ---------
(p) Note issue costs
Costs associated with the note issue have been capitalized and are amortized
over the period to maturity.
(q) Comparatives
Where necessary, comparative information has been reclassified to achieve
consistency in disclosure with current financial year amounts and other
disclosures.
(r) Change of year end
The Company changed its year end from 30 June to 31 December at 31 December
1996. The immediate prior period comparisons are therefore for the six month
period.
(s) Rounding of amounts
The Company is of a kind referred to in Regulation 3.6.05(6) of the Australian
Corporations Regulations and amounts in these financial statements have been
rounded off to the nearest one thousand dollars in accordance with Section 311
of the Australian Corporations Law and the regulations, unless otherwise
indicated.
F-7
47
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- ---------------------------------------------------------------------------------------------------------------------------------
2. OTHER REVENUE
Proceeds on sale of investment $ 4 $ -- $ -- $ --
Proceeds on sale of investment property -- 7,429 -- --
Proceeds on sale of oil and gas property 5,686 320 11 --
Proceeds on sale of trading securities 247 35 -- --
Proceeds on sale of property, plant and equipment 40 1,052 6 68
Less book value of assets sold (2,656) (8,228) -- --
Interest income 431 568 721 1,496
Rent received 1,131 1,242 93 203
Sundry income 290 654 9 687
========== ========== ========== ==========
Total other revenue before abnormal items 5,173 3,072 840 2,454
Abnormal revenue items
- - Proceeds on sale of investments -- 13,391 9,941 --
- - Proceeds on sale of oil and gas property 5,726 -- -- --
- - Less book value of assets sold (2,543) (5,226) (2) --
---------- ---------- ---------- ----------
Total other revenue after abnormals $ 8,356 $ 11,237 $ 10,779 $ 2,454
---------- ---------- ---------- ----------
3. OPERATING EXPENSES
Oil and gas royalties paid or due and payable $ 3,984 $ 13,554 $ 10,071 $ 30,200
Lease operating expenditure 12,337 13,900 3,378 11,721
General and administration 6,324 8,808 3,471 9,883
Amortization of exploration and development 6,658 17,945 13,663 55,754
Depreciation of property, plant and equipment 854 3,980 1,715 7,975
Restoration and reclamation 31 494 318 1,606
Exploration expenditure 841 1,510 2,831 1,012
Interest paid or due and payable to external parties 1,575 3,704 1,472 6,933
Less: interest capitalised at a rate of 9.5% per annum -- -- -- (911)
---------- ---------- ---------- ----------
Total operating expenses (excluding abnormal items) $ 32,604 $ 63,895 $ 36,919 $ 124,173
========== ========== ========== ==========
The twelve months ended 30 June 1995 and 1996 include the consolidated operating
expenses of Climax Mining Ltd.
4. ABNORMAL ITEMS
Included in the operating profit before income tax are
the following items:
Profit from sale of investments $ -- $ 8,165 $ 9,939 $ --
Income tax effect -- (4,654) (3,578) --
---------- ---------- ---------- ----------
-- 3,511 6,361 --
========== ========== ========== ==========
Dry hole costs -- -- -- (10,453)
Income tax effect -- -- -- 3,763
---------- ---------- ---------- ----------
-- -- -- (6,690)
========== ========== ========== ==========
Decrease in oil and gas reclamation provision 1,340 -- -- --
Increase in mining rehabilitation provision (763) (824) -- --
Income tax effect (258) 296 -- --
========== ========== ========== ==========
319 (528) -- --
---------- ---------- ---------- ----------
Provision against loan to affiliated company in respect of
minerals exploration at certain prospects in Ecuador
(no income tax effect) $ -- $ (842) $ -- $ --
========== ========== ========== ==========
F-8
48
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
Oil well restoration $ (1,338) $ -- $ -- $ --
Income tax effect 509 -- -- --
---------- ---------- ---------- ----------
(829) -- -- --
---------- ---------- ---------- ----------
Profit on sale of oil and gas property 3,183 -- -- --
Income tax effect (1,210) -- -- --
---------- ---------- ---------- ----------
1,973 -- -- --
---------- ---------- ---------- ----------
Aggregate abnormal items before income tax $ 2,422 $ 6,499 $ 9,939 $ (10,453)
---------- ---------- ---------- ----------
5. EXTRAORDINARY ITEM
Effect of deconsolidation of Climax Mining Ltd
(no income tax effect) $ -- $ (5,126) $ -- $ --
---------- ---------- ---------- ----------
6. AUDITORS' REMUNERATION
Amounts received or due and receivable for audit services by:
- - auditors of the Company $ 95 $ 107 $ 140 $ 78
- - other - (KPMG member firms) 25 38 30 38
---------- ---------- ---------- ----------
120 145 170 116
Amounts received or due and receivable for other services by:
- - auditors of the Company 38 410 -- 88
---------- ---------- ---------- ----------
$ 158 $ 555 $ 170 $ 204
---------- ---------- ---------- ----------
The amount received during the year ended 30 June 1996 includes audit services
in respect of the prospectus required for the Company's public offering in the
USA in July 1996
7. INCOME TAX EXPENSE
(a)Income tax expense
The prima facie income tax expense calculated at 36% (36% at
31 December 1997 and 1996 and 30 June 1996, 33%
at 30 June 1995) on the operating profit $ 821 $ 6,536 $ 7,722 $ 8,340
Increase (decrease) in income tax expense due to non-tax
deductible/assessable items:
- - realization of asset revaluation -- 1,698 -- --
- - legal expenses 141 121 9 16
- - provision against loan to overseas entity -- 303 -- --
- - diminution in value of investment property 131 -- -- --
- - non-assessable profit on sale of investments -- (133) (8) 31
- - other (57) (37) -- --
Utilization of exploration deductions not brought to account (301) (315) -- --
Utilization of tax losses previously not brought to account (294) (2,504) (1,373) (625)
Effect of different rates of tax on overseas income 538 206 203 --
Effect of change in income tax rate on deferred tax balances 39 -- -- --
Losses not carried forward as future income tax benefit 305 155 -- --
---------- ---------- ---------- ----------
Income tax expense $ 1,323 $ 6,030 $ 6,553 $ 7,762
---------- ---------- ---------- ----------
The income tax expense is made up of:
- - expense (benefit) resulting from translation of balance
sheet movements $ (14) $ 32 $ 24 $ 16
- - current income tax paid -- 14 120 133
- - current income tax provision 501 180 269 (249)
- - deferred income tax provision 4,371 10,385 10,678 8,242
- - future income tax benefit (3,535) (9,328) (4,538) (380)
- - adjustment on deconsolidation of Climax Mining Ltd. -- 4,747 -- --
---------- ---------- ---------- ----------
$ 1,323 $ 6,030 $ 6,553 $ 7,762
---------- ---------- ---------- ----------
F-9
49
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- -------------------------------------------------------------------------------------------------------------------------------
7. INCOME TAX EXPENSE (CONTINUED)
(b) Deferred income tax provision
Deferred income tax provision comprises the
estimated expense at current income tax rates on the following items:
Difference in depreciation and amortization of
property, plant and equipment and exploration
expenditure for accounting and income tax purposes $ 10,086 $ 20,876 $ 31,575 $ 39,797
Net unrealised foreign exchange gains transferred to the
foreign currency translation reserve -- -- -- 3,258
Prepayments and accrued income 455 49 28 48
---------- ---------- ---------- ----------
$ 10,541 $ 20,925 $ 31,603 $ 43,103
---------- ---------- ---------- ----------
(c)Future income tax benefit
Future income tax benefit comprises the estimated future
benefit at current income tax rates on the following items:
Difference in interest expense, borrowing costs and
compensation expense for accounting
and income tax purposes $ 1,651 $ 3,316 $ 242 $ 1,051
Provisions and accrued employee entitlements not
currently deductible 787 552 662 1,335
Tax losses carried forward 5,972 13,870 21,372 20,270
---------- ---------- ---------- ----------
$ 8,410 $ 17,738 $ 22,276 $ 22,656
---------- ---------- ---------- ----------
(d)Future income tax benefit not taken to account
The potential future income tax benefit arising from tax
losses and timing differences was not recognized as
an asset because recovery was not virtually certain: $ 2,468 $ 149 $ -- $ --
These benefits will be utilized only if:
i) the relevant company derives future assessable income of a nature and
an amount sufficient to enable the benefit to be realized, or the
benefit can be utilized by another company in the Economic Entity in
accordance with Section 80G of the Australian Income Tax Assessment
Act 1936;
ii) the relevant company continues to comply with the conditions for
deductibility imposed by the law; and
iii) no changes in tax legislation adversely affect the relevant company
in realizing the benefit.
8. EARNINGS PER SHARE
Weighted average number of ordinary shares used in the (in thousands)
calculation of the basic earnings per share
(excludes the shares owned by Climax Mining Ltd until
its deconsolidation) 75,874 86,297 104,977 107,320
Weighted average number of ordinary shares used in the
calculation of the diluted earnings per share
(excludes the shares owned by Climax Mining Ltd until
its deconsolidation) * 88,041 108,276 109,990
Operating profit after tax and before extraordinary items (US dollars, in thousands)
attributable to members of the Company (other than the
shares held by controlled entity, Climax Mining Ltd) as
used in the calculation of basic earnings per share $ 2,456 $ 10,372 $ 14,899 $ 15,404
Operating profit after tax and before extraordinary items
attributable to members of the Company (other than the
shares held by controlled entity, Climax Mining Ltd) as
used in the calculation of diluted earnings per share * $ 10,476 $ 15,095 $ 15,734
* Not materially different from basic earnings per share.
There were no dividends paid by the Company in the periods covered by these
financial statements. If the directors recommend any payment of dividends, such
dividends will be payable in Australian dollars.
F-10
50
31 December 31 December
1996 1997
(US dollars, in thousands)
- -----------------------------------------------------------------------------------------------------
9. RECEIVABLES
Current
Trade debtors $ 11,855 $ 13,978
Other debtors and prepayments 345 547
---------- ----------
Total current receivables 12,200 14,525
---------- ----------
Non-current
Loans under Employee Share Plan (Notes 18 and 24) 3,841 2,676
---------- ----------
Total non-current receivables $ 3,841 $ 2,676
---------- ----------
10. INVENTORIES
Crude oil - at cost $ 46 $ 43
---------- ----------
11. INVESTMENTS
Current
Listed entities - at directors' valuation 31 December 1997 $ -- $ 195
---------- ----------
Quoted market value of securities: $195,000
Non-current
(a)Investment in affiliated companies (Note 25)
Unlisted - at cost -- --
Listed entities - at directors' valuation 1989 6,725 5,502
Quoted market value of securities: $11,439,000 (1996: $36,041,000)
(b)Investment in other companies
Unlisted - at cost 32 --
Listed - at cost -- 26
Listed - at directors' valuation 1996 95 --
---------- ----------
Quoted market value of listed securities: $6,000 (1996: $112,000)
Total investments - non-current $ 6,852 $ 5,528
---------- ----------
The listed shares comprise investments in resource companies
F-11
51
11. INVESTMENTS (CONTINUED)
(c) Particulars of investments - controlled entities
---------------------------------------------------------
31 December 31 December Class of Place of
1997 1996 share incorporation
---------------------------------------------------------
% %
Petsec Investments
Pty. Limited (1) 100 100 ord. Australia
Petroleum Securities
Pty. Limited (1) 100 100 ord. Australia
Najedo Pty. Limited (1) 100 100 ord. Australia
Bacobi Pty. Ltd (1) 100 100 ord. Australia
Badino Pty. Ltd (1) 100 100 ord. Australia
Petroleum Securities Share
Plan Pty. Limited (1) 100 100 ord. Australia
Oilco Limited 99 99 ord. Australia
Petsec America Pty. Ltd 100 100 ord. Australia
Petsec (USA) Inc. (2) 100 100 ord. USA
Petsec Petroleum Inc. (2) 100 100 ord. USA
Petsec Energy Inc. (2) 100 100 ord. USA
Osglen Pty. Limited 80.7 80.7 ord. Australia
Laurel Bay Petroleum
Limited (1) 100 100 ord. Australia
Petroleum Securities
Energy Limited (1) 100 100 ord. Australia
Ginida Pty. Limited (1) 100 100 ord. Australia
Western Medical
Products Pty. Limited (1) 100 100 ord. Australia
102 Miller Street Pty. Limited 100 100 ord. Australia
(1) Entities which have entered into approved deeds of indemnity for the cross
guarantee of liabilities with the Company in respect of relief granted from
specified accounting and financial reporting requirements in accordance with a
Class Order issued by the Australian Securities Commission.
(2) Audited by overseas firm of KPMG.
All companies incorporated overseas carry on business in the respective overseas
country. All other companies carry on business within Australia.
31 December 31 December
1996 1997
(US dollars, in thousands)
----------------------------
12. PROPERTY, PLANT AND EQUIPMENT
Investment property - at cost $ 140 $ 115
---------- ----------
Furniture and fittings
- - at cost 192 167
- - accumulated depreciation (80) (65)
---------- ----------
- - at net book value 112 102
---------- ----------
Office machines and equipment
- - at cost 1,120 1,513
- - accumulated depreciation (441) (627)
---------- ----------
- - at net book value 679 886
---------- ----------
Motor vehicles
- - at cost 106 102
- - accumulated depreciation (67) (57)
---------- ----------
- - at net book value $ 39 $ 45
---------- ----------
F-12
52
31 December 31 December
1996 1997
(US dollars, in thousands)
- -------------------------------------------------------------------------------
Leasehold improvements
- - at cost $ 93 $ 99
- - accumulated amortization (36) (42)
---------- ----------
- - at net book value 57 57
---------- ----------
Plant and equipment
- - at cost 27,520 51,339
- - accumulated depreciation (6,924) (14,590)
---------- ----------
- - at net book value 20,596 36,749
---------- ----------
Total property, plant and equipment
- - at net book value $ 21,623 $ 37,954
---------- ----------
The methods and estimated useful lives of property, plant and equipment are:
----------------------------
Method Years
----------------------------
Furniture and fittings Straight line 7
Office machines and equipment Straight line 7
Motor vehicles Straight line 4
Leasehold improvements Straight line 5
Plant and equipment Unit of production n/a
13. Exploration and development expenditure
Exploration leases, permits and titles:
- - at cost $ 19,026 $ 27,463
- - accumulated amortization (3,267) (5,363)
---------- ----------
15,759 22,100
---------- ----------
Exploration expenditure:
- - at cost 126,241 230,298
- - accumulated amortization (29,963) (80,438)
---------- ----------
96,278 149,860
---------- ----------
Development expenditure:
- - at cost 14,482 21,990
- - accumulated amortization (5,161) (8,344)
---------- ----------
9,321 13,646
---------- ----------
Total exploration and development expenditure $ 121,358 $ 185,606
---------- ----------
F-13
53
31 December 31 December
1996 1997
---------- ----------
(US dollars, in thousands)
14. NOTE ISSUE COSTS
- at cost $ -- $ 3,171
- accumulated amortization -- (171)
---------- ----------
Net note issue costs (see Note 1(p)) $ -- $ 3,000
---------- ----------
15. CREDITORS, ACCRUALS AND BORROWINGS
Current
Trade creditors $ 18,120 $ 15,639
Sundry creditors and accruals 6,473 12,123
---------- ----------
Total current creditors and accruals 24,593 27,762
---------- ----------
Non-current
Bank loans - secured 37,000 --
Notes - unsecured -- 99,630
---------- ----------
Total non-current borrowings (see Note 17(a)) $ 37,000 $ 99,630
---------- ----------
16. PROVISIONS
Current
Employee entitlements $ 45 $ 306
Income tax 271 --
---------- ----------
Total current provisions $ 316 $ 306
---------- ----------
17. FINANCING ARRANGEMENTS AND FINANCIAL INSTRUMENTS DISCLOSURES
(a) Financing arrangements
The Economic Entity has US dollar debt relating to its US oil and gas
operations.
Petsec Energy Inc., a wholly-owned subsidiary, issued during the year $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 15 June 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 31 December
1997 was $60 million. At 31 December 1997 there were no borrowings and $10.0
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.
A summary of the maturities of long-term debt of the Economic Entity is as
follows:
--------------------------------
31 December 31 December
1996 1997
--------------------------------
Due within:
First year (current) $ -- $ --
Second year 9,250 --
Third year 18,500 --
Fourth year 9,250 --
Thereafter $ -- $ 100,000
(b) Interest rate risk exposures
Details of interest relating to the senior subordinated notes are shown in Note
17(a).
The interest rate on the borrowings under the revolving credit facility detailed
in Note 17(a) is LIBOR plus a margin of 1.25% to 1.50% per annum depending upon
the balance drawn. There is also a fee of 0.30% to 0.35% per annum on the unused
portion of the borrowing base. The weighted average interest rate for the six
months ended 31 December 1996 was 7.24%, with no borrowings outstanding at 31
December 1997.
At 31 December 1997, the weighted average interest rate for cash deposits was
5.80% per annum. The other financial assets and liabilities detailed in the
financial statements (receivables, payables and investments) are all
non-interest bearing.
F-14
54
(c) Foreign exchange exposures
Nearly all of the Economic Entity's operations are in the United States and its
sales, operating costs and capital expenditure are denominated predominantly in
US dollars. 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 Economic Entity, as measured in US dollars. The
Economic Entity'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 Economic Entity 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 Economic Entity 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 Economic Entity 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 Economic Entity will pay the difference to the
counterparty.
At 31 December 1997 the Economic Entity had the following outstanding contracts
maturing monthly through May 2000:
(i) swap agreements for the sale of 19.4 million MMbtu of natural gas at an
average price of $2.155 per MMbtu; and
(ii) swap agreements for the sale of 1.6 million barrels of oil at an average
price of $20.02 per barrel.
At 31 December 1997 the effect to the Company to terminate these contracts would
have been a gain of $2.5 million for oil and a cost of $1.6 million for gas,
representing the present value of the fair market value of the contracts at that
date.
For the year ended 31 December 1997 hedging activities reduced revenues by
US$4.4 million, (year ended 30 June 1995: gain of US$0.1 million, year ended 30
June 1996: reduction of US$4.2 million, six months ended 31 December 1996:
reduction of US$3.6 million).
Collars
A collar agreement is similar to a swap except that the Economic Entity receives
from the counterparty the difference between the floor price and NYMEX
settlement price if the settlement price is below the floor. The Economic Entity
pays to the counterparty the difference between the ceiling price and the NYMEX
settlement price if the settlement price is above the ceiling.
At 31 December 1997, the Economic Entity had 3.48 million MMbtu of gas hedged
through December 1998 in costless collars with an average floor price of $2.27
per MMbtu and an average ceiling price of $3.69 per MMbtu. The effect to the
Economic Entity to terminate these contracts at 31 December 1997 would have been
a gain of $0.4 million.
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 recognised if counterparties
failed to perform as contracted.
On-balance sheet financial assets:
The credit risk on financial assets, excluding investments, of the Economic
Entity which have been recognised 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:
------------------------------------------------------------------
Twelve months ended Six months ended Twelve months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
------------------------------------------------------------------
Vision Resources, Inc. 55% 55% 62% 46%
Aquila Energy Marketing Corporation - 33% * *
PG & E Energy Trading Corporation - - - 16%
Duke Energy Trading and Marketing, L.L.C.(formerly
Pan Energy Trading and Market Services, L.L.C.) 34% 10% 24% 22%
Natural Gas Clearinghouse * * 10% 12%
(* = less than 10%)
Based upon the current demand for oil and gas, the Company does not believe the
loss of any current purchasers would have a material adverse effect on the
Company. The Company continually evaluates the financial strength of its
customers but does not require collateral to support trade receivables.
Off-balance sheet financial instruments:
The credit risk on off-balance sheet derivative contracts is considered minimal
as counterparties are recognised financial intermediaries such as banks or
commodity trading houses with acceptable credit ratings determined by a
recognised rating agency. Letters of credit of $4,500,000 (1996: $7,850,000)
have been issued to support the Economic Entity's commodity hedging program in
the event that commodity prices are above the contracted amounts upon
settlement.
F-15
55
17. Financing arrangements and financial instruments disclosures (continued)
(f) Fair values of financial assets and liabilities
The carrying values of cash and cash equivalents, accounts receivable and
accounts payable are estimated to approximate fair value because of their short
maturity.
The fair values of marketable equity securities and commodity price contracts
are set out in Notes 11 and 17(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
marketable equity securities be sold may differ from the quoted market prices.
At 31 December 1997 the net fair value of the $100 million senior subordinated
notes was $102,625,000 based on quoted market prices of the notes.
-------------------------------
31 December 31 December
1996 1997
(US dollars, in thousands)
-------------------------------
18. Share capital
Authorised capital
250,000,000 shares of 20 Australian cents each $ 38,325 $ 38,325
Issued capital
107,601,041 (1996: 106,631,041) ordinary
shares of 20 Australian cents each fully paid $ 16,345 $ 16,491
At its general meeting on 29 November 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 Economic
Entity. 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 Economic Entity. The exercise prices of the options are the ruling market
prices when the options are issued. The total shares and options issued to
employees over a five year period is not to exceed 5% of the issued shares in
the Company. As at 31 December 1997 the number of further shares or options
which could be issued within the 5% limit was 234,052.
During the twelve months ended 31 December 1997 the Company increased the number
of ordinary shares on issue by issuing 970,000 shares at an average of A$2.09
per share upon exercise of options.
At 31 December 1997 there were the following unexercised options to purchase the
Company's ordinary shares:
- ---------------------------------------------------------------------------------------------------------------------
Date of grant Expiry date Number of shares Exercise price
- ---------------------------------------------------------------------------------------------------------------------
6 November 1995 6 November 2000 82,000 A$2.95 (employee options)
3 January 1996 3 January 2001 110,000 A$3.40 (employee options)
22 July 1996 21 July 2001 1,564,000 A$4.87 (employee options)
22 July 1996 20 July 2001 350,000 A$7.00
4 September 1996 3 September 2001 125,000 A$5.58 (employee options)
25 October 1996 24 October 2001 10,000 A$5.89 (employee options)
29 November 1996 28 November 2001 10,000 A$5.60 (employee options)
30 June 1997 30 June 2001 50,000 A$5.69 (employee options)
---------
Total unexercised options 2,301,000
=========
Options become exercisable after various dates and share prices of the Company
have been reached.
F-16
56
Option plan:
- -----------------------------------------------------------------------------------------------------------------------
Number Weighted Weighted Number Weighted
of average average exercisable average
outstanding exercise remaining exercise
options price contractual price
life of those
(years) exercisable
- -----------------------------------------------------------------------------------------------------------------------
As at 30 June 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 30 June 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 31 December 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 31 December 1997 2,301,000 A$5.12 3.5 82,000 A$2.95
----------
Employee Share Plan:
- -----------------------------------------------------------------------------------------------------------------------
Number Weighted Weighted Number Weighted
of average average vested average
outstanding issue remaining issue
shares subject price contractual price
to life of those
employee loans of loan vested
(years)
- -----------------------------------------------------------------------------------------------------------------------
As at 30 June 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 employee (160,000) A$1.75
----------
As at 30 June 1996 2,085,000 A$1.78 3.6 1,200,000 A$1.75
Issued 200,000 A$5.60
----------
As at 31 December 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 31 December 1997 1,875,000 A$2.19 2.6 1,665,000 A$1.75
----------
Weighted average grant-date fair value of:
-----------------------------------------------------------
Twelve months ended Six months ended Twelve months ended
30 June 31 December 31 December
1996 1996 1997
-----------------------------------------------------------
Options granted at market price $0.58 $1.11 $0.91
Options granted above market price -- $0.64 --
Employee shares issued at market price $0.71 $1.21 --
F-17
57
30 June 30 June 31 December 31 December
(US dollars, in thousands) 1995 1996 1996 1997
--------- --------- --------- ---------
19. RESERVES
Share premium $ 13,298 $ 27,722 $ 97,117 $ 98,504
Asset revaluation 4,452 3,003 3,003 3,003
Capital profits 3,335 5,885 5,885 5,885
Foreign currency translation (1,647) 497 817 (4,386)
--------- --------- --------- ---------
Total reserves 19,438 37,107 106,822 103,006
--------- --------- --------- ---------
Movements during the financial period
Share premium
Balance at the beginning of the financial period 10,549 13,298 27,722 97,117
Premium on share placement net of issue costs -- 16,220 68,128 (8)
Premium on ordinary shares issued on exercise of options 3 147 391 1,395
Premium on ordinary shares issued under Employee
Share Plans 3,555 261 876 --
Shares bought back under Employee Share Plan -- (33) -- --
Movement in outside equity interest (809) (1,288) -- --
Deconsolidation of Climax Mining Ltd -- (883) -- --
--------- --------- --------- ---------
Balance at the end of the financial period 13,298 27,722 97,117 98,504
--------- --------- --------- ---------
Foreign currency translation reserve
Balance at the beginning of the financial period (927) (1,647) 497 817
Tax effect on unrealised foreign exchange gains -- -- -- (3,258)
Adjustment on translation of self-sustaining operation (720) 2,144 320 (1,945)
--------- --------- --------- ---------
Balance at the end of the financial period $ (1,647) $ 497 $ 817 $ (4,386)
--------- --------- --------- ---------
20. COMMITMENTS AND CONTINGENT LIABILITIES
(a) Contingent liabilities
As at 31 December 1997, the estimated maximum contingent liability of the
Economic Entity 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 $10,191,000 (1996:
$12,492,000).
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 Economic Entity.
As at 31 December 1997, the total restoration and reclamation costs including
platform removals, and monitoring is estimated to be $7,318,000 (1996:
$3,595,000). This estimated expense is recognised 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 Economic
Entity.
In addition, a subsidiary has contingent liabilities in respect of its commodity
hedging program (see Note 17).
----------------------------
31 December 31 December
1996 1997
(US dollars, in thousands)
----------------------------
(b) Lease commitments
Future operating lease rentals on property:
Due not later than 1 year $ 385 $ 318
Due later than 1 year but not later than 2 years 314 315
Due later than 2 years but not later than 3 years 330 191
Due later than 3 years but not later than 4 years 229 130
Due later than 4 years but not later than 5 years 178 130
Due later than 5 years 533 260
---------- ----------
$ 1,969 $ 1,344
---------- ----------
F-18
58
(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) Exploration and lease rental commitments
At 31 December 1997, a subsidiary of the Company has exploration leases under
which it is committed to pay lease rentals. The amounts to be incurred were:
---------------------------
31 December 31 December
1996 1997
(US dollars, in thousands)
---------------------------
Due not later than 1 year $ 318 $ 256
Due later than 1 year but not later than 2 years 273 234
Due later than 2 years but not later than 3 years 223 167
Due later than 3 years but not later than 4 years 146 59
Due later than 4 years but not later than 5 years 38 --
Due later than 5 years 13 --
------- --------
$ 1,011 $ 716
------- --------
(e) Class Order
Pursuant to an Australian Securities Commission Class Order, relief was granted
to wholly-owned Australian subsidiaries of the Company from the Corporations Law
requirements for preparation, audit and publication of accounts. The respective
subsidiaries covered by the Class Order are listed in Note 11(c).
It is a condition of the Class Order that the Company and each of the
subsidiaries enter into a Deed of Cross Guarantee. The effect of the deed is
that the Company guarantees to each creditor payment in full of any debt in the
event of winding up of any of the subsidiaries under certain provisions of the
Corporations Law. If a winding up occurs under other provisions of the Law, the
Company will only be liable in the event that after six months any creditor has
not been paid in full. The subsidiaries have also given similar guarantees in
the event that the Company is wound up.
At 31 December 1997, the Company and the subsidiaries which are a party to a
deed with the Company had aggregate assets of $310,750,000 (December 1996:
$377,329,000) and aggregate liabilities of $18,989,000 (December 1996:
$22,369,000). Their contribution to the consolidated operating profit for the
year was a loss of $1,901,000 (six months to December 1996: a loss of
$6,600,000).
(f) Superannuation commitments
The Economic Entity contributes to one employer established accumulation
superannuation fund and to employees' private superannuation arrangements.
Employee contributions are based on various percentages of their gross salaries.
The Economic Entity is under no legal obligation to make up any shortfall in the
employer established accumulation fund's assets and to meet payments due to
employees. No actuarial assessment has been undertaken and an assessment is not
required. The assets of the fund are sufficient to meet all benefits payable in
the event of its termination, or the voluntary or compulsory termination of
employment of each employee of the Economic Entity.
- ---------------------------------------------------------------------------------------------------------------------------------
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
- ---------------------------------------------------------------------------------------------------------------------------------
21. DIRECTORS' AND EXECUTIVES' REMUNERATION
(a)Directors' remuneration
The numbers of directors of the Company whose income
from the Company or any related body corporate falls
within the following bands are:
A$ 10,000 - A$ 19,999 -- -- 1 --
A$ 20,000 - A$ 29,999 -- 2 2 1
A$ 30,000 - A$ 39,999 1 1 1 --
A$ 40,000 - A$ 49,999 1 1 -- --
A$ 50,000 - A$ 59,999 1 -- -- 3
Total income received, or due and receivable, by directors of
the Company from the Company or any related body corporate $ 100,746 $ 101,794 $ 84,337 $ 136,791
Total income received, or due and receivable, by directors
of each entity in the Economic Entity from the Company,
any related body corporate or controlled entity $ 108,087 $ 223,409 $ 109,044 $ 159,459
F-19
59
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- ---------------------------------------------------------------------------------------------------------------------------------
21. DIRECTORS' AND EXECUTIVES' REMUNERATION (CONTINUED)
(b)Executives' remuneration
The income of executives who work wholly or mainly outside
Australia is not included in this disclosure
The numbers of executive officers whose income from the
Company, controlled entities or related body corporate falls
within the following bands are:
A$120,000 - A$129,999 1 -- 1 --
A$130,000 - A$139,999 2 1 -- --
A$140,000 - A$149,999 1 -- -- --
A$150,000 - A$159,999 1 2 -- --
A$160,000 - A$169,999 1 -- 1 --
A$190,000 - A$199,999 -- 2 -- --
A$200,000 - A$209,999 -- 1 -- --
A$220,000 - A$229,999 1 -- -- --
A$240,000 - A$249,999 -- -- -- 1
A$340,000 - A$349,999 -- 1 -- --
A$550,000 - A$559,999 -- -- -- 1
Total income received, or due and receivable, from
the Company, controlled entities or related entities by
executive officers of the Economic Entity whose
income exceeds A$100,000 $ 795,526 $1,063,097 $ 226,455 $ 587,099
The income of directors and executives disclosed above includes payments for
superannuation to comply with the relevant government legislation and is in
accordance with Australian Securities Commission Class Order 95/741 dated 27
June 1995.
Prior to 30 June 1996 figures included executives of Climax Mining Ltd which was
within the Economic Entity during that period.
----------------------------
31 December 31 December
(US dollars, in thousands) 1996 1997
----------------------------
22. INTERESTS IN JOINT VENTURES
Included in the assets and liabilities of the Economic Entity are the
following items which represent the Economic Entity's interest in the
assets and liabilities employed in joint ventures:
Current assets
Cash $ -- $ --
Receivables -- --
Inventories -- --
---------- ----------
-- --
---------- ----------
Non-current assets
Property, plant and equipment -- --
Exploration and development expenditure 144 150
---------- ----------
144 150
---------- ----------
Total assets 144 150
---------- ----------
Current liabilities
Creditors and borrowings -- --
---------- ----------
Net assets 144 150
---------- ----------
The contribution of the Economic Entity's joint venture interests
to the operating profit 63 80
---------- ----------
Value of joint venture output $ 88 $ 199
---------- ----------
Refer Note 20 for details of commitments and contingent liabilities.
F-20
60
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
23. SEGMENT REPORTING
In the year ended 31 December 1997 the Economic Entity
operated predominantly within the USA and Australia in
the resource industry. In producing the data below, the
Company has made certain allocations of expenses, including
foreign currency translation gains and losses depreciation
and amortization, and general and administrative overhead
expenses
Geographic segments
Segment revenue:
Sales - USA (before deducting royalties) $ 20,531 $ 64,141 $ 47,592 $ 155,338
Sales - Australia (before deducting royalties) 7,837 9,358 -- --
Other revenue - USA 6,691 371 247 1,066
Other revenue - Australia 796 9,847 10,532 1,388
---------- ---------- ---------- ----------
Total revenue (including abnormal revenue items) 35,855 83,717 58,371 157,792
---------- ---------- ---------- ----------
Profit before interest and tax:
USA 8,607 18,716 13,458 30,208
Australia (4,941) 2,576 8,745 (2,516)
Other (32) -- -- --
---------- ---------- ---------- ----------
Profit before interest and tax 3,634 21,292 22,203 27,692
Interest expense, net of interest income (1,144) (3,136) (751) (4,526)
---------- ---------- ---------- ----------
Profit before tax 2,490 18,156 21,452 23,166
Income tax (1,323) (6,030) (6,553) (7,762)
---------- ---------- ---------- ----------
Operating profit after tax 1,167 12,126 14,899 15,404
---------- ---------- ---------- ----------
Assets at period end:
USA 64,043 134,597 177,390 270,425
Australia 22,973 15,993 7,106 6,164
Philippines 11,503 -- -- --
Other 2,113 -- -- --
Corporate (Australia) 2,582 2,625 16,228 14,765
---------- ---------- ---------- ----------
Total assets $ 103,214 $ 153,215 $ 200,724 $ 291,354
---------- ---------- ---------- ----------
Corporate assets comprise primarily cash and cash equivalents,
certain accounts receivable and office furniture and fittings
Industry segments
Segment revenue:
Oil and gas sales (before deducting royalties) $ 21,015 $ 64,614 $ 47,592 $ 155,338
Gold sales (before deducting royalties) 6,484 7,866 -- --
Property investment rentals and sale 869 1,374 -- --
Sale of investments and marketable equity securities 133 8,140 9,939 --
Other mining revenue -- 282 -- --
Other oil and gas revenue 6,749 231 110 --
Other 605 1,210 730 2,454
---------- ---------- ---------- ----------
Total revenue (including abnormal revenue items) 35,855 83,717 58,371 157,792
---------- ---------- ---------- ----------
Profit (loss) before interest and tax:
Oil and gas 7,960 18,207 13,458 30,208
Gold (2,047) (706) -- --
Property investment 454 832 -- --
Investment income 38 3,718 -- --
Other (2,771) (759) 8,745 (2,516)
---------- ---------- ---------- ----------
Profit before interest and tax 3,634 21,292 22,203 27,692
Interest expense, net of interest income (1,144) (3,136) (751) (4,526)
---------- ---------- ---------- ----------
Profit before tax 2,490 18,156 21,452 23,166
Income tax (1,323) (6,030) (6,553) (7,762)
---------- ---------- ---------- ----------
Operating profit after tax $ 1,167 $ 12,126 $ 14,899 $ 15,404
---------- ---------- ---------- ----------
F-21
61
Twelve months ended Six months ended Twelve months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- ----------------------------------------------------------------------------------------------------------------------------
23.SEGMENT REPORTING (CONTINUED)
Assets at period end:
Oil and gas $ 67,238 $ 143,745 $ 177,506 $ 270,752
Mining 21,494 -- -- --
Property investment 6,515 138 138 115
Investment in affiliated and other companies 5,015 6,707 6,852 5,722
Corporate (Australia) 2,582 2,625 16,228 14,765
Other 370 -- -- --
----------- ----------- ----------- -----------
Total assets 103,214 153,215 200,724 291,354
----------- ----------- ----------- -----------
Depletion, depreciation and amortization (including deferred
stripping) charged during the period:
Oil and gas 5,515 21,696 15,357 63,691
Mining 2,836 546 -- --
Property investment 14 12 -- --
Other 104 89 21 38
----------- ----------- ----------- -----------
Total depletion, depreciation and amortization 8,469 22,343 15,378 63,729
----------- ----------- ----------- -----------
Capital expenditure incurred during the period:
Oil and gas 32,935 63,875 48,472 154,762
Mining 5,321 14,298 -- --
Other 310 25 33 40
----------- ----------- ----------- -----------
Total capital expenditure $ 38,566 $ 78,198 $ 48,505 $ 154,802
----------- ----------- ----------- -----------
24. RELATED PARTY DISCLOSURES
(a) Directors
The names of persons who were directors of the Company during the year ended 31
December 1997 are Messrs A.J. Fletcher, T.N. Fern, D.A. Mortimer and R.B.
Corlett.
Details of the directors' remuneration are set out in Note 21.
Other than as disclosed below in this note, there were no material contracts
involving directors during the year.
Other than as disclosed below in this note, no loans were made to directors
during the current year or the previous periods and no such loans are
subsisting.
At 31 December 1997 the aggregate amount of loans outstanding to directors was
$2,576,000 (December 1996: $3,720,000). 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 (A.J. Fletcher,T.N. Fern, D.A. Mortimer and R.B. Corlett) and to an
employee who is a director of subsidiaries (R. A. Cumming). During the year D.G.
Battersby, a director of subsidiaries, repaid loans of $456,000.
During the year the Company made payments to a company associated with Mr Fern
which provided management services to the Economic Entity. The dealings were in
the ordinary course of business and were on normal terms and conditions. During
the year the company associated with Mr Fern was paid or was payable $290,000
(six months to 31 December 1996: $133,000) by the Company.
During the year the Company made payments to a company associated with Mr
Fletcher which provided management consulting services to the Economic Entity.
The dealings were in the ordinary course of business and were on normal terms
and conditions. During the year the company associated with Mr Fletcher was paid
or was payable $18,000 (six months to 31 December 1996: nil).
At 31 December 1997 the aggregate number of ordinary shares in the Company held
directly, indirectly or beneficially by directors of the Company or their
director-related entities was 29,374,123 (1996: 29,365,123).
F-22
62
(b) Controlled entities
Details of interests in controlled entities are set out in Note 11. Details of
dealings of the Company with controlled entities are set out below:
i) Wholly-owned controlled entities
Inter-company loans are interest free with no set repayment terms.
The aggregate amounts receivable from/and payable to wholly-owned controlled
entities by the Company at balance date were:
---------------------------
31 December 31 December
1996 1997
(US dollars, in thousands)
---------------------------
Receivables
Non-current $ 48,139 $ 39,567
Payable
Non-current $ 11,091 $ 9,126
At 31 December 1997, the Company had provided against various loans to
wholly-owned Australian controlled entities.
ii) Related entities
Climax Mining Ltd was charged an amount of $475,000 by the Company for the
provision of management, financial and office services for the twelve months to
31 December 1997 (six months to 31 December 1996: $257,000).
All related party transactions were on commercial terms and conditions.
F-23
63
Twelve
Six months ended months ended
31 December 31 December
1996 1997
(US dollars, in thousands)
----------------------------
25. INVESTMENTS IN AFFILIATED COMPANIES
(a) EQUITY INFORMATION
Share of affiliated company's operating (loss)
and extraordinary items after income tax $ (190) $ (2,097)
Share of affiliated company's retained earnings (accumulated loss) not
brought to account in the consolidated accounts 1,040 (5,511)
Share of affiliated company's reserves
not brought to account in consolidated accounts 9,096 9,253
Share of affiliated company's share issue not participated in -- 57
Profit on transaction with affiliate (6,361) --
Carrying value of investment - at directors' valuation 1989 6,725 5,502
Asset revaluation reserve (3,119) (2,552)
Discount on acquisition 2,232 2,232
----------- -----------
Equity accounted amount of investment $ 9,423 $ 6,884
----------- -----------
(b) Particulars of investments - affiliated companies
- ---------------------------------------------------------------------------------------------------------------------------
NAME PRINCIPAL PLACE OF INTEREST CARRYING VALUE
ACTIVITIES INCORPORATION 31 December 31 December 31 December 31 December
AND CLASS OF 1996 1997 1996 1997
SHARE % % $'000 $'000
- ---------------------------------------------------------------------------------------------------------------------------
Climax Mining Ltd Holding company Australia, ord. 44.39 43.92 6,725 5,502
and minerals
exploration
----------------------------------------------------------
30 June 30 June 31 December 31 December
(US dollars, in thousands) 1995 1996 1996 1997
----------------------------------------------------------
26. Outside equity interests
Climax Mining Ltd
- - Issued capital $ 6,914 $ -- $ -- $ --
- - Reserves 8,999 -- -- --
---------- ---------- ---------- ----------
15,913 -- -- --
---------- ---------- ---------- ----------
Interest in retained earnings (accumulated losses) at the
beginning of the financial year 1,186 (103) (6) --
Interest in consolidated profit (loss) (1996: for the period
to 23 April 1996) (1,289) 1,754 -- --
Adjustment on deconsolidation of Climax Mining Ltd -- (1,750) -- --
Foreign exchange translation 669 93 -- --
Adjustment to outside equity interests -- -- 6 --
---------- ---------- ---------- ----------
566 (6) -- --
---------- ---------- ---------- ----------
Total outside equity interests $ 16,479 $ (6) $ -- $ --
---------- ---------- ---------- ----------
F-24
64
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
(US dollars, in thousands) 1995 1996 1996 1997
- ---------------------------------------------------------------------------------------------------------------------------------
27. NOTES TO THE STATEMENTS OF CASH FLOWS
(a) Reconciliation of cash
For the purposes of the statements of cash flows, cash includes
cash on hand and at bank and short-term deposits at call, net of
outstanding bank overdrafts. Cash as at the end of the financial
year as shown in the statements of cash flows is reconciled to the
related items in the balance sheets as follows:
Cash at financial period end $ 1,339 $ 3,541 $ 12,528 $ 19,171
---------- ---------- ---------- ----------
(b) Reconciliation of operating profit after income tax to
net cash provided by operating activities:
Operating profit after income tax $ 1,167 $ 12,126 $ 14,899 $ 15,404
Add (less) items classified as investing or financing activities
(Profit) loss from sale of:
- - investments -- (8,520) (9,939) --
- - marketable equity securities held for trading (133) 25 -- --
- - property, plant and equipment -- (278) (6) (11)
- - investment in oil and gas property (3,183) -- -- --
Dividends received (2) -- -- --
Property rentals received (869) (1,019) -- --
Add (less) non-cash items:
Amortization of:
- - exploration and development expenditures 6,658 17,945 13,663 55,754
- - borrowing costs and discount on notes -- -- -- 190
- - deferred stripping 957 418 -- --
Depreciation of property, plant and equipment 854 3,980 1,715 7,975
Write off (write back) of :
- - exploration expenditures 841 1,510 2,831 10,454
- - marketable equity securities held for trading 95 (20) (10) (132)
- - bad debts 1 -- -- --
- - investment property 396 (318) -- --
Provision against exploration expenditures 66 -- -- --
Provisions:
- - employee entitlements 90 (102) 4 303
- - restoration and reclamation 794 1,318 318 1,606
- - exploration loan to affiliated company -- 842 -- --
---------- ---------- ---------- ----------
Net cash provided by operating activities
before changes in assets and liabilities 7,732 27,907 23,475 91,543
(Increase) decrease in inventories (3,062) 5,087 (4) 2
(Increase) decrease in trade, other debtors and prepayments (978) (5,482) (2,946) (2,327)
(Increase) decrease in future income tax benefit (3,745) (9,931) (4,475) 256
(Decrease) increase in trade creditors and accruals 425 2,043 1,139 60
(Decrease) increase in other provisions (1,276) (837) -- --
(Decrease) increase in income tax payable 502 4,366 82 (249)
(Decrease) increase in deferred tax payable 4,633 11,103 10,643 7,303
---------- ---------- ---------- ----------
Net cash provided by operating activities $ 4,231 $ 34,256 $ 27,914 $ 96,588
---------- ---------- ---------- ----------
F-25
65
28. RECONCILIATION FROM AUSTRALIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES TO
UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
PRINCIPAL DIFFERENCES BETWEEN AUS GAAP AND US GAAP
Financial statements in the United States are prepared in accordance with
accounting principles generally accepted in the United States ("US GAAP"). In
Australia financial statements are prepared in accordance with applicable
accounting standards issued by the Australian Accounting Standards Board and
codified in the Australian Corporations Law ("AUS GAAP"). The principal
differences between AUS GAAP and US GAAP which are material to the preparation
of the consolidated financial statements of the Company are set out below in
this note.
The differences between AUS GAAP and US GAAP related to foreign currency
transaction gains and losses only affect the accounts of Climax Mining Ltd. The
effect of such differences are included in the US GAAP reconciliation tables
included in Note 30(a) under the caption "Climax Mining Ltd" Note 30(b) contains
condensed consolidated financial data of Climax Mining Ltd on a US GAAP basis.
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.
US GAAP oil and gas operations
For US GAAP reporting the Company has adopted the successful efforts method to
account for its oil and gas exploration, evaluation and development expenditure.
The main difference from AUS GAAP is that under US GAAP all general, geological
and geophysical costs are expensed as incurred. In both US GAAP and AUS GAAP
drilling costs of successful wells are capitalized and drilling costs relating
to unsuccessful exploration wells are written off.
Oil and gas properties are periodically assessed for impairment and are written
down at such time an impairment is determined.
US GAAP MINING OPERATIONS
Under US GAAP exploration expenditures in the search for mineralized deposits is
expensed as incurred. Once it is determined that mineral reserves exist and are
commercially recoverable, expenditure is capitalized as development expenditure.
CONSOLIDATED ENTITIES
Under AUS GAAP the Company was required to consolidate Climax Mining Ltd
("Climax") until it ceased to be a "controlled entity" on 23 April 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 ownership by one enterprise (directly or
indirectly) of over 50% of the outstanding voting shares of another enterprise
is generally the condition requiring consolidation. As the Company owned between
44.4% and 49.9% of Climax's outstanding voting shares during the relevant
periods, for US GAAP purposes the investment is an affiliate; thus, the results
of operations, financial condition and cash flows of Climax are recorded 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.
Under US GAAP investments in affiliates are accounted for under the equity
method of accounting. The equity method of accounting requires the investor to
recognize its proportionate share of the affiliate's net profit or loss for the
period. Dividends received or receivable are accounted for as reductions in the
carrying value of the investor's investment.
MARKETABLE EQUITY SECURITIES
Under AUS GAAP marketable equity securities held for trading purposes are stated
at the lower of aggregate cost and net realizable value. Marketable equity
securities held for investment are stated at cost or at a directors' valuation.
Under US GAAP Statement of Financial Accounting Standards No. 115 (SFAS 115),
"Accounting for Certain Investments in Debt and Equity Securities" requires
investments to be classified into one of three categories and accounted for as
follows: debt securities that the Company has the positive intent and ability to
hold to maturity are classified as "held-to-maturity securities" and reported at
amortized cost; debt and marketable equity securities that are bought and held
principally for the purpose of selling them in the near term are classified as
"trading securities" and reported at fair value, with unrealized gains and
losses included in earnings; and debt and marketable equity securities not
classified as either held-to-maturity securities or trading securities are
classified as "available-for-sale securities" and reported at fair value, with
unrealized gains and losses excluded from earnings and reported in a separate
component of shareholders' equity.
F-26
66
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 profit and loss account except where a previous
revaluation decrement has been recorded for that class of assets through the
profit and loss account. An impairment or downwards revaluation is taken through
the profit and loss account 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, rather than the profit and loss
account.
US GAAP does not permit the upward revaluation of assets. US GAAP requires that
a permanent diminution of value be recorded in the profit and loss account when
an asset is impaired. Once impairment is recorded, subsequent recoveries through
the profit and loss account are not allowed except when the asset is sold.
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. Under US GAAP all foreign exchange transaction gains or losses are
recognized as a current gain or loss in the statement of operations.
TAXATION
Accounting under AUS GAAP is under the liability method and is equivalent in
most major respects to United States Statement of Financial Accounting Standards
No. 109 (SFAS 109), "Accounting for Income Taxes". SFAS 109 requires tax assets
and liabilities to be recognized for the estimated 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 the enacted tax rates in effect for
the year in which those temporary differences are expected to be recovered or
settled. Under SFAS 109 the effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the year that includes the
enactment date.
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. Under US GAAP a valuation allowance
is provided on deferred tax assets to the extent it is not "more likely than not
that" such deferred tax assets will be realized. 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 US GAAP employee shares, options issued under the Employee Share and
Option Plan and options issued to consultants result in compensation expense.
Effective for all options and shares granted after 1 July 1996 under the
employee plans, the Company has adopted Statement of Financial Accounting
Standards No. 123 (SFAS 123), "Accounting for Stock-Based Compensation", for
financial statement reporting. SFAS 123 specifies that the stock compensation
will be accounted for based on the fair value method rather than the intrinsic
value method discussed below in APB Opinion No. 25. The fair values of the
shares and options are calculated by taking into account the exercise price,
expected life, current price of underlying stock, expected volatility of the
underlying stock, expected dividend yield and the risk free interest rate. The
expected life, volatility, dividend yield and risk free interest rates used in
determining the fair value of options granted in the year ended 31 December 1997
were respectively, 1.5 to 2.5 years (weighted average 2.1 years); 30%; nil: and
5.8% to 6.5% per annum (weighted average 6.1% per annum). For the six month
period ended 31 December 1996 the expected life, volatility, dividend yield and
risk free interest rate were respectively, 2.1 to 3.5 years (weighted average
3.0 years); 30%; nil; and 7.1% to 8.4% per annum (weighted average 8% per
annum). The fair value was determined using the Black-Scholes valuation
methodology.
All shares and options granted before 30 June 1996 will continue to be accounted
for under APB Opinion No. 25, "Accounting for Stock Issued to Employees" which
treats the shares and options granted which do not vest until the Company's
shares have appreciated to a specified level as a variable plan. The measurement
date under US GAAP to measure total compensation cost is the first date upon
which both the number of shares that an individual employee is entitled to
receive and the exercise price are known. The amount of the compensation cost to
be recorded over the service period is the difference between the quoted market
price of the shares as at the measurement date and the amount to be paid by the
employee. In the calculation of this cost in respect of shares issued under the
Employee Share Plan the amount to be paid by the employee is adjusted for the
effect of discounting the interest free loans to their estimated present value.
Compensation cost is recorded in the periods when the hurdle rate is met based
on the quoted market price of the Company's shares.
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 the final costs.
F-27
67
PRESENTATION OF EQUITY
Outside equity interests (minority interests) are included as part of the total
shareholders' equity under AUS GAAP. US GAAP requires that these outside equity
interests be excluded from the determination of total shareholders' equity.
Under AUS GAAP the loans provided under the Employee Share Plan (see Note 18)
are recorded as non-current receivables on the consolidated balance sheets.
Under US GAAP such receivables are recorded as a reduction from shareholders'
equity.
ABNORMAL ITEMS
Under AUS GAAP items of revenue and expense which are considered abnormal by
reason of their size and effect on the results for the year are classified
separately as abnormal items in the profit and loss account of operations. While
these types of items may be separately identified for purposes of US GAAP, they
would normally be shown as part of continuing operations and are not presented
separately in the statement of operations.
EXTRAORDINARY ITEM
Under AUS GAAP items of revenue and expense which are attributable to
transactions or events outside the normal operations of a company and are not of
a recurring nature are classified as extraordinary items in the statement of
operations. In the year ended 30 June 1996 the Company recorded an extraordinary
item relating to the AUS GAAP accounting treatment of the deconsolidation of
Climax Mining Ltd, which ceased to be a controlled entity during the year. This
item does not occur in the US GAAP financial statements as under US GAAP the
Company accounts for Climax Mining Ltd under the equity method of accounting.
The item is included as a reconciling item between the AUS GAAP and US GAAP
statements of operations.
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 reclamation
provisions are accounted for on a prospective basis and only affect future
provisions made on the unit of production basis.
OTHER
Under AUS GAAP the Company does not record depreciation expense on buildings
held as investment properties. US GAAP requires depreciation expense to be
recorded while the investment properties are generating rent revenue and are not
held for sale.
DISCLOSURE OF REVENUES
Under AUS GAAP oil and gas sales are reported gross (ie. before deducting
government and over riding royalties) with royalties being reported as an
expense. Under US GAAP oil and gas sales are shown net of royalties, with no
expense relating to royalties.
NET EARNINGS PER ORDINARY SHARE
The Company adopted Statement of Financial Accounting Standards No. 128
"Earnings per Share" on a retroactive basis in 1997. Under both AUS GAAP and US
GAAP, basic earnings per ordinary share has been computed by dividing AUS GAAP
net earnings before extraordinary items and USGAAP net earnings after
extraordinary items, respectively by the weighted average number of ordinary
shares outstanding during the respective year.
Under AUS GAAP, diluted earnings per share has been computed by dividing net
earnings before extraordinary items under AUS GAAP (adjusted for interest income
after tax on the assumed funds generated by the exercise of options) by the
weighted average number of ordinary shares on issue assuming all options had
been exercised. Under US GAAP, diluted earnings per share has been computed by
dividing net earnings after extraordinary items under US GAAP by the weighted
average number of ordinary and ordinary equivalent shares outstanding during the
respective year. Ordinary share equivalents include potentially dilutive share
options. In measuring the dilutive effect of such options, the "treasury stock"
method is utilized. Under this method the assumed proceeds received or
receivable associated with the share issuance are assumed to have been used to
repurchase outstanding shares using the average market price of the period.
F-28
68
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
(US dollars, in thousands) 1995 1996 1996 1997
- -----------------------------------------------------------------------------------------------------------------------------
29. FINANCIAL STATEMENTS UNDER US GAAP
The financial statements of the Company under US GAAP
after adjusting for the items presented in the succeeding
reconciliation, are as follows:
STATEMENTS OF OPERATIONS
Oil and gas sales (net of royalties) $ 17,031 $ 51,150 $ 37,521 $ 125,139
----------- ----------- ----------- -----------
Operating expenses
Lease operating expenses 3,808 6,892 3,279 11,527
Depletion, depreciation and amortization 5,661 21,098 15,368 63,903
Exploration expenditure 2,697 3,320 5,249 17,782
General, administrative and other expenses 4,543 7,001 3,339 9,001
Stock compensation expense 102 1,749 677 1,461
----------- ----------- ----------- -----------
Total operating expenses 16,811 40,060 27,912 103,674
----------- ----------- ----------- -----------
Income from operations 220 11,090 9,609 21,465
Other income 52 223 -- 132
Profit on sale of assets 4,296 257 7,208 31
Interest expense (1,725) (3,687) (1,472) (6,022)
Interest income 210 485 822 1,685
Equity in income (loss) of affiliates (3,864) 282 (1,326) (1,595)
----------- ----------- ----------- -----------
Income (loss) before tax (811) 8,650 14,841 15,696
Income tax benefit (expense) 465 (895) (3,888) (5,416)
----------- ----------- ----------- -----------
Net income (loss) $ (346) $ 7,755 $ 10,953 $ 10,280
----------- ----------- ----------- -----------
Earnings per share:
Basic and diluted earnings per ordinary share $ (0.01) $ 0.09 $ 0.10 $ 0.10
Basic and diluted earnings per American Depositary Receipt
(based on the ratio of five ordinary shares to one
American Depositary Receipt) $ (0.02) $ 0.45 $ 0.52 $ 0.48
The Company issued its first American Depositary Receipts in July 1996 and the
net income per ADR is for comparative purposes only.
F-29
69
Twelve
Six months ended months ended
31 December 31 December
(US dollars, in thousands) 1996 1997
- ------------------------------------------------------------------------------------------------
29. FINANCIAL STATEMENTS UNDER US GAAP (CONTINUED)
BALANCE SHEETS
Current assets
Cash and cash equivalents $ 12,528 $ 19,171
Accounts receivable 11,855 13,978
Deferred income taxes 76 1,446
Other 382 786
----------- -----------
Total current assets 24,841 35,381
----------- -----------
Non-current assets
Proved oil and gas properties 131,933 227,049
Unproved oil and gas properties 7,276 20,759
Production facilities 38,049 66,956
Other 1,040 1,527
Less accumulated depletion, depreciation and amortization (44,664) (106,977)
----------- -----------
Net oil and gas properties 133,634 209,314
----------- -----------
Investment in Climax Mining Ltd group 2,178 --
Other investments 127 6
Other assets 303 3,261
----------- -----------
Total assets 161,083 247,962
----------- -----------
Current liabilities
Accounts payable and accrued liabilities 25,339 27,969
----------- -----------
Total current liabilities 25,339 27,969
----------- -----------
Long-term liabilities
Long-term debt less current maturities 37,000 99,630
Deferred income taxes 5,559 15,612
Other accrued liabilities 1,784 3,596
----------- -----------
Total long-term liabilities 44,343 118,838
----------- -----------
Shareholders' equity
Share capital 16,344 16,491
Additional paid-in capital 102,421 105,269
Subscriptions receivable (2,740) (2,406)
Unrealized gain (loss) on marketable securities 444 (13)
Foreign currency translation reserve (57) (3,455)
Retained deficit (25,011) (14,731)
----------- -----------
Total shareholders' equity 91,401 101,155
----------- -----------
Total liabilities and shareholders' equity $ 161,083 $ 247,962
----------- -----------
Retained deficit at 31 December 1996 and 1997 includes a debit amount of $39,339
which relates to the buy-back of shares in the Company.
F-30
70
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
(US dollars, in thousands) 1995 1996 1996 1997
- -------------------------------------------------------------------------------------------------------------------------------
STATEMENTS OF CASH FLOWS
Cash flows from operating activities
Net income (loss) $ (346) $ 7,755 $ 10,953 $ 10,280
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
- - (earnings) loss in affiliates 3,864 (282) 1,326 1,595
- - distributions received from affiliates 429 432 -- --
- - write down of investment 173 9 (10) --
- - depletion, depreciation and amortization 5,661 21,098 15,368 63,903
- - dry holes and abandonments 360 1,145 -- 10,454
- - loss (gain) on sale of assets (4,296) (257) (7,208) (31)
- - taxation payable 446 194 118 (9)
- - deferred tax (911) 701 3,770 5,425
- - translation (gains) losses (69) 101 (381) --
- - employee stock compensation 102 1,749 677 1,461
- - interest income on subscriptions receivable (102) (196) (103) (190)
- - amortization of borrowing costs and discount on notes -- -- -- 190
Changes in operating assets and liabilities:
- - accounts receivable 106 (4,921) (4,382) (2,124)
- - other current assets (530) (947) 1,436 (404)
- - accounts payable and accrued liabilities 5,486 11,754 4,640 2,625
- - other accrued liabilities (801) 266 250 261
---------- ---------- ---------- ----------
Net cash provided by operating activities 9,572 38,601 26,454 93,436
---------- ---------- ---------- ----------
Investing activities
Additions to oil and gas properties (28,952) (75,467) (48,419) (148,480)
Additions to other assets (10) -- (32) --
Proceeds of asset disposals 5,500 244 20 60
Proceeds of investment sales -- 3,651 13,703 --
Investment in affiliates (1,097) (1,488) -- --
Restricted deposit -- (1,501) 1,501 --
Repayment from affiliate -- 1,333 -- --
---------- ---------- ---------- ----------
Net cash used in investing activities (24,559) (73,228) (33,227) (148,420)
---------- ---------- ---------- ----------
Financing activities
Proceeds from note issue - unsecured -- -- -- 96,446
Proceeds from borrowings - secured loans 20,685 28,650 7,000 21,000
Repayments of borrowings - secured loans (5,429) (8,770) (22,000) (58,000)
Issuance of ordinary shares 35 17,635 71,944 1,542
Buy-back of ordinary shares -- -- (41,184) --
Repayment of Employee Share Plan loan -- 219 -- 524
---------- ---------- ---------- ----------
Net cash provided by financing activities 15,291 37,734 15,760 61,512
---------- ---------- ---------- ----------
Effect of exchange rate changes on cash 1 41 -- 115
---------- ---------- ---------- ----------
Increase in cash and cash equivalents 305 3,148 8,987 6,643
Cash and cash equivalents at the beginning of the period 88 393 3,541 12,528
---------- ---------- ---------- ----------
Cash and cash equivalents at the end of the period $ 393 $ 3,541 $ 12,528 $ 19,171
---------- ---------- ---------- ----------
Supplemental disclosures of cash flow information
Cash paid during the period for:
Interest $ 1,729 $ 3,746 $ 1,472 $ 6,022
Income taxes -- 493 306 136
Non-cash activities
During certain years 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 increased (decreased)
by $ 552 $ (243) $ -- $ --
F-31
71
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
29.FINANCIAL STATEMENTS UNDER US GAAP (CONTINUED)
During the year the increase (decrease) in market value of
marketable equity securities increased (decreased) the
investment balance and equity account - unrealised gain
(loss) on marketable equity securities held by affiliates $ 1,393 $ (2) $ 872 $ (89)
During the year marketable equity securities were disposed of
resulting in a decrease in the investment balance and the equity
account -unrealized gain (loss) on marketable equity securities
held by affiliates -- (1,534) -- --
Deferred taxes associated with the movements from the
above- mentioned transactions caused the equity and
deferred taxation balances to change by $ 642 $ (640) $ (314) $ --
30. ADDITIONAL DISCLOSURES REQUIRED UNDER US GAAP
(a) Reconciliation of net income (loss) and shareholders'
equity from Australian GAAP to US GAAP
Net income in accordance with Australian GAAP $ 2,456 $ 5,246 $ 14,899 $ 15,404
Adjustments for:
Climax Mining Ltd (3,244) (623) (1,326) (1,596)
Deconsolidation of Climax Mining Ltd -- 5,126 -- --
Oil and gas exploration expenditure (2,414) (1,829) (2,418) (6,316)
Oil and gas exploration amortized 84 667 214 1,378
Sale of oil and gas property 1,129 -- -- --
Sale of investment -- -- (2,737) --
Rehabilitation expenses (439) 129 114 56
Deferred compensation expense (401) (202) 117 280
Stock compensation expense (102) (1,749) (677) (1,461)
Interest income on subscriptions receivable 102 196 102 190
Other (148) (39) -- --
Tax effect of US GAAP adjustments 2,631 833 2,665 2,345
----------- ----------- ----------- -----------
Net income (loss) in accordance with US GAAP (346) 7,755 10,953 10,280
----------- ----------- ----------- -----------
Shareholders' equity excluding minority interests in
accordance with Australian GAAP at period end 33,233 59,131 105,670 117,404
Adjustments for:
Equity in Climax Mining Ltd (3,416) (2,356) (6,125) (5,678)
Oil and gas exploration expenditure (6,641) (7,592) (10,011) (16,327)
Oil and gas exploration amortized 1,036 752 966 2,344
Rehabilitation expenses (439) (310) (196) (140)
Deferred compensation expense (401) (603) (485) (205)
Additional paid-in capital in respect of employee shares (921) (870) (882) (882)
Subscriptions receivable in respect of employee shares (2,001) (2,074) (3,084) (2,406)
Cumulative effect of US GAAP adjustments on foreign
currency translation reserve 93 (213) 20 655
Other (1) -- -- (20)
Cumulative tax effect of US GAAP adjustments 362 1,614 5,528 6,410
----------- ----------- ----------- -----------
Shareholders' equity in accordance with US GAAP at
period end $ 20,904 $ 47,479 $ 91,401 $ 101,155
----------- ----------- ----------- -----------
(b) Selected consolidated financial data under US GAAP
for Climax Mining Ltd and its subsidiaries
Revenues $ 6,224 $ 7,866 $ -- $ --
----------- ----------- ----------- -----------
Income (loss) from operations before interest and taxation (8,853) 5,174 35,451 (9,569)
----------- ----------- ----------- -----------
Net income (loss) $ (7,699) $ 1,349 $ 36,638 $ (9,063)
----------- ----------- ----------- -----------
F-32
72
31 December 31 December
1996 1997
(US dollars, in thousands)
------------ ------------
Current assets $ 34,877 $ 17,344
----------- -----------
Non-current assets
Marketable equity securities 3,768 2,073
Other non-current assets 24,127 20,831
----------- -----------
27,895 22,904
----------- -----------
Total assets 62,772 40,248
----------- -----------
Current liabilities 3,941 4,495
Non-current liabilities 4,497 373
Shareholders' equity 54,334 35,380
----------- -----------
Total liabilities and shareholders' equity $ 62,772 $ 40,248
----------- -----------
Included in shareholders' equity are the following unrealised gains
(losses) on marketable equity securities net of tax effect:
- - other marketable equity securities $ 1,001 $ (107)
31. 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 30 June 1994, 1995, 1996
and 31 December 1996 and 1997 were based on studies performed by Ryder Scott
Company.
No major discovery or other favourable or adverse event subsequent to 31
December 1997 is believed to have caused a material change in the estimates of
proved or proved developed reserves as of that date.
Estimated net quantities of oil and gas reserves
The following table sets forth the Company's net proved reserves (at 15.025
pounds per square inch absolute), including the changes therein, and proved
developed reserves (all within the United States) at the end of each of the
three fiscal periods in the period ended 31 December 1997, 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 periods ended 30 June 1995 and 30 June 1996 was 29 Mbbls and 22
Mbbls, respectively. The interest in EP129 was disposed of in the period ended
30 June 1996.
-------------------------
CRUDE NATURAL
OIL GAS
(MBbl) (MMcf)
---------- ----------
Proved developed and undeveloped reserves:
30 June 1994 2,650 12,830
Revisions of previous estimates 2,861 293
Extensions, discoveries and other additions 2,210 11,194
Production (583) (3,556)
Sales of reserves in place (257) (434)
---------- ----------
30 June 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)
---------- ----------
F-33
73
31. SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)
-------------------------
CRUDE NATURAL
OIL GAS
(MBbl) (MMcf)
---------- ----------
30 June 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)
---------- ----------
31 December 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)
---------- ----------
31 December 1997 10,641 122,149
---------- ----------
Proved developed reserves:
30 June 1995 4,076 12,003
30 June 1996 8,084 31,043
31 December 1996 6,670 43,133
31 December 1997 8,430 88,199
-----------------------------------------------------------
30 June 31 December
1995 1996 1996 1997
(US dollars, in thousands)
-----------------------------------------------------------
Capitalized costs for oil and gas producing activities consist
of the following:
Proved properties $ 61,988 $ 118,462 $ 169,982 $ 294,005
Unproved properties 5,171 10,890 7,276 20,759
----------- ----------- ----------- -----------
Total capitalized costs 67,159 129,352 177,258 314,764
Accumulated depletion, depreciation and amortization (19,685) (29,303) (44,349) (106,392)
----------- ----------- ----------- -----------
Net capitalized costs $ 47,474 $ 100,049 $ 132,909 $ 208,372
----------- ----------- ----------- -----------
--------------------------------------------------------
Twelve
Twelve months ended Six months ended months ended
30 June 30 June 31 December 31 December
1995 1996 1996 1997
----------- ----------- ----------- -----------
Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:
Lease acquisition $ 2,422 $ 7,577 $ 44 $ 8,437
Exploration 18,279 53,974 46,147 115,523
Development 10,148 15,345 6,966 31,327
----------- ----------- ----------- -----------
Total costs incurred $ 30,849 $ 76,896 $ 53,157 $ 155,287
----------- ----------- ----------- -----------
Standardized measure of discounted future net cash flows relating to proved oil
and gas reserves
The following information has been developed utilising 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 realising future net oil and gas revenues; and (4) future net
revenues may be subject to different rates of income taxation.
F-34
74
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 31 December 1997 approximately 19.4 million MMbtu of the
Company's future gas production and 1.6 million barrels of oil were subject to
such positions. Future cash inflows were reduced by estimated future
development, abandonment and production costs based on period-end costs in order
to arrive at net cash flow before tax. Future income tax expense has been
computed by applying period-end statutory tax rates to aggregate future pre-tax
net cash flows, reduced by the tax basis of the properties involved and tax
carry forwards. Use of 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:
-----------------------------------------------------------
30 June 30 June 31 December 31 December
1995 1996 1996 1997
(US dollars, in thousands)
-----------------------------------------------------------
Future cash inflows $ 154,139 $ 369,921 $ 479,220 $ 472,470
Future production costs (32,022) (51,244) (58,367) (101,765)
Future development and abandonment costs (19,600) (55,610) (47,873) (53,851)
Future income tax expense (21,143) (61,956) (102,669) (64,064)
----------- ----------- ----------- -----------
Future net cash flows after income taxes 81,374 201,111 270,311 252,790
10% annual discount for estimated timing of cash flows (16,238) (40,569) (46,930) (48,676)
----------- ----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 65,136 $ 160,542 $ 223,381 $ 204,114
----------- ----------- ----------- -----------
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 $ 30,122 $ 65,136 $ 160,542 $ 223,381
----------- ----------- ----------- -----------
Sales and transfers of oil and gas produced, net of production
costs (12,482) (44,469) (34,180) (113,462)
Net changes in prices and production costs 4,532 19,569 75,645 (142,243)
Extensions, discoveries and improved recoveries, net of
future production and development costs 76,642 161,906 43,031 134,467
Net changes due to revision in quantity estimates (1,220) 9,697 6,532 40,994
Development costs incurred during the financial year- 14,820 3,728 1,050
Sales of reserves in place (3,140) -- -- --
Change in estimated future development costs (4,050) (40,578) (3,313) (5,674)
Accretion of discount (13,174) 12,423 6,783 32,481
Net change in income taxes (12,094) (37,962) (35,387) 33,120
----------- ----------- ----------- -----------
Net increase (decrease) 35,014 95,406 62,839 (19,267)
----------- ----------- ----------- -----------
End of the period $ 65,136 $ 160,542 $ 223,381 $ 204,114
----------- ----------- ----------- -----------
The computation of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves at 31 December, 1997 was based on
average natural gas prices of approximately $2.39 per mcf and on average liquids
of approximately $17.00 per barrel. Had March 1998 prices been used, the
Company's standardized measure of discounted future net cash flows relating to
proved oil and gas reserves at 31 December, 1997 would have been reduced.
F-35
75
INDEPENDENT AUDITORS' REPORT TO THE MEMBERS OF PETSEC ENERGY LTD
We have audited the consolidated balance sheets of Petsec Energy Ltd (a company
incorporated in New South Wales, Australia) and subsidiaries as of 31 December
1996 and 1997 and the related consolidated profit and loss accounts, and
statements of cash flows for each of the years in the two year period ended 30
June 1996, the six month period ended 31 December 1996 and the twelve month
period ended 31 December 1997, 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 31 December 1996 and 1997 and the results of operations
and cash flows for each of the years in the two year period ended 30 June 1996,
the six month period ended 31 December 1996 and the twelve month period ended 31
December 1997, in conformity with accounting principles generally accepted in
Australia.
Accounting principles generally accepted in Australia vary in certain
significant respects from accounting principles generally accepted in the United
States. Application of generally accepted accounting principles in the United
States would have affected the results of operations for each of the years in
the two year period ended 30 June 1996, the six month period ended 31 December
1996 and the twelve month period ended 31 December 1997, and shareholders'
equity as at 30 June 1995 and 1996 and 31 December 1996 and 1997 to the extent
summarized in Note 30 to the consolidated financial statements.
/s/ KPMG
KPMG
Sydney, Australia
March 16, 1998
F-36
76
EXHIBIT INDEX
23.1 Consent of KPMG
23.2 Consent of Ryder Scott Company