UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
(Mark One)
[ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2004
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _________to________
Commission file number 0-28608
PETSEC ENERGY LTD
(Exact name of Registrant as specified in its charter)
NEW SOUTH WALES, AUSTRALIA
(Jurisdiction of incorporation or organization)
LEVEL 13, 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.
119,222,841 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]
Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Sections 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court.
Yes [X] No [ ]
TABLE OF CONTENTS
Page
-------
Introduction.................................................................... 3
Glossary of Certain Industry Terms.............................................. 4 - 5
PART I
Item 1. Identity of Directors, Senior Management and Advisers............ 5
Item 2. Offer Statistics and Expected Timetable.......................... 5
Item 3. Key Information.................................................. 6 - 11
Item 4. Information on the Company....................................... 12 - 20
Item 5. Operating and Financial Review and Prospects..................... 21 - 30
Item 6. Directors, Senior Management and Employees....................... 31 - 35
Item 7. Major Shareholders and Related Party Transactions................ 36 - 37
Item 8. Financial Information............................................ 37
Item 9. The Offer and Listing............................................ 38 - 39
Item 10. Additional Information........................................... 40 - 49
Item 11. Quantitative and Qualitative Disclosure about Market Risk........ 49
Item 12. Description of Securities Other Than Equity Securities .......... 50
PART II
Item 13. Defaults, Dividend Arrearages and Delinquencies.................. 50
Item 14. Material Modifications to the Rights of Security Holders and
Use of Proceeds.................................................. 50
Item 15. Controls and Procedures.......................................... 50
Item 16A. Audit Committee Financial Expert................................. 50
Item 16B. Code of Ethics................................................... 50
Item 16C. Principal Accountant Fees and Services........................... 50
Item 16D. Exemptions from the Listing Standards For Audit Committee........ 51
Item 16E. Purchases of Equity Securities by the Issuer and Affiliated
Purchasers....................................................... 51
PART III
Item 17. Financial Statements............................................. 51
Item 18. Financial Statements............................................. 51
Item 19. Exhibits......................................................... 51
Signatures...................................................................... 52
Exhibit Index................................................................... 82
2
INTRODUCTION
Unless the context otherwise indicates, references in this Form 20-F to "we",
"us", "our", "Petsec" or the "Company" are to Petsec Energy Ltd, an Australian
public company (Australian Company Number 000 602 700), and its majority-owned
subsidiaries and entities in which it owns at least a 50% ownership interest.
The reference "PEL" is used to refer to Petsec Energy Ltd, the Australian public
company, separately from its subsidiaries. The reference to "PEI" is used to
refer to Petsec Energy Inc., a wholly owned U.S. subsidiary of Petsec Energy
Ltd. The reference to "PPI" is used to refer to Petsec Petroleum Inc., also a
wholly owned U.S. subsidiary of Petsec Energy Ltd. The Company publishes
consolidated financial statements in Australian dollars as required under
Australian law and under Australian generally accepted accounting principles
("AUS GAAP"). The Company also publishes consolidated financial statements in US
dollars and under U.S. generally accepted accounting principles ("US GAAP") as
set out under Item 18 in this Form 20-F. All financial information in this Form
20-F is based on US GAAP.
This report covers the years ended December 31, 2002, 2003 and 2004.
References to "US", "U.S.", "USA" and "U.S.A." are to the United States of
America. References to "US dollars" or "US$" or "$" are to United States dollars
and references to "A$" are to Australian dollars.
3
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 or expected to exceed completion costs, 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.
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.
Pay. Oil or gas saturated rock capable of producing oil or gas.
4
Present value or PV10. When used with respect to oil and natural gas
reserves, the estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future development costs,
using prices and costs in effect as of the date indicated, without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that
are expected to be recovered from completion intervals currently open in
existing wells and capable of production to market.
Proved reserves. The estimated quantities of crude oil, natural gas
and natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can
be drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore
in another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of costs of
production.
Undeveloped acreage. Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.
Working interest or W.I. The operating interest which gives the
owner the right to drill, produce and conduct operating activities on the
property and a share of production.
PART I
ITEM 1 - IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
Not applicable
ITEM 2 - OFFER STATISTICS AND EXPECTED TIMETABLE
Not applicable
5
ITEM 3 - KEY INFORMATION
A. 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 years indicated. The financial data for each of the five years ended
December 31, 2000, 2001, 2002, 2003 and 2004 is derived from the Company's US
Dollar Financial Statements, which were prepared under US GAAP. The following
data should be read in conjunction with "Item 5 - Operating and Financial Review
and Prospects" and the financial statements and notes thereto included elsewhere
in this Annual Report.
Year ended December 31
--------------------------------------------------------------
2000(1) 2001(1) 2002 2003 2004
(In thousands, except per share and per ADR data)
INCOME STATEMENT DATA
Oil and gas sales (net of royalties payable) $ 8,257 $ - $ - $ 23,270 $ 32,575
Oil and gas royalties - - 201 1,949 223
--------- --------- ---------- --------- ---------
Total revenues $ 8,257 $ - $ 201 $ 25,219 $ 32,798
--------- --------- ---------- --------- ---------
Lease operating expenses 1,657 - - 1,557 1,776
Depletion, depreciation and amortization 4,845 28 34 6,574 12,361
Exploration expenditure 365 422 1,176 1,329 1,452
Dry hole and abandonment costs 611 877 1,066 - 4,119
Major maintenance expense - - - - 592
Impairment expense - - - 38 201
General, administrative and other expenses 3,625 1,264 1,691 3,519 4,657
Stock compensation expense 138 11 40 90 83
--------- --------- ---------- --------- ---------
Total operating expenses 11,241 2,602 4,007 13,107 25,241
Profit (loss) on sale of assets 592 9 (8) - 2
--------- --------- ---------- --------- ---------
Income (loss) from operations (2,392) (2,593) (3,814) 12,112 7,559
Other income 1 200 137 364 89
Interest expense (3,378) - - (10) (32)
Interest income 1,037 447 136 142 311
--------- --------- ---------- --------- ---------
Income (loss) before income tax and extraordinary items (4,732) (1,946) (3,541) 12,608 7,927
Income tax benefit (expense) (10) 8 254 492 9,807
--------- --------- ---------- --------- ---------
Net income (loss) before extraordinary items $ (4,742) $ (1,938) $ (3,287) $ 13,100 $ 17,734
Extraordinary items (net of nil tax)
Recognition of deferred gain on subsidiary emergence
from bankruptcy - 37,147 - - -
Distribution from bankruptcy trustee - 1,103 - - -
--------- --------- ---------- --------- ---------
Net income (loss) $ (4,742) $ 36,312 $ (3,287) $ 13,100 $ 17,734
--------- --------- ---------- --------- ---------
BASIC AND DILUTED EARNINGS PER SHARE
Earnings (loss) before extraordinary items per share $ (0.04) $ (0.02) $ (0.03) $ 0.12 $ 0.15
Extraordinary items per share - 0.36 - - -
--------- --------- ---------- --------- ---------
Earnings (loss) per share $ (0.04) $ 0.34 $ (0.03) $ 0.12 $ 0.15
--------- --------- ---------- --------- ---------
Earnings (loss) before extraordinary items per ADR (2) $ (0.22) $ (0.10) $ (0.17) $ 0.62 $ 0.74
Extraordinary items per ADR - 1.82 - - -
--------- --------- ---------- --------- ---------
Earnings (loss) per ADR $ (0.22) $ 1.72 $ (0.17) $ 0.62 $ 0.74
--------- --------- ---------- --------- ---------
Weighted average number of ordinary shares outstanding 106,589 105,752 105,736 105,736 118,830
CASH FLOW DATA
Net cash provided by (used in) operating activities $ 518 $ (1,166) $ (2,728) $ 18,589 $ 22,032
Net cash provided by (used in) investing activities (6,136) 104 (8,170) (13,574) (26,046)
Net cash provided by (used in) financing activities (2,185) - - 6,851 1,070
6
BALANCE SHEET DATA (at period-end)
Total assets $ 16,036 $ 15,096 $ 14,206 $ 38,444 $ 63,527
Short-term loans - - - 328 1,175
Total shareholders (deficit) equity (22,953) 13,584 10,248 23,203 50,899
Share capital 120,789 120,661 120,701 120,791 130,106
Number of ordinary shares outstanding 105,786 105,736 105,736 105,736 119,223
- ------------
(1) On April 13, 2000, PEI filed a voluntary petition under Chapter 11 of the
U.S. Bankruptcy Code (the "Bankruptcy Code"). As a result of that filing, the
Company no longer had effective control over PEI and consequently PEI was
deconsolidated for financial accounting reporting purposes as of that date. On
January 16, 2001, PEI emerged as a reorganized entity under the Bankruptcy Code
and the Company regained control over PEI. The results of PEI have been
consolidated into the Company from that date forward. (2) American Depository
Receipt. See Item 9.C.
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 Noon Buying Rate at May 31, 2005 was 0.7605.
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
---------------------------------------------
End of
Period Average * High Low Period
- ---------------------------- --------- ------ ------ ------
Year ended December 31, 1999 0.6444 0.6705 0.6179 0.6560
Year ended December 31, 2000 0.5746 0.6386 0.5162 0.5489
Year ended December 31, 2001 0.5075 0.5714 0.4812 0.5062
Year ended December 31, 2002 0.5391 0.5772 0.5075 0.5598
Year ended December 31, 2003 0.6515 0.7442 0.5617 0.7431
Year ended December 31, 2004 0.7341 0.7992 0.6813 0.7784
November 2004 0.7709 0.7930 0.7223 0.7826
December 2004 0.7675 0.7798 0.7489 0.7784
January 2005 0.7658 0.7786 0.7543 0.7739
February 2005 0.7811 0.7940 0.7672 0.7861
March 2005 0.7848 0.7985 0.7713 0.7713
April 2005 0.7722 0.7798 0.7633 0.7778
May 2005 0.7664 0.7804 0.7545 0.7605
- -----------
* 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 Australian Stock Exchange Limited ("ASX") and, as a
result, are likely to affect the market price of the Company's American
Depository Receipts ("ADRs") in the United States. Such fluctuations also would
affect the US dollar amounts received by holders of ADRs on conversion by the
Bank of New York ("Depositary") of cash dividends, if any, paid in Australian
dollars on the Ordinary Shares underlying the ADRs.
The Company's operating activities are primarily conducted through
PEI and PPI, two of PEL's wholly owned U.S. operating subsidiaries, and its
transactions are denominated predominantly in US dollars. PEI's operations are
conducted in the U.S. and PPI's exploration activities are conducted primarily
in China with joint operating arrangement budgets denominated 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. Such fluctuations could materially
affect the Company's financial results as reported in Australian dollars.
The Company has not paid any dividends for the fiscal years ended
December 31, 2000, 2001, 2002, 2003 and 2004.
7
B. CAPITALIZATION AND INDEBTEDNESS
Not applicable.
C. REASONS FOR THE OFFER AND USE OF PROCEEDS
Not applicable.
D. RISK FACTORS
OUR GROWTH PROSPECTS MAY BE LIMITED BECAUSE WE HAVE LIMITED OPERATIONS AND
PROPERTIES WITH PROVED RESERVES OR PRODUCTION.
At December 31, 2004, our principal assets consisted of cash,
receivables and interests in proved and unproved oil and natural gas properties.
Our proved reserves are located in six Gulf of Mexico offshore leases of which
only four were producing at December 31, 2004. Because we have limited capital
resources, and our operating cash flow will be limited by the number of our
producing properties, our growth prospects may be limited. For the immediate
future, our prospects for growth will depend primarily upon our ability to
expand our production base using cash flow generated from our limited number of
producing properties.
WE MAY NOT BE ABLE TO FIND OR ACQUIRE SIGNIFICANT PROVED RESERVES.
Our future natural gas and oil production is highly dependent upon
our level of success in finding, developing or acquiring reserves that are
economically recoverable. The business of exploring for, developing or acquiring
reserves is capital intensive and uncertain. We may be unable to make the
necessary capital investment to maintain or expand our oil and natural gas
reserves since cash flow from operations is limited by the number of our
producing properties and external sources of capital are limited. In addition,
most of our leases with working interests are in the Gulf of Mexico. In general,
the volume of production from oil and natural gas properties declines as
reserves are depleted. The decline rates depend on reservoir characteristics.
Gulf of Mexico reservoirs experience steep declines, while the declines in
long-lived fields in other regions are lower. Any future reserves discovered on
our existing leases will decline as they are produced unless we acquire
additional properties with proved reserves. Given these uncertainties and
limitations, we cannot assure you that our future exploration, development and
acquisition activities will result in significant proved reserves or that we
will be able to drill productive wells at acceptable costs.
WE MAY NOT BE ABLE TO FUND OUR PLANNED CAPITAL EXPENDITURES.
In the past, we have spent a substantial amount of capital for the
development, exploration, acquisition and production of oil and natural gas
reserves. Substantial capital expenditures are required to access reserves and
undertake a drilling program to find new reserves. Our capital expenditures
including acquisitions were $29.3 million during 2004. We expect our total
capital expenditures in 2005 to be at least $28.0 million, including $2.0
million for anticipated lease awards in the Gulf of Mexico. The funding of our
future capital expenditures is primarily dependent upon the generation of
sufficient cash flow from our operating activities and proceeds which may be
raised from time-to-time by equity offerings. If low oil and natural gas prices,
drilling or production delays, operating difficulties or other factors, many of
which are beyond our control, cause our revenues and cash flows from operations
to decrease, we may be restricted in our ability to spend the capital necessary
to complete our drilling and development program. We have a $6 million bank
credit facility, the use of which is restricted to obtaining letters of credit.
We may not be able to borrow the funds necessary to support our working capital
needs or our capital expenditures program. After utilizing our available sources
of financing, we may be forced to raise debt or equity proceeds to fund such
expenditures. Our financial resources are limited, and we cannot assure you that
debt or equity financing or cash generated by operations will be available to
meet these requirements. A curtailment of capital spending could adversely
affect our ability to maintain or increase our production and our future cash
flow from operations. See "Item 5 -- Operating and Financial Review and
Prospects -- B. Liquidity and Capital Resources."
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.
Our operations are dependent upon a relatively small group of key
management and technical personnel. As of May 31, 2005, the Company's primary
operating subsidiary, PEI, had 13 employees. Although we have entered into
contracts with key managers and technical personnel, we cannot assure you 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.
8
COMPETITION WITHIN OUR INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS.
We operate in a highly competitive environment. The Company competes
with major and independent oil and gas companies and other independent producers
of varying sizes for the acquisition of desirable oil and natural gas properties
and the equipment and labor required to develop and operate such properties.
Most of these competitors have financial and other resources substantially
greater than ours. See "Item 4 - Information on the Company - Competition."
SUBSTANTIALLY ALL OF OUR OUTSTANDING ACCOUNTS RECEIVABLE MAY BE FROM A SINGLE
PURCHASER OF OUR OIL AND NATURAL GAS.
We often sell all of our monthly oil and natural gas production to a
single purchaser. We monitor our purchasers for developments that may indicate
whether the purchaser is having financial difficulty. Also, when we deem it
appropriate, we require the parent companies of our purchasers to give us a
guarantee that the parent will pay any delinquent obligations of their
subsidiary.
However, if a purchaser is unable to pay for the natural gas that we
sell, we could incur a significant amount of bad debt expense. Due to the delay
in recognizing a purchaser is unable to pay, our exposure to such a bad debt due
to non-payment by a purchaser, could be as much as two months of revenue.
OIL AND NATURAL GAS PRICE DECLINES AND THEIR VOLATILITY COULD ADVERSELY AFFECT
OUR REVENUES, CASH FLOWS AND PROFITABILITY.
Prices for oil and natural gas fluctuate widely. The Company's
revenues, profitability and future rate of growth depend substantially upon the
prevailing prices of oil and natural gas. Increases and decreases in prices also
affect the amount of cash flow available for capital expenditures and our
ability to borrow money or raise additional capital. Higher prices may reduce
the amount of oil and natural gas purchased from us because of reduced demand,
and lower prices may reduce the amount of oil and natural gas that we can
produce economically. Any substantial or extended decline in the prices of or
the demand for oil and natural gas could have a material adverse effect on our
financial condition, liquidity and results of operations.
We cannot predict future oil and natural gas prices. Factors that
can cause price fluctuations include:
- relatively minor changes in the supply of and demand for oil and
natural gas;
- market uncertainty;
- the level of consumer product demand;
- weather conditions;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political and economic conditions in oil producing countries,
particularly those in the Middle East;
- the foreign supply of oil and natural gas;
- the price of oil and natural gas imports; and
- general economic conditions.
From time to time, the Company uses derivative instruments, such as natural gas
swaps and costless collars, to reduce the risk of price fluctuations on a
portion of its future production. However, such hedging activities may not be
sufficient to protect the Company against the risk of price declines.
9
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND NATURAL GAS DRILLING AND
PRODUCTION ACTIVITIES.
Oil and natural gas drilling and production activities are subject
to numerous risks, including the risk that no commercially productive oil or
natural gas reservoirs will be found. The cost of drilling and completing the
wells is often uncertain. Oil and natural gas drilling and production activities
may be shortened, delayed or canceled as a result of a variety of factors, many
of which are beyond our control. These factors include:
- unexpected drilling conditions;
- geological pressure or irregularities in formations;
- equipment failures or accidents;
- weather conditions;
- shortages in experienced labor;
- shortages or delays in the delivery of equipment; and
- constraints on access to transportation systems (pipelines) delaying
sale of oil and or natural gas.
The prevailing prices of oil and natural gas also affect the cost of
and demand for drilling rigs, production equipment and related services.
We cannot assure you that the wells we drill will be productive or
that we will recover all or any portion of our investment. Drilling for oil and
natural gas may be unprofitable. Drilling activities can result in dry wells and
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs.
OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS.
The exploration, development and production of oil and natural gas,
involves a variety of operating risks. These risks include the risk of fire,
explosions, blow-outs, pipe failure, abnormally pressured formations and
environmental hazards. Environmental hazards include oil spills, natural gas
leaks, pipeline ruptures or discharges of toxic gases. If any of these industry
operating risks occur, we could have substantial losses. Substantial losses may
be caused by 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, most of our oil and natural gas
operations are located offshore in the Gulf of Mexico and are subject to the
additional hazards of marine operations such as capsizing, collision and adverse
weather and sea conditions. The Gulf of Mexico experiences tropical weather
disturbances, some of which can be severe enough to cause substantial damage to
facilities and possibly interrupt production. In accordance with industry
practice, the Company maintains insurance against some, but not all, of the
risks described above. We cannot assure you that our insurance will be adequate
to cover all of our losses or liabilities. Also, we cannot predict the continued
availability of insurance at premium levels that justify its purchase.
TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.
On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scale (the "September 11th attacks"). Since the
September 11th attacks, the U.S. government has issued warnings that U.S. energy
assets may be the future targets of terrorist organizations. If any future
terrorist attacks are aimed at our facilities, our purchasers' facilities,
transportation systems or other industry infrastructure, our business could be
materially adversely affected. Furthermore, such an actual or imminent terrorist
attack could affect our ability to obtain insurance against our operating risks.
A SIGNIFICANT PORTION OF OUR PRODUCTION, REVENUES AND CASH FLOW FROM OPERATING
ACTIVITIES ARE DERIVED FROM ASSETS THAT ARE CONCENTRATED IN A GEOGRAPHIC AREA.
As of January 1, 2005, nearly all of our production and revenues are
derived from wells located on two platforms in the Gulf of Mexico. One platform,
with four producing wells, is located at West Cameron 352 and the other
platform, with four producing wells, is located at Vermilion 258. Future wells
are also planned for the Gulf of Mexico. Accordingly, if the level of production
from these platforms substantially declines as a result of the occurrence of any
of the inherent operating risks, it could have a material adverse effect on our
overall production levels and our revenues.
10
OUR CASH BALANCES HELD IN AUSTRALIAN DOLLARS ARE EXPOSED TO CURRENCY EXCHANGE
RATE FLUCTUATIONS BETWEEN THE US DOLLAR AND THE AUSTRALIAN DOLLAR.
Since most of our operations are conducted in US dollars, we
generally maintain a substantial portion of our cash balances in US dollar
accounts. Occasionally, however, we may have substantial cash deposits in
Australian dollar accounts. Until these funds are converted to US dollars, the
US dollar value of the deposits will change as the exchange rate between the two
currencies fluctuate.
We currently do not use derivative financial instruments to hedge
our foreign exchange rate risk exposure.
OUR OIL AND NATURAL GAS OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL
REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.
Our oil and natural gas operations are subject to various U.S.
federal, state and local laws and regulations including requirements relating to
discharge of materials into the environment or otherwise to environmental
protection. These laws and regulations may be changed in response to economic or
political conditions. Regulated matters include permits for exploration,
development and production operations; limitations on drilling activities in
environmentally sensitive areas, such as wetlands and wilderness areas, and
restrictions on the way we can release materials into the environment; bonding
or other financial responsibility requirements to cover drilling contingencies
and well plugging and abandonment costs; reports concerning operations, the
spacing of wells, unitization and pooling of properties, taxation and interstate
transportation of oil and natural gas. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil, and criminal
penalties, imposition of remedial obligations, and the issuance of injunctions
prohibiting or restricting our operations. At various times, regulatory agencies
have imposed price controls and limitations on production. In order to conserve
supplies of oil and natural gas, these agencies have restricted the rate of flow
of oil and natural gas wells below actual production capacity. In addition, the
U.S. federal Oil Pollution Act, as amended ("OPA"), requires lessees and
permittees of offshore facilities such as us to prove that they have the
financial capability to respond to costs that may be incurred in connection with
potential oil spills. Under OPA and other U.S. federal and state environmental
statutes, including the federal Comprehensive Environmental Response,
Compensation and Liability Act, as amended ("CERCLA"), owners and operators of
certain defined onshore and offshore facilities are strictly liable for spills
of oil and other regulated substances, subject to certain limitations.
Consequently, a substantial spill from one of our facilities could require the
expenditure of additional, and potentially significant, amounts of capital, or
could have a material adverse effect on our earnings, results of operations,
competitive position or financial condition. U.S. federal, state and local laws
regulate the production, handling, storage, transportation and disposal of oil
and natural gas, by-products from oil and natural gas and other substances, and
materials produced or used in connection with oil and natural gas operations. We
cannot predict the ultimate cost of compliance with these requirements or their
effect on our operations. See "Item 4 -- Information on the Company."
The Company also has an interest in a joint operating arrangement
operating in China (Block 22/12, Beibu Gulf). The joint operating arrangement is
subject to the laws and regulations of the People's Republic of China, including
those relating to the exploration, development, production, marketing, pricing,
transportation and storage of natural gas and crude oil, taxation and safety and
environmental matters. The joint operating arrangement may be adversely affected
by changes in governmental policies or other political, economic or social
developments in or affecting China which are not within its control, including,
among other things, licensing and exploration arrangements, changes in crude oil
and natural gas development policies or regulations, marketing and pricing
policies, renegotiation or nullification of existing contracts, taxation
policies, exchange controls and repatriation arrangements and renminbi/US dollar
exchange rate fluctuations.
OUR SHAREHOLDERS MAY NOT BE ABLE TO SELL SHARES OF THE COMPANY AT THE TIME, IN
THE QUANTITY OR AT THE PRICE DESIRED BECAUSE OF OUR LOW TRADING VOLUME.
Our ordinary shares are traded on the Australian Stock Exchange
(symbol: PSA), and our ADRs are traded in the U.S. on the OTC Pink Sheets
(symbol PSJEY.PK). However, neither the ordinary shares nor the ADRs have
substantial trading volume, and on some days no ADRs are traded. Because of this
limitation, among others, our shareholders may not be able to sell shares of the
Company at the time, in the quantity, or at the price desired.
11
ITEM 4 - INFORMATION ON THE COMPANY
A. HISTORY AND DEVELOPMENT OF THE COMPANY
Petsec Energy Ltd is an independent oil and natural gas exploration
and production company operating primarily in the shallow waters of the Gulf of
Mexico, U.S.A., onshore Louisiana, U.S.A., and in the Beibu Gulf, offshore
China. It is an Australian public company incorporated in New South Wales,
Australia on December 7, 1967 with ordinary shares traded on the Australian
Stock Exchange (symbol: PSA), and ADRs traded in the U.S. on the OTC Pink Sheets
(symbol PSJEY.PK). In 1990, the Company incorporated PEI, a Nevada corporation
and its wholly owned subsidiary, and commenced evaluating oil and natural gas
exploration opportunities in the U.S., primarily in the Gulf of Mexico, offshore
Louisiana. The Company's joint operating arrangements in China are conducted
through its wholly owned subsidiary PPI, a Nevada corporation incorporated in
1987.
The Company is registered with the Australian Securities and
Investments Commission, Australian Company Number 000 602 700. The principal
address and telephone number is as follows:
Petsec Energy Ltd
Level 13
1 Alfred Street
Sydney, NSW 2000
Australia
Phone 011-612-9247-4605
The principal office address and telephone number of Petsec's U.S. incorporated
subsidiaries is as follows:
Petsec Energy Inc.
3861 Ambassador Caffery Parkway
Suite 500
Lafayette LA 70503
(337) 989 1942
CAPITAL EXPENDITURES
United States.
The Company acquired a 75% working interest in West Cameron 343,
offshore Louisiana at the March 2002 lease sale held in New Orleans, Louisiana
by the MMS. In addition, the Company earned a 75% working interest in the
adjacent West Cameron 352 lease by drilling a well in October 2002. A total of
three wells were drilled on these two leases during the fourth quarter of 2002,
each well encountering hydrocarbon-bearing sands with economic potential. The
existing production platform on West Cameron 352 was upgraded and production
from all three wells commenced towards the end of January 2003. The total cost
of the acquisition, drilling of the first three wells and platform upgrade
related to West Cameron 343 and West Cameron 352 ("West Cameron 343/352") wells
was $7.6 million and $1.5 million in 2002 and 2003, respectively.
In August and September 2003, the Company drilled two additional
wells from the West Cameron 352 platform. Both wells encountered
hydrocarbon-bearing sands with economic potential and were brought into
production in October 2003. The total cost to drill the two wells was $5.0
million.
In December 2003, the Company drilled a well at Vermilion 258 that
encountered hydrocarbon-bearing sands with economic potential. In January 2004,
the well was cased and suspended awaiting further development. The Company
expended $4.4 million in 2003 on the well. In January 2004, following the casing
and suspension of the first well, the Company drilled a second well at Vermilion
258, which also encountered hydrocarbon-bearing sands with economic potential.
The Company subsequently installed a platform, production facilities, and
pipeline. Following the installation, the Company completed the two wells and
started production in July 2004. The total amount expended in 2004 to case,
suspend, and complete the first well, drill and complete the second well, and to
construct and install the facilities was $12.3 million.
At the March 2004 lease sale held in New Orleans, Louisiana by the
MMS, the Company successfully bid on and was subsequently awarded three
additional exploration leases in the Gulf of Mexico. Total bids on the leases,
which are at Main Pass 19, Vermilion 244, and Vermilion 259, were $1.3 million,
net to Petsec. The Company holds a 100% working interest in the Vermilion 244
and 259 leases and a 55% working interest in the Main Pass 19 lease.
12
The Vermilion 244 and 259 leases offset certain discoveries in the Company's
Vermilion 258 lease. The Company acquired the two leases to protect its
interests in those discoveries. The Company plans to drill three wells at Main
Pass 19 in the second quarter of 2005. The Company expects to expend
approximately $12.2 million on the Main Pass 19 project in 2005.
In September 2004, the Company drilled two additional wells from the
Vermilion 258 platform to develop hydrocarbons that were discovered with the
first two wells. One of the development wells started production in November
2004. The completion of the other development well, which was brought into
production in May 2005, was initially delayed by down-hole mechanical
difficulties. The Company expended $7.3 million on the two development wells in
2004. The Company has expended approximately $4.0 million in 2005 to remediate
the down-hole mechanical difficulties.
In September 2004, the Company agreed to earn a 25% working interest
in the Price Lake field in Cameron Parish, Louisiana by participating in the
drilling of three wells. The first of the three wells commenced drilling in
September 2004 and the second of the three commenced drilling in December 2004.
In the first quarter of 2005, both wells encountered hydrocarbon-bearing sands
and were completed for production, though both wells have since proved to be
uneconomic. Consequently, in accordance with US GAAP, all the exploration costs
incurred and previously capitalized through December 31, 2004 in relation to
both these wells have been expensed as dry hole costs as of December 31, 2004.
The costs incurred on these wells after December 31, 2004 will be expensed in
2005. The Company expects to begin drilling of the third well in the second
quarter of 2005. The Company had expended $3.2 million on the Price Lake field
in 2004 and expects to expend approximately $5.0 million in 2005.
In December 2004, the Company purchased the right to participate in
a 3-D seismic survey over 94 square miles 50 miles west of New Orleans,
Louisiana ("Moonshine Project"). The Company will hold a 50% working interest in
the Moonshine Project and will act as operator. In 2004, the Company expended
$2.4 million on the Moonshine Project and expects to expend approximately $4.5
million on the project in 2005.
As of December 31, 2004, the Company has overriding royalty
interests or working interests in 13 exploration leases located in the Gulf of
Mexico, offshore Louisiana and Texas, and one onshore Louisiana lease. Six of
the offshore leases were undrilled as of that date.
At the March 2005 lease sale held in New Orleans, Louisiana by the
MMS, the Company was high bidder for two additional exploration leases in the
Gulf of Mexico. Total bids on the leases at Main Pass 18 and Main Pass 103,
which are adjacent to the Main Pass 19 lease, were $2.0 million. On May 26, 2005
the Company was awarded both the leases in which it will hold a 100% working
interest.
China
In 2002, the Company earned a 25% working interest in a block in the
Beibu Gulf, offshore China by contributing to the drilling of a well. The Wei
6-12-1 well was drilled and intersected nine meters of pay. The well was plugged
and abandoned for further evaluation. The joint operating arrangement then
completed a 3D seismic survey which was used to evaluate the economic potential
of the existing discoveries and plan for future work. The Company expended $1.0
million in 2002 on the Wei 6-12-1 well.
In 2003, the joint operating arrangement focussed on interpretation
of the 3D seismic survey identifying a number of drill targets. A three well
drilling programme, which commenced in mid-April 2004 and was completed by
mid-May 2004, tested one prospect and appraised two existing discoveries in and
around the 12-8 West and 12-8 East oil fields. The 12-8-3 appraisal well
intersected eleven meters of net oil pay in a highly permeable sand and
confirmed 1) the previous estimates of oil in place and 2) the highly viscous
nature of the oil contained in the 12-8 East field. The well was plugged and
abandoned for further evaluation of the development economics. Both the 12-7-1
exploration well and the 12-3-4 appraisal wells were plugged and abandoned as
dry holes. The Company expended a total of $1.9 million in 2004 on the three
wells.
In August 2004, the joint operating arrangement completed its
analysis of the development economics for the 12-8-1 and 12-8-2 oil fields and
also evaluated the exploration potential around the 6-12-1 oil discovery. The
post-drill analysis of the 12-8 East field indicated that the total oil in place
in this field and the adjacent 12-8 West field, is significantly greater than
previous independent estimates. The study also indicated that there was further
exploration potential in the vicinity of the 6-12-1 oil discovery well. In
October 2004, the joint operating arrangement elected to proceed into the third
exploration phase of the petroleum contract and commenced a pre-feasibility
study into the development of the 12-8 fields.
13
In January 2005, the joint operating arrangement completed the
pre-feasibility study concluding that the 12-8 West field should be developed
subject to a full feasibility study which is expected to be completed by mid
2005. The Company's share of the joint operating arrangement's 2005 budgeted
expenditure is $2.9 million.
B. BUSINESS OVERVIEW
Petsec is an oil and natural gas exploration and production company
operating in the shallow waters of the Gulf of Mexico, U.S.A., onshore
Louisiana, U.S.A., and in the Beibu Gulf, offshore China.
Revenues for 2004 were $32.8 million, comprising $32.6 million of
oil and natural gas sales, net of royalties paid, and $0.2 million from
overriding royalty interests. For 2003, the Company recorded revenues of $25.2
million, comprising $23.3 million of oil and natural gas sales, net of royalties
paid, and $1.9 million from overriding royalty interests. In 2002, the Company
recorded $0.2 million of oil and natural gas revenue, which was entirely the
result of its overriding royalty interests at Ship Shoal 184/191.
The Company's joint operating arrangement operations offshore China
have had no production or revenues to date.
See "Risk Factors" in "Item 3 D. - Key Information" for a discussion
of risks which could impact on the Company's ability to find proved reserves and
factors that affect oil and natural gas prices.
LIKELY DEVELOPMENTS
Drilling of the third well in the Price Lake field is expected to
commence in the second or third quarter of 2005. A three-well drilling program
at Main Pass 19 commenced in the second quarter of 2005 and the Moonshine 3D
seismic survey, which commenced in the first quarter of 2005, is expected to be
completed during 2005. As of June 7, 2005, the three wells had been drilled at
Main Pass 19 with all three discovering commercial hydrocarbons. Following
development of the discoveries at Main Pass 19, the Company expects production
to commence during the fourth quarter of 2005. The Company expects that
exploration opportunities that arise from the Moonshine survey, if any, will not
commence until late 2005 or until 2006.
In the Beibu Gulf, offshore China, a feasibility study into
development of the 12-8 West oil field at Block 22/12 is expected to be
concluded by mid 2005, to be followed by a decision regarding the construction
of production facilities.
Any other exploration and development undertaken in 2005 will be
determined by availability of funds, including expected cash flow from
production.
See "Trend Information" in "Item 5 D -- Operating and Financial
Review and Prospects".
14
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated net proved oil and natural
gas reserves of the Company (all of which were held in PEI), and the associated
historical 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 December 31, 2002, 2003 and 2004. All information relating to
estimated net proved oil and natural gas reserves and the estimated future net
cash flows attributable thereto is based upon reports by Ryder Scott Company
L.P., Petroleum Consultants. All calculations of estimated net proved reserves
have been made in accordance with the rules and regulations of the SEC, 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
natural gas. The present value of estimated future net revenues has been
calculated using a discount factor of 10% per annum.
As of December 31,
---------------------------------------------
2002 2003 2004
TOTAL NET PROVED:
Oil (Mbbls) 23 39 63
Gas (MMcf) 7,764 10,737 12,269
-------- -------- --------
Total (MMcfe) 7,902 10,971 12,647
-------- -------- --------
NET PROVED DEVELOPED:
Oil (Mbbls) 23 32 63
Gas (MMcf) 7,764 3,725 12,269
-------- -------- --------
Total (MMcfe) 7,902 3,916 12,647
-------- -------- --------
Estimated future net revenues before income taxes
(in thousands) $ 29,900 $ 44,527 $ 64,132
Present value of estimated future net revenues before
income taxes (in thousands) (1) $ 26,156 $ 35,495 $ 57,892
Standardized measure of discounted future net cash flows
(in thousands) (2) (3) $ 26,156 $ 35,495 $ 57,892
Average prices used in calculating the net present values:
Oil ($ per Bbl) $ 29.20 $ 32.41 $ 43.13
Gas ($ per Mcf) $ 4.57 $ 5.99 $ 6.18
- --------
(1) The present value of estimated future net revenues before income taxes
attributable to the Company's reserves was prepared using constant prices,
including the effects of hedging as of the calculation date, discounted at
10% per annum on a pre-tax basis. These prices have varied significantly
from year to year affecting the net present values, and are not
necessarily representative of current prices.
(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.
(3) Income taxes have not been provided for due to the Company's availability
of net operating loss carryforwards.
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 represents only estimates. Reserve engineering is
a subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact manner. The accuracy of any reserve
estimate depends on the quality of available data and the interpretation of that
data by geological engineers. Results of drilling, testing and production
subsequent to the date of an estimate may justify a revision of such estimates.
If significant, these revisions would change the schedule of any further
production and development drilling. Accordingly, reserve estimates generally
differ from the quantities of oil and natural 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.
15
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,
onshore Louisiana, and China during the period indicated.
Years ended December 31,
-----------------------------------------
2002 2003 2004
------ ------- -------
(In Thousands)
Acquisition costs $ 125 $ 519 $ 3,973
Exploration costs 2,149 6,586 11,943
Development costs 7,627 8,987 15,898
------ ------- -------
Total costs incurred $9,901 $16,092 $31,814
------ ------- -------
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, 2004:
Gross Net
------- ------
Productive wells (1):
Oil - -
Gas 7 6.1
------- ------
Total 7 6.1
------- ------
Developed Acreage (1) 10,156 8,867
Undeveloped Acreage (1) (2) 142,990 52,696
------- ------
Total 153,146 61,563
------- ------
- ---------------
(1) Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections.
Wells that are completed in more than one producing horizon are counted as
one well. Five (4.3 net) of our productive wells have multiple producing
horizons remaining. 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 natural gas, regardless of
whether or not such acreage contains proved reserves. A gross acre is an
acre in which a working interest is owned. Leases in which the Company
only holds an overriding royalty interest are excluded. A net acre is
deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional
interests owned in gross acres expressed as whole numbers and fractions
thereof.
(2) Leases covering 3% of the Company's undeveloped acreage will expire in
2006, 19% will expire in 2008, 24% will expire in 2009, and 54% are held
by production or exploration activities.
Drilling activity. The following table sets forth the Company's
drilling activity for the periods indicated.
Years ended December 31,
---------------------------------------------------------------------
2002 2003 2004
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
Gulf of Mexico
Exploratory wells - - - - 2 2
Development wells 3 2.25 2 1.75 1 1
Beibu Gulf, China
Exploratory wells - - - - 1 0.25
Dry holes - - - - 2 0.50
Abandoned wells 1 0.25 - - - -
----- ---- ----- ---- ----- ----
Total 4 2.50 2 1.75 6 3.75
----- ---- ----- ---- ----- ----
16
Present activity. At December 31, 2004, the Company had one
development well at Vermilion 244 in the process of being completed. The Company
holds a 100% working interest in the well which commenced production in May
2005. Also at December 31, 2004, two wells at the Price Lake Field, in which the
Company holds a 25% working interest, were being drilled though both these wells
have since proved to be dry holes.
In China, a feasibility study into development of the 12-8 West oil
field at Block 22/12 has commenced and is expected to be concluded by mid 2005.
A decision regarding the construction of production facilities will be made
following completion of the feasibility study.
OIL AND NATURAL GAS MARKETING
The Company sells all of its natural gas, oil and condensate
production at a combination of fixed, index and spot prices pursuant to short
term production sales contracts. The Company uses an outside party to market its
oil and natural gas. During 2004, approximately 55% of the Company's oil and
natural gas sales were made to Chevron USA Inc., 22% were made to Louis Dreyfus
Inc., and 20% were made to Reliant Energy Services Inc. The Company typically
sells all of its monthly natural gas production to only one or two purchasers.
COMPETITION
The Company competes for the acquisition of oil and natural gas
properties with numerous other entities, including major oil companies, other
independent oil and natural 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 natural 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,
to access adequate financing, and to consummate transactions in a highly
competitive acquisition environment.
REGULATION
The U.S. domestic oil and natural gas industry is extensively
regulated by U.S. federal, state and local authorities. In particular, oil and
natural 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.
Regulation of Natural Gas and Oil Exploration and Production. The
Company's U.S. operations are subject to various types of regulation at the
federal and state 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. The effect of these regulations may limit the
amount of oil and natural gas the Company can produce from its wells and may
limit the number of wells or the locations at which the Company can drill. Any
of these actions could negatively impact the amount or timing of revenues.
Federal Leases. The Company has in the past had operations located
on federal oil and natural gas leases, which are administered by the MMS. The
Company also anticipates future exploration and development of federal oil and
natural gas leases. 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, 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. Lessees must
also comply with detailed MMS regulations governing, among other things,
engineering and construction specifications for offshore production facilities,
safety procedures, flaring of production, plugging and abandonment of OCS wells,
calculation of royalty payments and the valuation of production for this
purpose, and removal of 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.
17
Natural Gas and Oil Marketing and Transportation. The transportation
and sale for resale of natural gas in interstate commerce are regulated pursuant
to the Natural Gas Act of 1938 (the "NGA"), 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 natural gas could be sold. Deregulation of
wellhead natural gas sales began with the enactment of the NGPA. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act (the "Decontrol Act").
The Decontrol Act removed all NGA and NGPA price and non-price controls from
wellhead sales of natural gas effective January 1, 1993. The FERC's regulations
currently eliminate price controls from the sales of natural gas by pipeline
affiliates, most of which remain subject to FERC's jurisdiction under the NGA.
While sales by producers, such as the Company, of natural gas and all sales of
crude oil, condensate, and natural gas liquids can currently be made at
uncontrolled market prices, there is no assurance that such regulatory treatment
will continue indefinitely into the future. Congress or, in the case of the
jurisdictional sales of natural gas by pipeline affiliates, the FERC could
reenact price controls in the future.
Commencing in 1992, the FERC issued Order No. 636 and subsequent
orders (collectively, "Order No. 636"), which require interstate pipelines to
provide transportation separate, or "unbundled," from the pipelines' sales of
natural gas. Also, Order No. 636 requires pipelines to provide open-access
transportation on a basis that is equal for all shippers. Although Order No. 636
does not directly regulate our activities, the FERC has stated that it intends
for Order No. 636 to foster increased competition within all phases of the
natural gas industry. The implementation of these orders has not had a material
adverse effect on our results of operations. The courts have largely affirmed
the significant features of Order No. 636 and numerous related orders pertaining
to the individual pipelines, although certain appeals remain pending and the
FERC continues to review and modify its open access regulations.
In 2000, the FERC issued Order No. 637 and subsequent orders
(collectively, "Order No. 637"), which imposed a number of additional reforms
designed to enhance competition in natural gas markets. Among other things,
Order No. 637 effected changes in FERC regulations relating to scheduling
procedures, capacity segmentation, pipeline penalties, rights of first refusal
and information reporting. Most major aspects of Order No. 637 were upheld on
judicial review, though certain issues, such as capacity segmentation and rights
of first refusal, were remanded to the FERC, which issued a remand order in
October of 2002. In January 2004, FERC denied rehearing of its October 2002
remand order. Petitions for review of that order have been filed at the United
States Court of Appeals for the District of Columbia Circuit and are currently
pending. We cannot predict whether and to what extent FERC's market reforms will
survive further judicial review and, if so, whether the FERC's actions will
achieve the goal of increasing competition in markets in which our natural gas
is sold. However, we do not believe that we will be affected by any action taken
materially differently than other natural gas producers and marketers with which
we compete.
Additional proposals and proceedings that might affect the oil and
natural gas industry are pending before Congress, the FERC, the MMS 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 less stringent regulatory approach currently
pursued by the FERC and Congress will continue indefinitely.
Environmental regulation. Our operations are subject to stringent
federal, state and local laws and regulation governing the discharge of
materials into the environmental or otherwise relating to environmental
protection. Such laws and regulations have generally increased the cost of
planning, designing, drilling, operating and abandoning wells. Failure to comply
with these laws and regulations may result in the assessment of administrative,
civil, and criminal penalties, imposition of remedial obligations, and the
issuance of injunctions prohibiting or restricting our operations. Although we
believe that compliance with environmental laws and regulations will not have a
material adverse effect on operations or earnings, the risks of substantial
costs and liabilities are inherent in oil and natural gas operations, and there
can be no assurance that significant costs and liabilities will not be incurred.
Moreover, it is possible that other developments, such as stricter environmental
laws and regulations, and claims for damages to property or person resulting
from the Company's operations could result in substantial costs and liabilities.
The Oil Pollution Act of 1990, as amended, (the "OPA") and
regulations thereunder impose a variety of regulations on "responsible parties"
related to the prevention of oil spills in U.S. waters and liability for damages
resulting from such spills. A "responsible party" includes the lessee or
permittee of the area in which an offshore facility is located. OPA assigns
liability to each responsible party for oil clean up costs and a variety of
public and private damages. While liability limits for offshore facilities under
OPA is the payment of all removal costs plus up to $75 million in other damages,
these limits may not apply if the spill was caused by a party's gross negligence
or willful misconduct, the spill resulted from violation of a federal safety,
construction or operating regulation, or if a party fails to report the spill or
cooperate fully in the cleanup. Few defenses exist to the liability imposed by
the OPA.
18
OPA also imposes ongoing requirements on lessees or permittees of
offshore areas in which a covered offshore facility is located, including the
preparation of oil spill response plans and proof of financial responsibility in
the amount of $35 million ($10 million if the offshore facility is located
landward of the seaward boundary of a state) to cover at least some costs in a
potential spill. Higher amounts of financial responsibility of up to $150
million my be required in certain limited circumstances where the MMS believes
such a level is justified by the risks posed by the operations, or if the
worst-case spill discharge volume possible at the facility may exceed the
applicable threshold volumes specified under the MMS's final rule. While we are
subject to and are in substantial compliance with OPA financial responsibility
requirements, we cannot predict whether these financial responsibility
requirements will result in the imposition of substantial additional annual
costs to the us in the future or otherwise materially adversely affect us. The
impact, however, should not be any more adverse to us than it will be to other
similarly situated or less capitalized owners or operators in the Gulf of
Mexico. We also have OPA-required spill response plans in place.
The Federal Water Pollution Control Act, as amended ("FWPCA"),
imposes restrictions and strict controls regarding the discharge of produced
waters and other oil and natural gas wastes into navigable waters without a
permit. The FWPCA and similar state laws provide for civil, criminal and
administrative penalties for any unauthorized discharges of pollutants. Many
state discharge regulations and the federal National Pollutant Discharge
Elimination System general permits issued by EPA prohibit the discharge of
produced water and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and natural gas industry into coastal waters.
Although the costs to comply with zero discharge mandates under federal or state
law may be significant, the entire industry is expected to experience similar
costs and we believe that these costs will not have a material adverse impact on
our results of operations or financial position.
The Comprehensive Environmental Response, Compensation and Liability
Act, as amended ("CERCLA"), also known as the "Superfund" law, and analogous
state laws impose 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. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several, strict 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. We also may incur liability
under the Federal Resource Conservation and Recovery Act, as amended ("RCRA"),
which imposes requirements relating to the management and disposal of solid and
hazardous wastes. While RCRA generally does not regulate most wastes generated
by the exploration and production of oil and natural gas, ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils,
may be regulated as solid hazardous waste. Failure by us to properly manage and
dispose of materials and wastes generated by or resulting from operation by us
or predecessor owners of properties that we acquire could result in the
imposition of remedial and abandonment liabilities under CERCLA, RCRA, and
analogous state laws.
China. The petroleum industry in the People's Republic of China
("PRC") is regulated by the PRC government. Areas over which it exercises
control include licensing, exploration, production, distribution, pricing,
exports, allocation of various resources used by the industry and environmental
management. The State Development and Reform Commission is the primary
co-ordinator for the petroleum industry and, together with other relevant
governmental agencies, provides regulatory supervision over the industry.
Participation by foreign companies in offshore oil and natural gas
production in China, alone or in joint operating arrangement, is conducted by
co-operation with the China National Offshore Oil Corporation under a petroleum
contract. The contract includes provisions covering minimum expenditure
requirements for exploration, terms of relinquishment of exploration acreage,
evaluation of development and development planning upon discovery of petroleum
reserves, production sharing arrangements and recovery of capital expenditures,
as well as the responsibilities of the foreign company as operator.
Foreign participants are subject to the tax laws and regulations of
the PRC including regulations governing the discharge of materials into the
environment or otherwise protection of the environment. We believe we are in
substantial compliance with all such applicable environmental requirements.
C. ORGANIZATIONAL STRUCTURE
Petsec Energy Ltd is an Australian Public Company, incorporated in
New South Wales, Australia. The Company's principal subsidiaries are Petsec USA
Inc. a wholly owned company incorporated in Nevada, ("PUSA") and PUSA's wholly
owned subsidiaries Petsec Energy Inc. and Petsec Petroleum Inc., also
incorporated in Nevada.
19
D. PROPERTY, PLANT AND EQUIPMENT
At December 31, 2004, the Company had interests in 13 oil and
natural gas leases located in the shallow waters of the Gulf of Mexico offshore
Louisiana and Texas and one oil and natural gas lease onshore Louisiana. The
interests in ten of the Company's offshore leases collateralize a significant
portion of PEI's $6.0 million credit facility.
The Company also has a 25% working interest in a petroleum contract
over a block in the Beibu Gulf, offshore China.
Refer to tables set forth in "B. Business Overview" within this Item
4 for information regarding the Company's oil and natural gas reserves and
production.
20
ITEM 5 - OPERATING AND FINANCIAL REVIEW AND PROSPECTS
A. OPERATING RESULTS
INTRODUCTION
The following discussion is intended to assist in the understanding of the
Company's results from operations for the years ended December 31, 2002, 2003
and 2004, and its financial position at December 31, 2004. The Company's
financial statements for these periods are set forth under Item 18 and should be
referred to in conjunction with the following discussion.
OVERVIEW
The Company's results from operations are primarily generated from its
operations in the Gulf of Mexico and its 25% working interest in a block in the
Beibu Gulf, offshore China. All of the Company's oil and natural gas operations
in the Gulf of Mexico are conducted by PEI. The 25% working interest in the
Beibu Gulf is owned by PPI. For the periods discussed, however, other factors
also impacted income from operations and net income, which are discussed below
under the caption "Other Items Affecting Results."
On January 6, 2004, Petsec issued 12,846,800 shares at A$0.95 per share to
raise a net A$11.6 million or approximately US$8.6 million, following a
placement arranged in December 2003. The Company used the funds for the
development of Vermilion 258, for exploration and development in the Beibu Gulf
offshore China, to fund lease acquisitions that were acquired at the March 2004
Central Gulf of Mexico lease sale, and other acquisition, exploration, and
development opportunities.
In December 2003, the Company began drilling the first of two exploration
wells at its Vermilion 258 lease and in early January 2004 began drilling the
second well. Both wells encountered hydrocarbon-bearing sands with economic
potential. Following the installation of a platform, production facilities, and
a pipeline, both wells were completed and put into production in July 2004. In
September 2004, the company began drilling two additional wells at Vermilion 258
to develop hydrocarbon-bearing sands that were discovered by the first two
wells. One of the wells was completed and put into production in November 2004.
The other development well was brought into production in May 2005. Through
December 31, 2004, the Company has expended $24.0 million to drill the four
wells and install the facilities, including $4.4 million expended in 2003. The
project was funded by cash flow generated from operations and from proceeds of
the January 2004 share placement.
In the Beibu Gulf 22/12 contract area, China, a three well drilling
programme, which commenced in mid-April 2004 and was completed by mid-May 2004,
tested one prospect and appraised two existing discoveries in and around the
12-8 West and 12-8 East oil fields. The 12-8-3 appraisal well intersected eleven
meters of net oil pay in a highly permeable sand and confirmed 1) the previous
estimates of oil in place and 2) the highly viscous nature of the oil contained
in the 12-8 East field. The well was plugged and abandoned for further
evaluation of the development economics. Both the 12-7-1 exploration well and
the 12-3-4 appraisal wells were plugged and abandoned as dry holes.
In August 2004, the joint operating arrangement completed its analysis of
the development economics for the 12-8-1 and 12-8-2 oil fields and also
evaluated the exploration potential around the 6-12-1 oil discovery. The
post-drill analysis of the 12-8 East field indicated that the total oil in place
in this field and the adjacent 12-8 West field, is significantly greater than
previous independent estimates. The study also indicated that there was further
exploration potential in the vicinity of the 6-12-1 oil discovery well. In
October 2004, the joint operating arrangement elected to proceed into the third
exploration phase of the petroleum contract and commenced a pre-feasibility
study into the joint development of the 12-8 fields.
Also during 2004, the Company:
- Entered into an agreement to participate in the drilling of three
wells at the Price Lake field, onshore Louisiana to earn a 25%
working interest and a 17.5% net revenue interest. The first two
wells of the three well programme, which commenced drilling in
September 2004 and December 2004, respectively, encountered
hydrocarbon-bearing sands and were completed for production. The
reserves discovered have subsequently proved to be uneconomic and as
a result, the wells have been determined to be dry holes and costs
incurred and previously capitalized through December 31, 2004 have
been expensed as of December 31, 2004. Drilling of the third well in
the Price Lake field is expected to commence in the second or third
quarter of 2005.
21
- Purchased the right to participate in the Moonshine Project, a 3-D
seismic survey over 94 square miles, 50 miles west of New Orleans,
Louisiana. The Company will hold a 50% working interest in the
Moonshine Project and will act as operator. The survey is expected
to be completed in 2005.
At December 31, 2004, the Company held working interests and/or overriding
royalty interests in 14 leases in the U.S. operations, one of which began
production during the year, and one in China. In the USA, five of the leases are
currently held by production.
At the March 2005 lease sale held in New Orleans, Louisiana by the MMS,
the Company was the high bidder for two additional exploration leases in the
Gulf of Mexico. Total bids on the leases, which are at Main Pass 18 and Main
Pass 103, were $2.0 million. On May 26, 2005, the Company was awarded both
leases in which it will hold 100% working interests.
Under US GAAP, the Company accounts for its oil and natural gas operations
under the successful efforts method of accounting. Under this method, the
Company capitalizes lease acquisition costs, costs to drill and complete
exploration wells in which proved reserves are discovered and costs to drill and
complete development wells. Costs to drill exploratory wells that do not find
proved reserves are expensed. Seismic, geological and geophysical, and delay
rental expenditures are expensed as incurred.
The following table sets forth certain operating information with respect
to the oil and natural gas operations of the Company.
Year ended December 31
2002 (1) 2003 (2) 2004 (3)
-------- -------- --------
Net production
Oil (Mbbls) 1 19 15
Gas (MMcf) 40 4,403 5,595
-------- -------- -------
Total (MMcfe) 46 4,517 5,685
-------- -------- -------
Net sales data (in thousands) (4):
Oil $ 28 $ 582 $ 669
Gas 173 24,637 32,129
-------- -------- -------
Total $ 201 $ 25,219 $32,798
-------- -------- -------
Average sales price (4):
Oil (per Bbl) $ 28.00 $ 30.84 $ 44.79
Gas (per Mcf) 4.33 5.60 5.74
-------- -------- -------
Total (per Mcfe) $ 4.37 $ 5.58 $ 5.77
-------- -------- -------
Average costs (per Mcfe):
Lease operating expenses(5) $ - $ 0.34 $ 0.31
Depletion, depreciation and amortisation 0.74 1.46 2.17
General, administrative and other expenses 36.76 0.81 0.82
- ---------
(1) Production from Ship Shoal 184/191 commenced in November 2002.
(2) Production from three wells at West Cameron 343/352 commenced in January
2003 and production from two additional wells at West Cameron 343/352
commenced in October 2003.
(3) Production commenced at Vermilion 258 from two wells in July 2004 and one
well in November 2004.
(4) Includes effects of hedging activities.
(5) Excludes major maintenance expense.
22
RESULTS OF OPERATIONS
The following table sets forth in US dollars and under US GAAP, selected
consolidated financial data for the Company for the periods indicated.
Year ended December 31
---------------------------------
2002 2003 2004
(In thousands)
INCOME STATEMENT DATA
Oil and gas sales (net of royalties paid or payable) $ - $ 23,270 $ 32,575
Oil and gas royalties 201 1,949 223
------- -------- --------
Total revenues $ 201 $ 25,219 $ 32,798
------- -------- --------
Lease operating expenses - 1,557 1,776
Depletion, depreciation and amortization 34 6,574 12,361
Exploration expenditure 1,176 1,329 1,452
Dry hole and abandonment costs 1,066 - 4,119
Major maintenance expense - - 592
Impairment expense - 38 201
General, administrative and other expenses 1,691 3,519 4,657
Stock compensation expense 40 90 83
------- -------- --------
Total operating expenses 4,007 13,107 25,241
Profit (loss) on sale of assets (8) - 2
------- -------- --------
Income (loss) from operations (3,814) 12,112 7,559
Other income 137 364 89
Interest expense - (10) (32)
Interest income 136 142 311
------- -------- --------
Income (loss) before income tax and extraordinary items (3,541) 12,608 7,927
Income tax benefit 254 492 9,807
------- -------- --------
Net income (loss) $(3,287) $ 13,100 $ 17,734
------- -------- --------
The following discussion relates to the operating information and financial data
tabled above and on the previous page:
YEAR ENDED DECEMBER 31, 2004 COMPARED TO YEAR ENDED DECEMBER 31, 2003
General. The start of production from the Vermilion 258 natural gas field
in late July 2004, partially offset by a natural decline in production from West
Cameron 343/352, resulted in higher production and revenue in 2004. The Company
recorded total revenues for the year of $32.8 million from net production of 5.7
Bcfe at an average price received of $5.77/Mcfe. This represents an increase of
$7.6 million, or 30.2%, on 2003.
Lease operating expenses were $1.8 million in 2004. This compares to $1.6
million in 2003. The increase is attributable to the start of production from
Vermilion 258.
Exploration Expenditures, Dry Hole and Abandonment Cost, Impairment
Expense and Major Maintenance Expense, In 2004, $1.5 million was expensed for
seismic, geological and geophysical expenditures, $4.1 million was expensed as
incurred for dry hole costs and abandonments, $0.6 million was expensed for
major maintenance expenditure and $0.2 million was expensed for impairment. The
dry hole costs and abandonments were the result of two dry holes drilled in the
Beibu Gulf, China ($1.1 million) and two dry holes drilled in the Price Lake
field ($3.0 million). The major maintenance expense was incurred in an attempt
to repair a completion failure at West Cameron 343/352. The impairment expense
relates to a provision made against the Company's share of the lease costs
incurred in respect of the Price Lake field. In 2003, $1.3 million was expensed
for seismic, geological and geophysical expenditures. Dry hole and abandonment
costs and major maintenance expense were nil in 2003.
23
General and Administrative Expense. General and administrative expense
increased $1.2 million, or 34%, to $4.7 million in 2004 from $3.5 million in
2003. The increase is largely attributable to the addition of staff and
increased exploration, operational, and production activities in the Gulf of
Mexico.
Depreciation, Depletion, and Amortization. Depreciation, depletion, and
amortization expense ("DD&A") increased $5.8 million, or 88%, to $12.4 million
in 2004 from $6.6 million in 2003. Higher DD&A costs in 2004 were due to higher
production and a downward revision of West Cameron reserves for the first half
of the year. DD&A on the Company's proved oil and natural gas properties is
calculated on a units-of-production basis. DD&A in 2004 per Mcfe was $2.17
compared to $1.46 in 2003.
Income Tax Benefit. The Company recognized an income tax benefit in 2004
despite generating a pre-tax . profit. This is primarily due to the reduction of
the deferred tax asset valuation allowance by $12.4 million, of which
$9.8 million relates to a change in judgement about management's assessment of
realizing the benefit of certain deferred tax assets in the future. The Company
also recognized an income tax benefit in 2003 despite generating a pre-tax
profit. This was primarily due to the reduction of the deferred tax asset
valuation allowance by $5.3 million caused by the realization of tax benefits in
2003 that were not previously recognized.
Net Income (loss). Net income in 2004 of $17.7 million is $4.6 million, or
35% higher than net income in 2003 of $13.1 million primarily due to increased
revenues for the year and the recognition of an income tax benefit resulting
from the Company's re-assessment of future taxable income. This was offset by an
additional $12.1 million of operating costs including additional DD&A costs of
$5.8 million.
YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002
General. The Company returned to strong profitability for the 2003
financial year due to the successful development and resulting production from
the Company's natural gas discoveries on the West Cameron 343/352 leases in the
Gulf of Mexico, USA. Historically high natural gas prices also contributed to
the strong operating profits.
Production from West Cameron 343/352 commenced in January 2003 and
significantly contributed to the Company's $25.2 million of revenue for the
year. The Company recorded net income of $13.1 million. This compares to a net
loss of $3.3 million in 2002. Lease operating expenses were $1.6 million. For
2002, the Company only had production from properties in which it had an
overriding royalty interest. Therefore lease operating expenses for this period
were nil.
Exploration Expenditures and Dry Hole and Abandonment Costs. In 2003, $1.3
million was expensed for seismic, geological and geophysical expenditures. In
2002, $1.1 million was expensed as incurred for dry hole costs and abandonments
and $1.2 million was expensed for seismic, geological and geophysical
expenditures. Substantially all of the dry hole costs and abandonments were the
result of operations in the Beibu Gulf, China.
General and Administrative Expense. General and administrative expense
increased $1.8 million, or 106%, to $3.5 million in 2003 from $1.7 million in
2002. General and administrative expense for 2003 includes $0.9 million of
incentive compensation recorded pursuant to a plan that was established for PEI
employees during 2003. The increase is also attributed to staff and activity
increases following the commencement of production activities in the Gulf of
Mexico.
Depreciation, Depletion, and Amortization. The $6.5 million increase in
DD&A reflects the start of production at West Cameron 343/352 in 2003. DD&A on
the Company's proved oil and natural gas properties is calculated on a
units-of-production basis. DD&A in 2003 per Mcfe was $1.46.
Income Tax Benefit. The Company recognized an income tax benefit in 2003
despite generating a pre-tax profit. This was primarily due to the reduction of
the deferred tax asset valuation allowance by $5.3 million caused by the
realization of tax benefits in 2003 that were not previously recognized. In
2002, the Company recognized a lower than expected income tax benefit on its
pre-tax loss primarily because of an increase in its deferred tax asset
valuation allowance of $0.6 million based on management's assessment that it was
more likely than not the benefit of certain deferred tax assets would not be
realized in the future.
Net Income (loss). As a result of the commencement of oil and natural gas
production, net income of $13.1 million was recorded for 2003, an increase of
$16.4 million from the net loss of $3.3 million for 2002. Net income was $13.1
million in 2003 compared to a net loss of $3.3 million in 2002.
24
HEDGING TRANSACTIONS
From time to time, the Company utilizes hedging transactions with respect
to a portion of its oil and natural gas production to achieve a more predictable
cash flow and to reduce its exposure to oil and natural gas price fluctuations.
While these hedging arrangements limit the downside risk of adverse price
movements, they may also limit future revenues from favorable price movements.
The use of hedging transactions also involves the risk that the counterparties
will be unable to meet the financial terms of such transactions. The credit
worthiness of counterparties is subject to continuing review and full
performance is anticipated. The Company has limited the term of the transactions
and the percentage of the Company's expected aggregate oil and natural gas
production that may be hedged. The Company accounts for these transactions as
hedging activities and, accordingly, gains or losses are included in oil and
natural gas revenues when the hedged production is delivered.
At December 31, 2004, the Company had the following outstanding natural
gas hedges in place:
WEIGHTED AVERAGE
PRODUCTION PERIOD HEDGE TYPE DAILY VOLUME USD PRICE
- ------------------- --------------- ------------ ----------------
First quarter 2005 Costless collar 4,000 MMBtu 6.00/7.08 (1)
Swap 6,000 MMBtu 7.89
Second quarter 2005 Swap 4,000 MMBtu 6.61
Third quarter 2005 Swap 4,000 MMBtu 6.59
Fourth quarter 2005 Swap 4,000 MMBtu 6.87
- ------------
(1) Floor/Ceiling
At December 31, 2004, the Company estimated that it would have realised a
gain of approximately $1.4 million if it settled the costless collars/swap
agreements before their expiration, if it had so elected. See "Item 11 -
Quantitative and Qualitative Disclosures About Market Risk".
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
In December 2004, the FASB issued FASB Statement No. 123 (revised 2004),
Share-Based Payment, which addresses the accounting for transactions in which an
entity exchanges its equity instruments for goods or services, with a primary
focus on transactions in which an entity obtains employee services in
share-based payment transactions. This statement is a revision to Statement 123
and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and
its related implementation guidance. This Statement will be effective for the
Company as of January 1, 2006. We are currently assessing the impact of the
adoption of this standard though we do not expect that the initial adoption of
this Statement will have a significant impact on our consolidated financial
position or our results of operations.
In April 2005, the FASB issued FASB Staff Position FAS 19-1, Accounting
for Suspended Well Costs, which will apply to enterprises that use the
successful efforts method of accounting as described in FASB Statement No. 19,
Financial Accounting and Reporting by Oil and Gas Producing Companies. The FSP
will require the Company to apply more judgement than was required by Statement
19 in evaluating whether the costs of exploratory wells meet the criteria for
continued capitalization. The FSP is an amendment to Statement 19, paragraphs 31
- - 34, and prescribes that exploratory well costs should continue to be
capitalized when the well has found a sufficient quantity of reserves to justify
its completion as a producing well and the Company is making sufficient progress
assessing the reserves and the economic and viability of the project. The FSP
will be effective for the Company as of 1 January 2006. We are currently
assessing the impact of the adoption of this FSP though we do not expect that
the initial adoption of this Statement will have a significant impact on our
consolidated financial position or our results of operations.
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 contingent obligations will be met. As of June 2, 2005, the Company had
posted $4.7 million of required bonding with the MMS. $2.6 million of these
bonds have been collateralized by letters of credit.
The Company's operations are subject to various U.S. federal, state and
local laws and regulations relating to the protection of the environment. See
"Item 4 - Information on the Company - Regulation." The Company believes its
operations are in material compliance with current applicable environmental laws
and regulations. However, there can be no assurance that current regulatory
requirements will not change, currently unforeseen environmental incidents will
not occur or past unknown non-compliance with environmental laws will not be
discovered.
25
FORWARD-LOOKING STATEMENTS
The information in this Form 20-F, includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All
statements, other than statements of historical or present facts, that address
activities, events, outcomes and other matters that the Company plans, expects,
intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or
anticipates (and other similar expressions) will, should or may occur in the
future are forward-looking statements. These forward-looking statements are
based on management's current belief, based on currently available information,
as to the outcome and timing of future events. When considering forward-looking
statements, you should keep in mind the risk factors and other cautionary
statements in this Form 20-F.
Forward-looking statements appear in a number of places and include
statements with respect to, among other things:
- any expected results or benefits associated with our acquisitions;
- planned capital expenditures and availability of capital resources to fund
capital expenditures;
- estimates of our future oil and natural gas production, including
estimates of any increases in oil and natural gas production;
- our outlook on oil and natural gas prices;
- estimates of our oil and natural gas reserves;-
- any estimates of future earnings growth;
- the impact of political and regulatory developments;
- our future financial condition or results of operations and our future
revenues and expenses; and
- our business strategy and other plans and objectives for future
operations.
We caution you that these forward-looking statements are subject to all of
the risks and uncertainties, many of which are beyond our control, incidental to
the exploration for and development, production and sale of oil and natural gas.
These risks include, but are not limited to, commodity price volatility,
inflation, lack of availability of goods and services, environmental risks,
drilling and other operating risks, regulatory changes, the uncertainty inherent
in estimating proved oil and natural gas reserves and in projecting future rates
of production and timing of development expenditures and the other risks
described in this Form 20-F.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way.
The accuracy of any reserve estimate depends on the quality of available data
and the interpretation of that data by geological engineers. In addition, the
results of drilling, testing and production activities may justify revisions of
estimates that were made previously. If significant, these revisions would
change the schedule of any further production and development drilling.
Accordingly, reserve estimates are generally different from the quantities of
oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described above or
elsewhere in this Form 20-F occur, or should underlying assumptions prove
incorrect, our actual results and plans could differ materially from those
expressed in any forward-looking statements. We specifically disclaim all
responsibility to publicly update any information contained in a forward-looking
statement or any forward-looking statement in its entirety and therefore
disclaim any resulting liability for potentially related damages.
All forward-looking statements express or implied, included in this Form
20-F and attributable to the Company are qualified in their entirety by this
cautionary statement. This cautionary statement should also be considered in
connection with any subsequent written or oral forward-looking statements that
the Company or persons acting on its behalf may issue.
B. LIQUIDITY AND CAPITAL RESOURCES
The Company had cash available in the amount of approximately $9.5 million
at December 31, 2004. At May 31, 2005, the Company's cash balances were
approximately $18.2 million. The Company believes, based on its analysis of
planned capital expenditure, forecast revenues and its current business plan
that its current cash and sources of liquidity are sufficient for the Company's
present requirements.
26
Cash Flow
The following table represents cash flow data for the Company for the
periods indicated.
Years Ended December 31,
-----------------------------
2002 2003 2004
------- -------- --------
(in thousands)
NET CASH PROVIDED BY (USED IN):
Operating activities $(2,728) $ 18,589 $ 22,032
Investing activities (8,170) (13,574) (26,046)
Financing activities - 6,851 1,070
Cash flow from operating activities in 2004 increased over 2003 primarily
as a result of the start of production from the Company's Vermilion 258 natural
gas field in late July 2004.
The cash flow from operating activities and the proceeds from the share
subscription monies received in December 2003 and January 2004 funded the
Company's $26.0 million of net investment activities in 2004 including capital
expenditures of $19.0 million for the drilling of four wells, development,
pipelines and facilities at Vermilion 258/244, $2.4 million for the cost of
re-completions at West Cameron 343/352, $1.5 million for drilling and
development at Price Lake onshore Louisiana, $1.8 million for lease acquisitions
and delay rentals and $2.0 million for exploration and development at Block
22/12 in the Beibu Gulf, China. The Company also received a refund of $2.1
million comprising $1.7 million of cash collateral previously posted to secure
surety bonds issued to the MMS and $0.4 million in respect of cash collateral
previously provided to hedging instruments counterparties.
Net cash provided by financing activities for the year ended December 31,
2004 was $1.1 million which comprised of $2.0 million relating to the remaining
balance of the share subscription monies received in relation to the January 6,
2004 share issuance offset by short-term loan repayments of $0.9 million.
Credit Facilities
Effective February 20, 2004, PEI entered into a $2.0 million credit
agreement with a U.S. bank for the purpose of securing letters of credit issued
by the bank and also to allow the refund of US$1.7 million of cash collateral
previously posted to secure surety bonds issued to the Minerals Management
Service (MMS). This facility was subsequently increased to $3.0 million in July
2004 and to $6.0 million in December 2004. In connection with the facility,
letters of credit totaling $4.1 million are outstanding as of May 31, 2005.
Letters of credit totaling $2.6 million secure bonding and potential plug and
abandonment and environmental contingent liabilities in connection with PEI's
oil and natural gas operations. Letters of credit totaling $1.5 million secure
the Company's obligations to a hedging counterparty.
PEI incurs fees of 1 3/4% per annum on the amount of letters of credit
issued by the bank. Any calls made against a letter of credit by a beneficiary
will constitute a loan under the credit agreement. Principal payments on any
such loan will be payable at the end of each calendar quarter in an amount
determined by the bank. Interest on any outstanding loans will accrue, at PEI's
election, at either (i) the bank's prime rate plus 1/2% pa, but no less than 4
1/2% pa or (ii) at LIBOR plus 3 1/2% pa. Upon final maturity of the credit
agreement, all loans and interest outstanding become due. The final maturity
date of the credit agreement, which was recently extended by one year, is March
31, 2007. To date, there have been no loans under the credit agreement.
The credit facility is secured by mortgages on PEI's interest in oil and
natural gas properties. The credit facility also contains financial covenants
that require PEI to:
(i) maintain its tangible net worth to be not less than 90% of the tangible
net worth at the closing date plus 50% of any advances to PEI from PEL,
and
(ii) a ratio of current assets to current liabilities of at least one to one.
The terms of the financial covenants governing the credit facility are
currently being met.
Future Capital Expenditures and Commitments
At the March 2005 lease sale held in New Orleans, Louisiana by the MMS,
the Company was the high bidder for two exploration leases in the Gulf of Mexico
(Main Pass 18 and Main Pass 103). On May 26, 2005 the Company was awarded the
two leases at a total cost of $2.0 million.
27
In total, the Company expects to expend at least $28 million for
acquisitions, exploration and development in 2005 including the following
projects:
USA
-- Remediation of the down-hole mechanical difficulties that have occurred
on a well at Vermilion 258;
-- Drilling and completion of three wells at Main Pass 19;
-- Platform and facilities at Main Pass 19;
-- Drilling and completion of the two Price Lake wells that commenced in
2004;
-- Drilling of the third well at the Price Lake field;
-- Moonshine Project 3-D seismic survey over 94 square miles onshore
Louisiana;
China
-- Participation in a feasibility study and Oil Development Plan ("ODP")
for the 12.8 West oil field.
The Company anticipates that it will fund these projects with available
cash and cash flow from operations.
C. RESEARCH AND DEVELOPMENT
Not applicable.
D. TREND INFORMATION
The Company anticipates production for 2005 will be higher than 2004 as it
should benefit from a full year of production from the three wells at Vermilion
258 that commenced production in mid to late 2004. Additionally, as of June 7,
2005, the Company discovered commercial hydrocarbons in all three wells drilled
at Main Pass 19. The Company will undertake the development of Main Pass 19 and
expects production to commence in the fourth quarter of 2005. Petsec owns a 100%
working interest in Vermillion 258 and a 55% working interest in Main Pass 19.
In conjunction with increased production, lease operating expenses and DD&A will
also be higher in 2005. The anticipated increase in production for 2005 will be
partially offset by the natural decline of production from West Cameron 343/352.
As of May 31, 2005, the first two wells drilled at Price Lake were
determined to be dry holes. As a result, the Company expects to record
approximately $5.0 million of dry hole expense in 2005 in conjunction with the
two wells.
The costs incurred for the 3-D seismic survey phase of the Moonshine
Project must be recorded as an exploration expense under the successful efforts
method of accounting. The Company expects to record approximately $4.5 million
of exploration expense in 2005 for the Moonshine 3-D seismic survey.
Currently, the Company is primarily a natural gas producer. Natural gas
prices during the first quarter of 2005 were generally higher than 2004. In the
first quarter of 2005, the Company has realized approximately $6.66 per Mcf of
natural gas excluding the impact of any financial hedges. In the first quarter
of 2004, the Company realized approximately $5.49 per Mcf of gas sold. Margins
could improve in 2005 compared to 2004 if the current natural gas price
environment continues for the remainder of the year.
E. OFF-BALANCE SHEET ARRANGEMENTS
We do not currently maintain any off-balance sheet arrangements with
unconsolidated entities or others that could materially affect liquidity, the
availability of capital resources or requirements for capital resources.
F. CONTRACTUAL OBLIGATIONS
The following table shows our other cash commitments as of December 31,
2004.
US$'000 Payments due by periods as of December 31, 2004
- ---------------------------------- ------------------------------------------------------------
Less than 1
Contractual obligations Total year 1 - 3 years 3 - 5 years After 5 years
- ---------------------------------- ----- ----------- ----------- ----------- -------------
Operating leases $ 393 $ 174 $ 209 $ 2 $ -
Exploration lease rental 509 132 348 29 -
----- ------ ------ ----- -----
Total contractual cash obligations $ 894 $ 306 $ 557 $ 31 $ -
----- ------ ------ ----- -----
28
In addition to the contractual cash obligations listed above, the Company
has committed to expending approximately $7.9 million in total during 2005 for
exploration within the U.S. and China in respect of its joint operating
arrangement commitments.
G. CRITICAL ACCOUNTING POLICIES
The Company's critical accounting policies under US GAAP are those that we
believe are most important to the portrayal of its financial condition and
results, and that require management's most difficult, subjective or complex
judgments. In many cases, the accounting treatment of a particular transaction
is specifically dictated by generally accepted accounting principles with no
need for the application of the Company's judgment. In certain circumstances,
however, the preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires the Company to use its
judgment to make certain estimates and assumptions. These estimates affect the
reported amounts of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period. The
Company believes the policies described below are its critical accounting
policies.
(1) Successful efforts method of accounting
The Company accounts for its natural gas and crude oil exploration and
development activities utilizing the successful efforts method of accounting.
Under this method, costs of productive exploratory wells, development dry holes
and productive wells and costs to acquire mineral interests are capitalized.
Exploration costs, including personnel costs, certain geological and geophysical
expenses including seismic costs and delay rentals for oil and natural gas
leases, are charged to expense as incurred. Exploratory drilling costs are
initially capitalized, but charged to expense if and when the well is determined
not to have found reserves in commercial quantities. As detailed below,
capitalized costs are subject to impairment tests. Each part of the impairment
test is subject to a large degree of management judgment, including the
determination of a property's reserves, future cash flows, and fair value.
Previously capitalized costs of $4.1 million and $1.1 million were
written-off and charged to the line item "Dry holes and abandonment costs" in
our consolidated statement of operations for the years ended December 31, 2004
and 2002, respectively.
(2) Impairment of oil and natural gas properties
The Company reviews its oil and natural gas properties for impairment at
least annually and whenever events and circumstances indicate a decline in the
recoverability of their carrying value. The Company estimates the expected
future cash flows of its oil and natural gas properties and compares such future
cash flows to the carrying amount of the properties to determine if the carrying
amount is recoverable. If the carrying amount exceeds the estimated undiscounted
future cash flows, the Company will adjust the carrying amount of the oil and
natural gas properties to their fair value. The factors used to determine fair
value include, but are not limited to, estimates of proved reserves, future
commodity pricing, future production estimates, anticipated capital
expenditures, and a discount rate commensurate with the risk associated with
realizing the expected cash flows projected.
Management's assumptions used in calculating oil and natural gas reserves
or regarding the future cash flows or fair value of our properties are subject
to change in the future. Any change could cause impairment expense to be
recorded, reducing our net income and the carrying value of the related asset.
Future prices received for production and future production costs may vary,
perhaps significantly, from the prices and costs assumed for purposes of
calculating reserve estimates. There can be no assurance that the proved
reserves will be developed within the periods estimated or that prices and costs
will remain constant. Actual production may not equal the estimated amounts used
in the preparation of reserve projections. As these estimates change, the amount
of calculated reserves changes. Any change in reserves directly impacts our
estimated future cash flows from the property, as well as the property's fair
value. Additionally, as management's views related to future prices change, this
changes the calculation of future net cash flows and also affects fair value
estimates. Changes in either of these amounts will directly impact the
calculation of impairment.
Given the complexities associated with oil and natural gas reserve
estimates and the history of price volatility in the oil and natural gas
markets, events may arise that would require the Company to record an impairment
of the recorded book values associated with oil and natural gas properties.
During the years ended December 31, 2004 and 2003, we recognized
impairment charges of $201 thousand and $38 thousand, respectively.
29
(3) Depreciation, Depletion, and Amortization
The Company records DD&A expense on its producing oil and natural gas
properties using a units-of-production method based on the ratio of actual
production to remaining reserves as estimated by independent petroleum
engineers. The effect of any revisions to the estimated remaining reserves on
DD&A is only considered in future periods and no adjustment is made to
accumulated DD&A applicable to prior periods. Because revisions to estimated
reserves are only considered prospectively when calculating DD&A expense, DD&A
expense in current and future periods may be significantly impacted by DD&A
attributable to past periods.
There have been no significant changes to the initial estimates of
remaining reserves in any of the last three years presented.
(4) Realization of Deferred Tax Assets
Deferred tax assets are reduced by a valuation allowance when, in the
opinion of management, it is more likely than not that some portion or all of
the deferred tax assets will not be realized. The Company's ability to realize
the benefit of its deferred tax assets requires that the Company achieve certain
future earnings levels prior to the expiration of its NOL carryforwards.
For U.S. federal income tax purposes, at December 31, 2004 the Company
estimates that it had net operating losses ("NOLs") of approximately $47.9
million which are available to offset future U.S. federal taxable income. The
NOLs from previous tax periods will expire from 2016 through 2021.
As of December 31, 2004, the Company revised its estimate of the amount of
deferred tax assets it believes it will ultimately be able to realize as a
result of changes in its forecast of future taxable income over the next three
years (the period in which the estimated reserves are expected to be extracted).
This resulted in a reduction in the beginning of year deferred tax asset
valuation allowance of $9.8 million in our consolidated balance sheet with a
corresponding increase in income tax benefit in our consolidated statement of
operations. The Company was also able to realize the benefits of approximately
$1.6 million of deferred tax assets in 2004 that were not previously recognized
because of its ability to generate taxable income in 2004. This reduced the
deferred tax asset valuation allowance in our consolidated balance sheet with a
corresponding increase in income tax benefit in our consolidated statement of
operations in 2004.
For the year ended December 31, 2003, the Company was also able to realize
the benefits of approximately $5.3 million of deferred tax assets that were not
previously recognized because of its ability to generate taxable income in that
2003. This reduced the deferred tax asset valuation allowance in our
consolidated balance sheet with a corresponding increase in income tax benefit
in our consolidated statement of operations in 2003.
In 2002, the Company increased its deferred tax asset valuation allowance
by $0.6 million based on management's assessment its was more likely than not
the benefit of certain deferred tax assets would not be realized in the future.
This reduced the net deferred tax assets recognized in our consolidated balance
sheet with a corresponding reduction in income tax benefit in our consolidated
statement of operations in 2002.
(5) Asset retirement obligations
The Company recognizes a liability for the legal obligation associated
with the retirement of a long-lived assets that results from the acquisition,
construction, development, and (or) the normal operation of oil and natural gas
properties. The initial recognition of a liability for an asset retirement
obligation, which is discounted using a credit-adjusted risk-free interest rate,
increases the carrying amount of the related long-lived asset by the same amount
as the liability. In periods subsequent to initial measurement, period-to-period
changes in the liability are recognized for the passage of time (accretion) and
revisions to the original estimate of the liability. Additionally, the
capitalized asset retirement cost is subsequently allocated to expense on a
straight-line basis over its estimated useful life.
There have been no significant changes to the assumptions used in
determining the asset retirement obligation since adoption of this standard in
2003.
30
ITEM 6 - DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A. DIRECTORS AND SENIOR MANAGEMENT
The following table sets forth the name, age and position of each director
and executive officer of the Company.
Name Age Position
- ---------------------- --- -------------------------------------------------------
Directors:
Terrence N. Fern (1) 57 Chairman, Managing Director and Chief Executive Officer
David A. Mortimer 60 Director, Chairman of Audit and Remuneration and
Nomination Committees
Peter E. Power 71 Director
Executive officers:
Ross A. Keogh 46 President of Petsec Energy Inc.
Prent Kallenberger 50 Vice President, Exploration of Petsec Energy Inc.
Norman Fakier 60 Vice President, Operations of Petsec Energy Inc.
Fiona A. Robertson (1) 49 Chief Financial Officer
Craig H. Jones (3) 46 General Manager - Corporate and Company Secretary
(1) Mr. Fern and Mrs. Robertson provide services to the Company through
contractual arrangements between the Company and corporate affiliates.
(2) Mr. Jones was appointed to the position of General Manager - Corporate
effective from January 10, 2005 and Company Secretary from February 28,
2005.
The following biographies describe the business experience of the
directors and executives of the Company and Petsec Energy Inc.
TERRENCE N. FERN has over 30 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 a director of Climax Mining Ltd.
DAVID A. MORTIMER has over 35 years corporate finance experience and was a
senior executive of TNT Limited Group from 1973 serving as Finance Director and
Chief Executive. He retired as its Chairman in 1997. He is a director of
Leighton Holdings Limited, Adsteam Marine Limited, Virgin Blue Holdings Limited,
Macquarie Infrastructure Investment Management Ltd, Arrow Pharmaceuticals Ltd,
and is Deputy Chairman of Australia Post and Chairman of Citect Corporation
Limited and Crescent Capital Partners Limited. Mr. Mortimer holds a Bachelor of
Economics degree from The University of Sydney.
PETER E. POWER has over 40 years experience in petroleum exploration
worldwide. Dr. Power has a Bachelor of Science degree from The University of
Sydney and gained his doctorate at the University of Colorado, USA. He has
served as Chairman of the Australian Petroleum Production and Exploration
Association and President of the Australian Geoscience Council. Dr. Power was
Managing Director of Ampolex Limited from 1987 to 1996.
ROSS A. KEOGH joined the Company in 1989 and has over 20 years experience
in the oil and gas industry. Between 1979 and 1989, Mr. Keogh worked in the
financial accounting and budgeting divisions of Total Oil Company and as Joint
Venture Administrator for Bridge Oil Limited in Australia. Mr. Keogh holds a
Bachelor of Economics degree, with a major in Accounting, from Macquarie
University in Sydney. Mr. Keogh was appointed Chief Financial Officer in
November 1998 until April 2002, and appointed President of PEI in April 2002.
PRENT KALLENBERGER is the Vice President of Exploration of Petsec Energy,
Inc. He joined Petsec in September of 1992 after holding various technical and
supervisory positions with Tenneco Oil Company, Union Pacific Resources Inc. and
Unocal Corporation. In these positions, he was responsible for exploration and
development programs in California and the Gulf of Mexico. 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.
NORMAN FAKIER joined Petsec in 2002 as VP-Operations. He has held
supervisory and management positions domestically and internationally with Shell
Oil Company, Amoco International (now BP-Amoco) and
31
Marathon Oil Company. Mr. Fakier has been involved in operations for 41 years in
drilling, completions, remedial work, construction and production.
FIONA A. ROBERTSON joined the Company in 2002 as the Chief Financial
Officer of the Petsec Energy Ltd group. Mrs. Robertson has over 25 years of
corporate finance experience, 15 in the resources industry. She spent 14 years
working for the Chase Manhattan Bank in London, New York and Sydney, and eight
years with Delta Gold Limited as General Manager, Finance/Chief Financial
Officer. Mrs. Robertson holds an MA in geology from Oxford University, is a
Fellow of the Australian Institute of Company Directors and a Member of the
Australasian Institute of Mining and Metallurgy.
CRAIG H. JONES joined the Company in January 2005 as General Manager -
Corporate and was also appointed as Company Secretary in February 2005. Mr.
Jones has had over 20 years corporate finance experience in listed companies in
the mining and healthcare industries after initial experience with an
international chartered accounting firm. Since 1987 he has served as Chief
Financial Officer with Sedimentary Holdings Ltd, ICSGlobal Limited, and Alpha
Healthcare Limited and as General Manager, Treasury and Corporate Services with
MIA Group Limited. Mr. Jones holds a Bachelor of Business Degree from the
University of Southern Queensland, is a Fellow of the Australian Society of
CPAs, a Fellow of the Institute of Chartered Secretaries and an Associate of the
Securities Institute of Australia.
B. COMPENSATION
The total compensation received by the directors of the Company for their
services as directors for 2004 was $429,804. The total compensation received by
the executive officers of the Company and its controlled and related companies
for 2004 was $1,349,267.
Fiscal year ended Base Other Retirement Other
December 31, 2004 emoluments Bonuses benefits(5) benefit plans compensation Total
- ------------------- ---------- ------- ----------- ------------- ------------ -------
$ $ $ $ $ $
DIRECTORS
T.N. Fern (1) - - 12,096 - 337,692 349,788
D.A. Mortimer 36,705 - - 3,303 40,008
P.E. Power 36,705 - - 3,303 40,008
EXECUTIVE OFFICERS
R.A. Keogh (2) 160,626 230,350 30,849 - - 421,825
P. Kallenberger (2) 160,800 210,000 29,421 - - 400,221
N. Fakier (2) 135,231 179,000 25,642 - - 339,873
F.A. Robertson (3) - - 1,073 - 102,337 103,410
G. H. Fulcher (4) 65,040 - 11,557 7,341 - 83,938
(1) Included in other compensation above is an amount of $337,692 which was
paid or is payable to Geofin Consulting Services Pty Ltd ("Geofin"), a
company which Mr. Fern is a director. During the year, Geofin provided
management services to the Company and its controlled entities. The
dealings were in the ordinary course of business and on normal terms and
conditions.
(2) Bonuses were granted pursuant to an employee incentive plan that PEI
established for its employees during 2003. Under the plan, the Company
will pay up to 6 1/2 percent of PEI's operating profit before interest,
taxes and incentive compensation for payment to PEI employees. The
allocation of the bonus to PEI's employees is made at the discretion of
the Company's management. For 2004, the Company recorded $1.0 million of
compensation expense under the plan.
(3) Included in other compensation above is an amount of $102,337 which was
paid or is payable to Geofin, a company through which Mrs. Robertson
provided services.
(4) Mr. Fulcher resigned from his position of Company Secretary on February
28, 2005.
(5) Other benefits includes amounts accrued or incurred by the Company on
behalf of the employee in relation to health, dental, life and salary
continuance insurance, leave entitlements and parking benefits.
32
In addition, the Company has accrued $220,000 payable as a retirement
benefit to the directors, Mr. D.A. Mortimer and Dr. P.E. Power on retirement.
The Company provides for directors' retirement benefits based on the number of
years service at the reporting date. All existing non-executive directors are
presently entitled to payments under the scheme which entitles them to a
benefit, on retirement, equivalent to the total remuneration received in the
past three years.
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 "Nomination and Remuneration Committee") appointed by the
Board of Directors. The total number of Ordinary Shares issued or subject to
option under all share and option plans during any five-year period may not
exceed 6,987,567. As at December 31, 2004 the number of further shares or
options, which could be issued within the limit was 3,349,567.
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 December 31, 2004, there were no entitlements
to shares under the Plan.
The Option Plan provides for the issue of options to purchase Ordinary
Shares to employees and (with shareholder approval) directors at prevailing
market prices and subject to certain conditions set by the Nomination and
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 not more than five years from the date of grant. As of December 31,
2004, directors of the Company held no options to purchase Ordinary Shares
pursuant to the Option Plan. During the year, Mr. G.H. Fulcher exercised 20,000
options on Ordinary Shares at an exercise price of A$0.41 per share. At December
31, 2004, Mr G.H. Fulcher held 35,000 remaining options to purchase Ordinary
Shares at an exercise price of A$0.40 per share and expiry date of December 1,
2007. Mr. Keogh held options to purchase an aggregate of 1,250,000 Ordinary
Shares at an exercise price of A$0.30 per share. Mr. Keogh received his options
during 2002 and his options expire on June 1, 2007. No other directors or
executive officers held options.
C. BOARD PRACTICES
The Board of Directors has an Audit Committee, a Nomination and
Remuneration Committee, of which each director is a member. Meetings of the
Board and Committees held during the year and attendance by directors were as
follows:
Nomination and
Regular Additional Audit Remuneration Date
Board Board Committee Committee Director First
Meetings Meetings Meetings Meetings Appointed
-------- ---------- --------- -------------- --------------
Total number held during
the year 10 6 4 2
T.N. Fern 10 6 4 2 May 21, 1987
D.A. Mortimer 10 6 4 2 July 1, 1985
P.E. Power 10 6 4 2 July 21, 1999
The Company's Constitution does not impose limits to each director's term
in office. However, under the Australian Corporations Act 2001, at least one
third of the Company's directors (other than the Managing Director) must retire
at each annual general meeting and may present themselves for re-election. To
comply with that act, the non-Managing Directors of the Company stand for
re-election on a rotating basis each year.
The Company has no severance contracts with its directors other than that
disclosed in Item 7 - Major shareholders and related party transactions, Section
B (b) and the retirement benefits outlined in "Section B" above.
33
The Nomination and Remuneration Committee of which Mr D.A. Mortimer is
Chairman is responsible for making recommendations to the Board on remuneration
policies and packages applicable to the Board members and senior executive
officers of the Company. The broad policy is to ensure the remuneration package
properly reflects the relevant person's duties and responsibilities and that
remuneration is competitive in attracting, retaining and motivating people of
the highest quality. Executive directors may receive bonuses based on the
achievements of specific goals related to the performance of the Company.
Non-executive directors do not receive any performance-related remuneration. The
Remuneration Committee comprises all of the directors.
The role of the Audit Committee is to review the half yearly and annual
accounts, to discuss the auditor's reports and reviews, and to oversee the
maintenance of a framework of internal control in the Company. The
responsibilities of the audit committee also include an annual review of the
performance of the auditors and of their reappointment. All the services
provided by the external auditors are approved by the audit committee prior to
commencement of their work. The external auditors are invited to attend audit
committee meetings. The audit committee comprises all of the directors.
Under Australian law, a company may pay non-executive directors, without
obtaining shareholders' consent, a benefit on retirement proportional to the
length of service of the director, with a maximum of seven times the average
remuneration of the last three years of service. There are no other
non-executive director retirement benefits.
D. EMPLOYEES
As of December 31, 2004, the Company had 17 full-time employees 13 of whom
were in Lafayette, Louisiana, and four of whom were in Australia. See "Item 3 -
Key Information - D. Risk Factors" "The loss of key personnel could adversely
affect our ability to operate." 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 certain of its
executives 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.
E. SHARE OWNERSHIP
The following table sets forth certain information regarding the
beneficial ownership of the Company's ordinary shares ("Ordinary Shares") as of
May 31, 2005 by each person who is known by the Company to own beneficially 10%
or more of the Ordinary Shares and by all directors and executive officers of
the Company and Petsec Energy Inc, as a group. The percentages herein have been
calculated based on the 119,547,841 Ordinary Shares outstanding on May 31, 2005.
NUMBER OF OPTIONS
ORDINARY SHARES PERCENTAGE OVER ORDINARY
NAME BENEFICIALLY OWNED BENEFICIALLY OWNED SHARES
- --------------------------------------- ------------------ ------------------ -------------
All Directors and executives as a group
(6 persons) (1) (2) (3) 28,708,926 24.0% -
Terrence N. Fern (2) (3) 26,882,498 22.5% -
D.A Mortimer 610,068 * -
P.E. Power 225,323 * -
R. A. Keogh (4) - * 1,250,000
P. Kallenberger (4) - * 1,125,000
N. Fakier (4) 825,000 * 300,000
F.A. Robertson 75,000 * -
G. H. Fulcher (5) 91,037 * 35,000
Den Duyts Corporation Pty Limited (3) 18,344,639 15.3% -
* These persons individually have less than 1% beneficial ownership of the
Company's outstanding ordinary shares.
(1) Includes Ordinary Shares held by family-controlled entities or companies
associated with such individuals. Also includes Ordinary Shares reflected
for Terrence N. Fern, Chairman and Managing Director of the Company. See
notes (2) and (3) below.
34
(2) Includes 4,000 Ordinary Shares held by Mr. Fern directly; 96,509 Ordinary
Shares held by a trust of which Mr. Fern is a shareholder of the corporate
trustee; 6,470,661 Ordinary Shares held by a trust of which Den Duyts
Corporation Pty Limited ("Den Duyts") is a shareholder and Mr. Fern is a
director of the corporate trustee; 1,966,689 Ordinary Shares held by a
corporation of which Mr. Fern is a shareholder; and 18,344,639 Ordinary
Shares held by a trust, Den Duyts. Excludes 4,000 Ordinary Shares held by
Mr. Fern's wife of which he disclaims that he is the beneficial owner and
42,000 Ordinary Shares held by Mr. Fern's adult children of which he
disclaims that he is the beneficial owner (as defined under Rule 13D-3 of
the Securities Exchange Act of 1934 (the "Exchange Act") ("Beneficial
Owner")). See note (3) below.
(3) Den Duyts is a company, which acts as the trustee of a trust, the
beneficiaries of which include members of Mr. Fern's family. Mr. Fern is
deemed to be the Beneficial Owner of such shares.
Under Australian law a shareholder is required to disclose to the Company
if the shareholder is "entitled" to 5% or more of the Company's Ordinary
Shares. A shareholder making such disclosure is required to aggregate with
the shares held personally and beneficially by such shareholder any other
shares in which the shareholder or an "associate" of the shareholder has a
"relevant interest". Under Australian law, a person has a "relevant
interest" in a share held by another person if the first person or a
corporate entity controlled by the first person has the right to exercise
or control the exercise of the voting rights in respect of that share or
has the power to dispose of or control the disposal of that share. An
"associate" is defined broadly and includes any person with whom the first
person has an agreement, arrangement or understanding relating to control
over shares, or with whom the first person proposes to act in concert. The
"relevant" interests of Den Duyts including its associates at May 31,
2005, were 26,785,989 Ordinary Shares and the "relevant" interests of Mr.
Fern were 26,785,989 Ordinary Shares.
(4) Options expire on June 1, 2007 and are exercisable at a price of A$0.30.
(5) Options expire on December 1, 2007 and are exercisable at a price of
A$0.40.
35
ITEM 7 - MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A. MAJOR SHAREHOLDERS
At May 31, 2005, shareholders who were the beneficial owners of 5% or more
of the Company's voting securities were:
Name of Holder Number of Shares %
- --------------------------------- ---------------- -----
Terrence N. Fern (1) 26,882,498 22.49
Den Duyts Corporation Pty Limited 18,344,639 15.35
National Nominees Ltd 12,703,062 10.63
ANZ Nominees Limited 9,869,265 8.26
Citicorp Nominees Pty Limited 11,628,544 9.73
Canning Oil Pty. Limited 6,470,661 5.41
(1) Includes shares held by Den Duyts Corporation Pty Limited.
Approximately 97% of the Company's voting securities are held by 3,570
shareholders in the host country.
Major shareholders who had significant changes in the percentage ownership
held during the past three years were:
Shareholder April 30, 2003 May 3, 2004 May 31, 2005
- --------------------------------------- ------------------ ------------------ ------------------
No. of % No. of % No. of %
Shares o'ship Shares o'ship Shares o'ship
Citicorp Nominees Pty Limited 14,447,027 13.66 10,534,574 8.84 11,628,544 9.73
ANZ Nominees Limited 10,286,435 9.73 11,745,244 9.85 9,869,265 8.26
National Nominees Ltd - - 13,046,782 10.95 12,703,062 10.63
Commonwealth Custodial Services Limited 8,870,420 8.39 - - - -
The Company's shares are all of one class and carry equal voting rights.
At May 31, 2005 there were 119,547,841 ordinary shares held by 3,975
shareholders.
B. RELATED PARTY TRANSACTIONS
(a) Directors
The names of persons who were directors of the Company during the year
ended December 31, 2004 are Messrs T.N. Fern, D.A. Mortimer and P.E. Power.
Details of the director's remuneration are set out in Item 6 - Directors,
Senior Management and Employees.
(b) Executive officer and director compensation and interest of management in
certain transactions
Other than as disclosed below in this section, there were no material
contracts involving directors during the year.
No loans were made to directors during the year and no such loans are
subsisting.
At December 31, 2004 there were no loans outstanding to directors.
A company associated with Mr. Fern provided management services to the
Company in the ordinary course of business and on normal terms and conditions.
The terms include provision for compensation in the event of termination without
due notice. The cost of the services provided to the Company during 2004 by the
company associated with Mr. Fern was $440,000.
36
The Company holds unlisted shares in an investment fund of which Mr.
Mortimer is Chairman. At December 2004 the Company had invested $528,000 in the
fund and has a total commitment to the fund of up to $778,000.
At December 31, 2004, 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 27,776,223.
(c) Controlled entities
Details of dealings of the Company with wholly owned controlled entities
are set out below:
The aggregate amounts receivable from/and payable to wholly owned entities
by the Company at balance date were:
December 31, 2002 December 31, 2003 December 31, 2004
$'000 $'000 $'000
----------------- ----------------- -----------------
Receivables - non-current 14,448 14,902 21,734
Payables - non-current 4,131 5,661 11,644
================= ================= =================
At December 31, 2004, PEL had provided against various loans to wholly
owned Australian controlled entities.
C. INTEREST OF EXPERTS AND COUNSEL
Not applicable.
ITEM 8 - FINANCIAL INFORMATION
A. CONSOLIDATED FINANCIAL STATEMENTS AND OTHER FINANCIAL INFORMATION
The US Dollar Financial Statements of the Company and the Independent
Auditors' Report are included on pages F-1 through F-29 of the Form 20-F. See
Item 18 below.
B. SIGNIFICANT CHANGES
None.
37
ITEM 9 - THE OFFER AND LISTING
A. OFFER AND LISTING DETAILS - PRICE HISTORY OF ORDINARY SHARES AND ADRS
The following table sets forth, for the periods indicated, the high and
low closing sale prices per Ordinary Share as reported on the ASX in Australian
dollars and translated into US dollars at the Noon Buying Rate on the respective
dates on which such closing prices occurred, unless otherwise indicated.
A$ US$
High Low High Low
---- ---- ---- ----
Year ended December 31, 2000: 0.25 0.08 0.16 0.05
Year ended December 31, 2001: 0.19 0.11 0.10 0.06
Year ended December 31, 2002: 0.30 0.14 0.16 0.07
First Quarter 0.20 0.14 0.11 0.07
Second Quarter 0.24 0.16 0.14 0.09
Third Quarter 0.30 0.19 0.16 0.10
Fourth Quarter 0.29 0.23 0.16 0.13
Year ended December 31, 2003:
First Quarter 2003 0.41 0.25 0.30 0.19
Second Quarter 2003 0.84 0.41 0.62 0.46
Third Quarter 2003 0.92 0.66 0.68 0.49
Fourth Quarter 2003 1.13 0.72 0.84 0.54
Year ended December 31, 2004:
First Quarter 2004 1.56 1.04 1.17 0.77
Second Quarter 2004 1.67 1.08 1.15 0.74
Third Quarter 2004 1.40 0.98 1.00 0.70
Fourth Quarter 2004 1.43 1.15 1.11 0.90
November 2004 1.43 1.22 1.12 0.95
December 2004 1.39 1.15 1.08 0.90
January 2005 1.25 1.11 0.97 0.86
February 2005 1.18 1.09 0.93 0.86
March 2005 1.29 1.09 1.01 0.86
April 2005 1.20 0.97 0.93 0.75
May 2005 1.14 0.84 0.87 0.64
38
The following table sets forth for the periods indicated the high and low
closing prices per ADR on the U.S. markets, as discussed below, in US dollars:
US$
High Low
---- ----
Year ended December 31, 2000 0.81 0.02
Year ended December 31, 2001 0.47 0.20
Year ended December 31, 2002
First Quarter 0.51 0.35
Second Quarter 0.68 0.41
Third Quarter 0.81 0.50
Fourth Quarter 0.81 0.32
Year ended December 31, 2003
First Quarter 1.22 0.70
Second Quarter 2.79 1.23
Third Quarter 2.87 2.10
Fourth Quarter 4.15 2.35
Year ended December 31, 2004
First Quarter 2004 5.90 3.98
Second Quarter 6.15 3.71
Third Quarter 4.95 3.43
Fourth Quarter 5.40 4.23
November 2004 5.40 4.50
December 2004 5.39 4.40
January 2005 4.84 4.08
February 2005 4.50 4.05
March 2005 5.00 4.20
April 2005 4.60 3.85
May 2005 4.25 3.40
B. PLAN OF DISTRIBUTION
Not applicable.
C. MARKETS
The trading market for the Company's Ordinary Shares is the Australian
Stock Exchange Limited ("ASX"), which is the principal stock exchange in
Australia. 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 three days after the transaction.
On October 13, 2000, the ADRs commenced trading on the OTC Pink Sheets
under the ticker symbol "PSJEY.PK". Each ADR evidences one American Depositary
Share ("ADS"), which represents five Ordinary Shares. The depositary of the ADRs
representing the ADSs is The Bank of New York ("Depositary").
As at May 31, 2005, 1,896,616 ADRs were on issue. These were equivalent to
9,483,080 Ordinary Shares or approximately 8% of the Company's issued capital.
D. SELLING SHAREHOLDERS
Not applicable.
E. DILUTION
Not applicable.
F. EXPENSES OF THE ISSUE
Not applicable.
39
ITEM 10 - ADDITIONAL INFORMATION
A. SHARE CAPITAL
Not applicable
B. CONSTITUTION
The Company is a public company registered or taken to be registered under
the Corporations Act 2001 of the Commonwealth of Australia (CORPORATIONS ACT).
The Company is admitted to the official list of the Australian Stock Exchange
(ASX).
At the 2004 Annual General Meeting of the Company, shareholders approved
an amendment to the Company's constitution to permit the sale of non-marketable
parcels of shares. This new section has been added as Section 23A of the
constitution. A complete copy of the constitution is annexed as an Exhibit.
The following is a brief summary of the provisions of the Company's
constitution relating to:
- certain powers of the directors;
- the rights, preferences and restrictions attaching to the ordinary shares
on issue in the capital of the Company; and
- certain other matters.
This summary is not intended to be exhaustive and is qualified by the
constitution, the Corporations Act, the Listing Rules of the ASX and the general
law in Australia.
1. DIRECTORS
The management and control of the business and affairs of the Company is
vested in the Board, which may exercise all the powers of the Company as are not
by the Corporations Act or by the constitution required to be exercised by the
shareholders in general meeting.
POWER TO VOTE WHERE MATERIALLY INTERESTED
A director may not vote in respect of any contract, arrangement or
proposal in which he or she has a direct or indirect material personal interest
or be present at a directors' meeting while any such contract, arrangement or
proposal is being considered unless permitted to do so under the Corporations
Act, including where the interest:
- arises because the director is a shareholder of the Company and is held in
common with the other shareholders of the Company;
- arises in relation to the director's remuneration as a director of the
Company;
- relates to a contract the Company is proposing to enter into that is
subject to approval by the shareholders and will not impose any obligation
on the Company if it is not approved by the shareholders;
- arises merely because the director is a guarantor or has given an
indemnity or security for all or part of a loan, or proposed loan, to the
Company;
- arises merely because the director has a right of subrogation in relation
to a guarantee or indemnity referred to above;
- relates to a contract that insures, or would insure, the director against
liabilities the director incurs as an officer of the Company (but only if
the contract does not make the Company or a related body corporate the
insurer);
- relates to any payment by the Company or a related body corporate in
respect of a permitted indemnity (as defined under the Corporations Act)
or any contract relating to such an indemnity; or
- is in a contract, or proposed contract with, or for the benefit of, or on
behalf of, a related body corporate and arises merely because the director
is a director of a related body corporate.
COMPENSATION/REMUNERATION
Each non-executive director is entitled to be paid for their services as a
director such remuneration, not exceeding the maximum sum from time to time
approved by an ordinary resolution of the shareholders, as the directors
40
determine. Such remuneration must be a fixed sum and not be by way of a
commission on, or percentage of, the profits or operating revenue of the
Company.
BORROWING POWERS
The Board has power to raise or borrow any money for the purposes of the
Company, with or without security. The Board may secure the repayment of
borrowed monies or any debts, liabilities, contracts or obligations undertaken
or incurred by the Company in such a manner and upon such terms and conditions
as it thinks fit.
RETIREMENT OF DIRECTORS
At every annual general meeting one third of the directors, or, if their
number is not a multiple of 3, then the number nearest to but not exceeding
one-third, must retire from office. The directors to retire are those longest in
office since last being elected. As between 2 or more directors who have been in
office an equal length of time, the directors to retire are determined by lot
(in default of agreement between them). Further, a director (other than the
Managing Director) must retire from office at the conclusion of the third annual
general meeting or the period of 3 years, whichever is the longer, after which
the director was appointed. A retiring director is eligible for re-election.
The Managing Director is not subject to retirement by rotation nor to be
taken into account in determining the rotation or retirement of directors.
There are no age limit requirements for the retirement or non-retirement of
directors.
SHARE QUALIFICATION
Unless otherwise determined by the shareholders in general meeting, there
is no shareholding qualification for directors. To date, the shareholders have
not made any such determination.
2. RIGHTS ATTACHED TO SHARES
DIVIDEND RIGHTS
Dividends on the Company's shares may only be paid out of the Company's
profits. The Board may determine a dividend to be paid to the shareholders. The
shareholders may also determine a dividend if and only if the Board has
recommended it and the dividend does not exceed the maximum amount recommended
by the Board. Payment of any dividend may be made in such manner or by such
means as agreed by the Board. The Board may pay interim dividends.
Subject to the rights of, or any restrictions on, the holders of shares created
under any special arrangement as to dividend, a dividend must be paid on all
shares in proportion to the amount paid or credited as paid on them.
All dividends remaining unclaimed after 1 year after being declared may be
invested or otherwise used by the Board for the benefit of the Company until
claimed or otherwise disposed of according to the Corporations Act.
VOTING RIGHTS
Subject to any rights or restrictions attaching to any class of shares,
every shareholder may vote at a meeting of shareholders and:
- on a show of hands, every shareholder has one vote; and
- on a poll, every shareholder has, for each fully paid share held by the
shareholder, one vote; and for each partly paid share a fraction of a vote
equivalent to the proportion which the amount paid (not credited)
represents to the total amounts paid and payable, whether or not called
(excluding amounts credited), on the share.
Votes may be given either personally or by proxy or by attorney or in the
case of a corporation by its duly authorized representative. A shareholder is
not entitled to vote at any meeting of shareholders in respect of any shares
held by the shareholder upon which calls remain unpaid.
Voting at any general meeting is in the first instance to be conducted by a show
of hands unless a poll is demanded by any of the following (except in relation
to the election of a chairman of a meeting):
- the chairman;
- not less than 5 members entitled to vote on the resolution; or
- members with at least 5% of the total votes that may be cast on the
resolution on a poll.
41
LIQUIDATION RIGHTS
On a winding up, the assets available for distribution to shareholders
must be distributed in proportion to the capital paid up on the shares held by
them. Once all the liabilities of the company are satisfied, a liquidator may,
with the authority of a special resolution of shareholders, divide among the
shareholders in kind all or any of the assets of the company. The liquidator may
with the sanction of a special resolution of the company vest all or any part of
the company's assets in trust for the benefit of shareholders as the liquidator
thinks fit, but the liquidator may not require a shareholder to accept any
shares or other securities in respect of which there is any liability.
CAPITAL CALLS
Subject to the terms on which any shares may have been issued, the Board
may make such calls on the shareholders as it thinks fit in respect of moneys
unpaid on their shares. Each shareholder is liable to pay the amount of each
call in the manner, at the time and at the place specified by the Board. Calls
may be made payable by instalments. The Board may charge interest on calls not
paid on or before the due date for payment. Shares in respect of which calls
have not been duly paid are liable to forfeiture.
3. VARIATION OF RIGHTS
The rights and privileges attached to any different class of shares may be
varied with the sanction of a special resolution passed at a separate meeting of
the holders of shares of that class (unless otherwise provided by their terms of
issue).
4. CONDITIONS GOVERNING GENERAL MEETINGS
The Board may call a general meeting of the shareholders. An annual
general meeting must be held at least once in every calendar year and within 5
months after the end of the Company's financial year (presently 31 December). At
present, an individual director may also call a general meeting. No shareholder
may convene a general meeting except where entitled under the Corporations Act
to do so. Notice of a meeting, in a form which complies with the Corporations
Act, must be given to all shareholders by a means permitted by the Corporations
Act. At least 28 days' notice of any general meeting must be given to
shareholders. All provisions of the constitution relating to general meetings
apply to any special meeting of the shareholders or any class of shareholders
held under the constitution or the Corporations Act.
Three shareholders must be personally present to form a quorum for a
general meeting for the election of a chairman, the declaration of a dividend
and the adjournment of the meeting. For all other purposes, a quorum is
comprised of at least 3 shareholders who hold or represent at least 10% of the
issued shares.
5. LIMITATIONS ON RIGHTS TO OWN SECURITIES
The constitution does not impose any limitations on the rights to own, or
exercise voting rights attached to, the Company's securities. However, the
Australian Foreign Acquisition and Takeovers Act 1975 imposes a number of
conditions, which restrict foreign ownership of Australian-based companies.
6. CHANGE OF CONTROL, ETC.
A sale of the Company's main undertaking can only be made with the
approval or ratification of an ordinary resolution of the shareholders. The
Corporations Act and the ASX Listing Rules regulate a change in control of the
Company and certain other corporate actions relating to the merger, acquisition
or restructuring of the Company.
7. DISCLOSURE OF OWNERSHIP THRESHOLD
The constitution does not require disclosure of shareholder ownership.
However, the Corporations Act does require a person who has an interest in 5% or
more of the shares in the Company to disclose certain information in relation to
that holding to the Company and the ASX.
C. MATERIAL CONTRACTS
None.
42
D. EXCHANGE CONTROLS
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 in this Item 10). 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 in this
Item 10) or in the Company's constituent documents that prevents or restricts a
non-resident of Australia from freely owning and voting the Ordinary Shares
which underlie the Company's ADRs.
Non-Australian shareholders should be aware that Australian law contains
certain provisions that may apply if a significant interest in the Ordinary
Shares is proposed to be acquired. The following brief discussion of relevant
Australian law restrictions on non-Australian ownership of securities is in no
way intended to be an exhaustive statement of the Australian position. The
discussion does not address general restrictions in Australian law on securities
ownership per se.
The Australian Foreign Acquisitions and Takeovers Act of 1975 (the
"Foreign Takeovers Act") requires notification to the Australian government of
any proposed acquisition by a foreign person which would result in such person
and any of its associates controlling not less than 15% of the voting power or
holding an interest in not less than 15% of the shares of an Australian company
with total assets valued at A$5 million or more. Upon receipt of such
notification, the Australian government has the authority to review such
acquisition. The Australian government also has the authority to review any
transaction involving two or more foreign persons who, with their associates,
are able to control at least 40% of the voting power or hold interests in not
less than 40% of the shares of an Australian corporation. Under its present
policy and except in certain special cases, the Australian government will
automatically approve such acquisitions if the corporation has total assets of
less than A$50 million. Where the corporation has assets in excess of A$50
million (as does the Company), the Australian government either may permit the
proposed acquisition to proceed subject to conditions or may prohibit the
transaction as contrary to the national interest. Under the terms of the Foreign
Takeovers Act, ownership of ADRs will constitute ownership of shares or voting
power of the Company.
Section 671B of the Australian Corporations Act 2001 requires a
shareholder who is entitled (within the meaning of the Australian Corporations
Act) 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 671B of the Australian Corporations Act 2001 also 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 the
Australian Corporations Act 2001, a person who holds an ADR is deemed to be
entitled to the underlying shares.
Section 606 of the Australian Corporations Act 2001 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 Act 2001) 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.
43
E. TAXATION
AUSTRALIAN TAXATION
Dividends. Fully franked dividends (i.e., dividends paid out of the
Company's profits which have been subject to Australian income tax at the
maximum corporate tax rate) which are paid to shareholders who are U.S.
residents will not be subject to Australian income or Australian withholding
taxes. Unfranked dividends (i.e., dividends that are paid out of profits that
have not been subject to Australian income tax) are subject to Australian
withholding tax when paid to U.S. resident shareholders. In the event the
Company pays partially franked dividends, shareholders will be subject to
withholding tax on the unfranked portion. Pursuant to the bilateral taxation
convention between Australia and the United States (the "Treaty"), the
withholding tax imposed on dividends paid by the Company to a U.S. resident is
limited to 15%. Refer, however, to "Changes to the Treaty," below.
Dividends which are paid to the Company by a U.S. subsidiary out of the
trading profits of that subsidiary will give rise to a credit in the Company's
"foreign dividend account" ("FDA"). Where the Company has a credit balance in
its FDA and makes a written FDA declaration specifying that all or a portion of
an unfranked dividend to be paid by the Company is a FDA dividend, the amount so
specified will be exempt from Australian withholding tax. The payment of a FDA
dividend gives rise to a debit in the Company's FDA account. The Australian
Federal Government is considering the extension of the dividend withholding tax
exemption to all types of foreign income derived by an Australian company.
Sales of ADSs or Ordinary Shares. U.S. residents who do not hold and have
not at any time in the five years preceding the date of disposal held (for their
own account or together with associates) 10% or more of the issued share capital
of a public Australian company are not liable for Australian capital gains tax
on the disposal of shares or ADSs of such company.
U.S. residents are subject to Australian capital gains tax on the disposal
of shares or ADSs of a private Australian company where the disposal
consideration exceeds the cost base unless such a gain is exempt from Australian
tax under the Treaty. The rate of Australian tax on taxable capital gains
realized by U.S. residents is 30% for companies for the 2003 income year (for
most taxpayers, the year ending June 30, 2003). For individuals, the rate of tax
increases from 29% to a maximum of 47%. However, if the Ordinary Shares or ADSs
are held for 12 months or more, an individual should be entitled to an exemption
of 50% of the otherwise taxable capital gain. U.S. residents who are subject to
Australian tax on capital gains made on the disposal of shares or ADSs are
required to file an Australian income tax return for the year in which the
disposal occurs.
Non-residents of Australia who are securities dealers or in whose hands a
profit on disposal of ADSs or Ordinary Shares is regarded as ordinary income and
not as a capital gain (such ADSs and Ordinary Shares are referred to as "revenue
assets") will be subject to Australian income tax on Australian source profits
arising on the disposal of the ADSs or Ordinary Shares, unless such profits are
exempt from Australian tax under the Treaty. Prospective investors should
consult their own tax advisors in determining whether the ADSs or Ordinary
Shares are revenue assets because such a conclusion depends on the particular
facts and circumstances of the individual investor.
Pursuant to the Treaty, capital gains or profits arising on the disposal
of ADSs or Ordinary Shares which constitute "business profits" of an enterprise
carried on by a U.S. resident who does not carry on business in Australia
through a permanent establishment to which such gains or profits are
attributable are exempt from Australian tax. Refer, however, to "Changes to the
Treaty," below. The term "business profits" is not defined in the Treaty and
thus its meaning in the present context is that which the term has under
Australian tax law. The Australian Courts have held that the term business
profits is not confined to profits derived from the carrying on of a business
but must embrace any profit of a business nature or commercial character. The
term "permanent establishment" is defined in the Treaty to mean a fixed place of
business through which an enterprise is carried on and includes an Australian
branch of the U.S. resident and an agent (other than an agent of independent
status) who is authorized to conclude contracts on behalf of the U.S. resident
and habitually exercises that authority in Australia. Any capital gains or
profits derived by a U.S. resident from the disposal of the ADSs or Ordinary
Shares held as revenue assets (including gains derived by a securities dealer)
will constitute business profits under the Treaty and, thus be exempt from
Australian tax, provided that such holder does not carry on business in
Australia through a permanent establishment to which such gains or profits are
attributable.
The view of the Australian Taxation Commissioner is that the Treaty in its
current form would not preclude Australia from taxing a capital gain realised by
a U.S. resident on the sale of ADSs or Ordinary Shares.
U.S. residents with no taxable income (or deductible losses) from sources
in Australia other than dividends with respect to the Ordinary Shares or ADSs
are not required to file an Australian income tax return.
44
Changes to the Treaty. On September 27, 2001, the Governments of the
United States and Australia signed a Protocol ("the Protocol") amending the
existing Treaty. The Protocol came into force on May 12, 2003 and has the
following dates of effect:
1 For withholding taxes, the protocol will have effect in relation to
payments made on or after July 1, 2003.
2 For other taxes covered, the protocol will have effect in respect of
income, profits or gains of years of income beginning on or after
July 1, 2004.
Broadly, subject to the two exceptions mentioned below, the existing tax
treatment of dividends paid to U.S. residents will continue; that is, no
withholding tax will be imposed on the franked component of dividends paid to a
U.S. resident shareholder and 15% withholding tax will be imposed on the
unfranked component of dividends. The two exceptions are:
a) no withholding tax will be imposed on unfranked dividends paid to a
U.S. resident company which is beneficially entitled to 80% of the
voting power (for a 12 month period prior to the date the ( dividend
is declared) of the Company and the U.S. resident company satisfies
a public listing requirement; and
b) a withholding tax limit of 5% will apply to unfranked dividends paid
to a U.S. resident company ( that holds at least 10% of voting power
in the Company but does not meet the 80% test mentioned above.
The Protocol will also amend the Treaty to the effect that Australia will not be
precluded by the Treaty from taxing capital gains derived by a U.S. resident on
the sale of ADSs or Ordinary Shares.
UNITED STATES FEDERAL INCOME TAXATION
The following is a summary of the principal U.S. federal income tax
consequences of the purchase, ownership and sale of ADSs (which are evidenced by
ADRs) by a "U.S. Holder." As used herein, the term "U.S. holder" means a
beneficial owner of ADRs that is for U.S. federal income tax purposes (1) an
individual who is a U.S. citizen or U.S. resident alien; (2) a corporation, or
other entity taxable as a corporation for U.S. federal income tax purposes, that
was created or organized in or under the laws of the United States, any state
thereof or the District of Columbia; (3) an estate whose income is subject to
U.S. federal income taxation regardless of its source; or (4) a trust if a court
within the United States is able to exercise primary supervision over the
administration of the trust and one or more United States persons have the
authority to control all substantial decisions of the trust, or that has a valid
election in effect under applicable U.S. Treasury Regulations to be treated as a
United States person.
In this discussion, we do not purport to address all tax considerations
that may be important to a particular holder in light of the holder's
circumstances, or to certain categories of investors that may be subject to
special rules, such as financial institutions, insurance companies, regulated
investment companies, tax-exempt organizations, dealers in securities or
currencies, persons whose functional currency is not the U.S. dollar, U.S.
expatriates, persons that own directly, indirectly or constructively 10% or more
of our voting stock, partnerships or other pass-through entities, persons who
hold ADRs as part of a hedge, conversion transaction, straddle or other risk
reduction transaction, or persons who acquire ADRs pursuant to the exercise of
employee stock options or otherwise as compensation. This discussion is limited
to U.S. Holders who hold ADRs as capital assets (within the meaning of section
1221 of the Internal Revenue Code of 1986, as amended (the "Code")). If a
partnership holds ADRs, the tax treatment of a partner generally will depend
upon the status of the partner and the activities of the partnership. This
discussion also does not address the tax considerations arising under the laws
of any foreign, state, local, or other jurisdiction.
This summary is based upon the provisions of the Code, applicable Treasury
Regulations promulgated thereunder, judicial authority and administrative
interpretations, as of the date hereof, all of which are subject to change,
possibly with retroactive effect, or are subject to different interpretations.
We cannot assure you that the Internal Revenue Service will not challenge one or
more of the tax consequences described herein, and we have not obtained, nor do
we intend to obtain, a ruling from the IRS or an opinion of counsel with respect
to the United States federal tax consequences of acquiring, holding or disposing
of ADRs.
THE SUMMARY OF U.S. FEDERAL INCOME TAX CONSEQUENCES SET FORTH BELOW IS FOR
GENERAL INFORMATION PURPOSES ONLY. U.S. HOLDERS OR PROSPECTIVE U.S. HOLDERS OF
ADRS THEREFORE SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION
OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS, INCLUDING
THE APPLICABILITY AND EFFECT OF STATE, LOCAL OR FOREIGN TAX LAWS AND TAX
TREATIES AND POSSIBLE CHANGES IN LAW.
45
TAXATION OF DIVIDENDS
The amount of any distribution paid to a U.S. Holder in respect of
Ordinary Shares represented by the ADRs, including any Australian taxes withheld
from the amount of such distribution, will be includable in gross income of the
U.S. Holder as a dividend, to the extent paid out of current or accumulated
earnings and profits, on the date such distributions are received by the
Depositary. Generally, such dividends will be treated as foreign source passive
income for U.S. foreign tax credit purposes. The amount of any distribution of
property other than cash will be the fair market value of the property on the
date of the distribution. To the extent the amount of a distribution received by
a U.S. Holder exceeds that holder's share of the Company's current and
accumulated earnings and profits, the excess will be applied first to reduce
such U.S. Holder's tax basis in the ADRs and then, to the extent the
distribution exceeds the U.S. Holder's tax basis, will be treated as capital
gain.
Dividends paid with respect to the Ordinary Shares generally will not be
eligible for the dividends received deduction allowed to corporations receiving
dividends from certain U.S. corporations. Under certain circumstances, a U.S.
Holder that is a corporation and that owns ADRs representing at least 10% of the
total voting power and value of the stock of the Company may be entitled to a
70% deduction of the U.S. source portion of dividends received from the Company
(unless the Company qualifies as a "Foreign Personal Holding Company" or a
"Passive Foreign Investment Company" as defined below). The availability of the
dividends received deduction is subject to several complex limitations, which
are beyond the scope of this discussion, and U.S. Holders of ADRs should consult
their own tax advisors regarding the dividends received deduction.
Under recently enacted legislation, subject to certain restrictions and
limitations, U.S. Holders that are individuals, estates or trusts may be
eligible for the maximum 15% long-term capital gains tax rate on dividends
received from "qualified foreign corporations." The term qualified foreign
corporation includes a foreign corporation that is eligible for the benefits of
a comprehensive income tax treaty with the United States which the U.S. Treasury
Department determines to be satisfactory and which includes an exchange of
information provision. The legislative history underlying the provision
indicates that until the U.S. Treasury Department issues guidance regarding the
determination of treaties as satisfactory for this purpose, a foreign
corporation will be considered to be a qualified foreign corporation if it is
eligible for the benefits of a comprehensive income tax treaty with the United
States that includes an exchange of information provision (other than the
U.S.-Barbados Treaty). The U.S. - Australia Income Tax Treaty contains such an
exchange of information provision and thus, it appears that the Company should
be treated as a qualified foreign corporation. However, if the Company
constitutes a "Foreign Personal Holding Company," a "Foreign Investment
Company," or a "Passive Foreign Investment Company," each as defined below, for
its taxable year during which it pays a dividend, or for its immediately
preceding taxable year, the Company generally will not be treated as a
"qualified foreign corporation" and dividends received by U.S. Holders that are
individuals, estates or trusts will be subject to U.S. federal income tax at
ordinary income tax rates (and not at the preferential tax rates applicable to
long-term capital gains).
Dividends paid in Australian dollars will be includable in income in the
U.S. dollar amount based on the exchange rate on the date such dividends are
paid by the Company. U.S. 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 U.S. dollars and any such gain or loss
will be ordinary gain or loss.
FOREIGN TAX CREDIT
A U.S. Holder who pays (or has withheld from distributions) Australian
taxes with respect to the ownership of the ADRs may be entitled to claim a
foreign tax credit for the amount of such Australian taxes against such U.S.
Holder's U.S. federal income tax liability, subject to certain limitations and
restrictions that may vary depending upon such holder's circumstances. Instead
of claiming the foreign tax credit, a U.S. Holder may deduct the U.S. dollar
value of such Australian taxes in computing such U.S. Holder's taxable income,
subject to generally applicable limitations under U.S. federal income tax law.
The election to credit foreign taxes is made on a year-by-year basis and applies
to all foreign taxes paid by (or withheld from distributions to) the U.S. Holder
during that year.
TAXATION OF WITHDRAWALS
U.S. Holders of ADRs that exercise their right to withdraw Ordinary Shares
from the Depositary in exchange for the ADRs representing such Ordinary Shares
will generally not be subject to United States federal income tax on such
exchange. The aggregate basis of the Ordinary Shares so received will be equal
to the U.S. Holder's aggregate adjusted basis in the ADRs exchanged therefor.
46
TAXATION OF CAPITAL GAINS
A U.S. Holder generally will recognize a capital gain or loss for United
States federal income tax purposes upon a sale or other disposition of ADRs in
an amount equal to the difference between such U.S. Holder's tax basis in the
ADRs and the amount realized on their disposition. The amount realized includes
the amount of cash and the fair market value of any property received by a U.S.
Holder in exchange for the ADRs. Such capital gain or loss will be long-term
capital gain or loss if the U.S. Holder holds the 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 U.S. Holder of ADRs generally will constitute gains or
losses from sources within the United States.
INFORMATION REPORTING AND BACKUP WITHHOLDING
Information reporting may apply to a U.S. Holder with respect to
distributions made by the Company or to the proceeds of the sale or other
disposition of ADRs, and backup withholding (currently at a rate of 28%) may
apply unless the U.S. Holder provides the appropriate intermediary with a
taxpayer identification number, certified under penalties of perjury, as well as
certain other information or otherwise establishes an exemption from backup
withholding. Any amount withheld under the backup withholding rules is allowable
as a credit against the U.S. Holder's federal income tax liability, if any, and
a refund may be obtained if the amounts withheld exceed the U.S. Holder's actual
U.S. federal income tax liability and the required information is provided to
the IRS.
OTHER U.S. TAX CONSIDERATIONS
Set forth below are certain material exceptions to the above-described
general rules describing the United States federal income tax consequences
resulting from the holding and disposition of the ADRs.
Foreign Personal Holding Company
If at any time during a taxable year (a) more than 50% of the total voting
power or the total value of the Company's outstanding shares is owned (including
through ownership of ADRs), directly or indirectly (pursuant to rules of
constructive ownership), by five or fewer individuals who are citizens or
residents of the United States and (b) 60% (or 50% in certain cases) or more of
the Company's gross income for such year consists of certain types of passive
income (e.g., dividends, interest, royalties, certain gains from the sale of
stock and securities, and certain gains from commodities transactions), the
Company may be treated as a "Foreign Personal Holding Company" ("FPHC"). In that
event, U.S. Holders of ADRs of the Company would be required to include in gross
income for such year their allocable portions of such passive income to the
extent the Company does not actually distribute such income.
The Company does not believe that it currently constitutes a FPHC.
However, there can be no assurance that the Company will not be considered a
FPHC for the current or any future taxable year.
Foreign Investment Company
If (a) 50% or more of the total voting power or the total value of the
Company's outstanding shares is owned (including through ownership of ADRs),
directly or indirectly (pursuant to rules of constructive ownership), by
citizens or residents of the United States, U.S. partnerships or corporations,
or U.S. estates or trusts (as defined for U.S. federal income tax purposes), and
(b) the Company is found to be engaged primarily in the business of investing,
reinvesting, or trading in securities, commodities, or any interest therein, the
Company may be treated as a "Foreign Investment Company" ("FIC"), causing all or
part of any gain realized by a U.S. Holder selling or exchanging ADRs of the
Company to be treated as ordinary income rather than capital gain. The Company
does not believe that it currently constitutes a FIC. However, there can be no
assurance that the Company will not be considered a FIC for the current or any
future taxable year.
Controlled Foreign Corporation
If more than 50% of the total voting power or the total value of the
Company's outstanding shares is owned (including through ownership of ADRs),
actually or constructively, by citizens or residents of the United States, U.S.
partnerships or corporations, or U.S. estates or trusts (as defined for U.S.
federal income tax purposes), each of which owns (including through ownership of
ADRs), actually or constructively, 10% or more of the total voting power of the
Company's outstanding shares (each a "10% Shareholder"), the Company would be
treated as a "Controlled Foreign Corporation" ("CFC").
47
The classification of the Company as a CFC would cause many complex
results, including that 10% Shareholders would generally (i) be treated as
having received a current distribution of the Company's "Subpart F income" and
(ii) would also be subject to current U.S. federal income tax on their pro rata
shares of the Company's earnings invested in "United States property." In
addition, gain from the sale or other taxable disposition of ADRs of the Company
by a U.S. Holder that is or was a 10% Shareholder at any time during the
five-year period ending with the sale is treated as a dividend to the extent of
earnings and profits of the Company attributable to the ADRs sold or exchanged.
If the Company is classified as both a Passive Foreign Investment Company as
described below and a CFC, the Company generally will not be treated as a
Passive Foreign Investment Company with respect to 10% Shareholders.
The Company does not believe that it currently constitutes a CFC. However,
there can be no assurance that the Company will not be considered a CFC for the
current or any future taxable year. The CFC rules are very complicated, and U.S.
Holders should consult their own tax advisor regarding the CFC rules and how
these rules may affect their U.S. federal income tax situation.
Passive Foreign Investment Company
Special U.S. federal income tax rules apply to U.S. Holders of shares
(including ADRs representing such shares) in a "Passive Foreign Investment
Company" ("PFIC"). In general, a PFIC is any non-United States corporation if,
for any taxable year, either (a) 75% or more of its gross income is "passive
income" (the "Income Test") or (b) the average percentage, by fair market value
(or, if the corporation is not publicly traded and either is a CFC or makes an
election, by adjusted tax basis), of its assets that produce or are held for the
production of "passive income" is at least 50% (the "Asset Test"). Passive
income includes, for example, dividends, interest, certain rents and royalties,
certain gains from the sale of stock and securities, and certain gains from
commodities transactions.
For purposes of the Income Test and the Assets Test, if a foreign
corporation owns (directly or indirectly) at least 25% by value of the stock of
another corporation, such foreign corporation shall be treated as if it (a) held
a proportionate share of the assets of such other corporation, and (b) received
directly its proportionate share of the income of such other corporation. Also,
for purposes of such tests, passive income does not include any interest,
dividends, rents or royalties that are received or accrued from a "related"
person to the extent such amount is properly allocable to the income of such
related person which is not passive income. For these purposes, a person is
related with respect to a foreign corporation if such person "controls" the
foreign corporation or is controlled by the foreign corporation or by the same
persons that control the foreign corporation. For these purposes, "control"
means ownership, directly or indirectly, of stock possessing more than 50% of
the total voting power of all classes of stock entitled to vote or of the total
value of stock of a corporation.
U.S. Holders owning common shares of a PFIC are subject to the highest
rate of tax on ordinary income in effect for the applicable taxable year and to
an interest charge based on the value of deferral of tax for the period during
which the common shares (including ADRs representing such shares) of the PFIC
are owned with respect to certain "excess distributions" on and dispositions of
PFIC stock. However, if the U.S. Holder makes a timely election to treat a PFIC
as a qualified electing fund ("QEF") with respect to such shareholder's interest
therein, the above-described rules generally will not apply. Instead, the
electing U.S. Holder would include annually in his gross income his pro rata
share of the PFIC's ordinary earnings and net capital gain regardless of whether
such income or gain was actually distributed. A U.S. Holder of a QEF can,
however, elect to defer the payment of U.S. federal income tax on such income
inclusions. In addition, subject to certain limitations, U.S. Holders owning,
actually or constructively, marketable (as specifically defined) stock in a PFIC
will be permitted to elect to mark that stock to market annually, rather than be
subject to the tax regime described above. Amounts included in or deducted from
income under this alternative (and actual gains and losses realized upon
disposition, subject to certain limitations) will be treated as ordinary gains
or losses.
The Company believes that it did not constitute a PFIC for its fiscal year
ended December 31, 2002. However, there can be no assurance that the Company
will not be considered a PFIC for the current or any future taxable year. There
can be no assurance that the Company's determination concerning its PFIC status
will not be challenged by the IRS, or that it will be able to satisfy record
keeping requirements that will be imposed on QEFs in the event that it qualifies
as a PFIC.
The PFIC rules are very complicated, and U.S. Holders should consult their
own tax advisors regarding the PFIC rules and how these rules may affect their
U.S. federal income tax situation.
F. DIVIDENDS AND PAYING AGENTS
Not applicable.
48
G. STATEMENT BY EXPERTS
Not applicable.
H. DOCUMENTS ON DISPLAY
The Company electronically files certain documents with the SEC including
its Annual Report of Foreign Private Issuers on Form 20-F; Report of Foreign
Issuer on Form 6-K; and any related amendments and supplements thereto. You may
read and copy any materials the Company files with the SEC at the SEC's Public
Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain
information regarding the Public Reference Room by calling the SEC at
1-800-SEC-0330. In addition, the SEC maintains an internet website at
www.sec.gov that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the SEC.
The Company provides a link to the SEC's website on its internet website,
www.petsec.com.au. Information on the Company's website does not constitute part
of this Annual Report. You may also contact the Company in the U.S.A. at
337-989-1942, extension 208, for paper copies of these reports free of charge.
I. SUBSIDIARY INFORMATION
Not applicable.
ITEM 11 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from adverse changes in commodity
prices, interest rates, and currency exchange rates.
Commodity Price Risk. The Company is an oil and natural gas exploration
and production company, and, thus sells natural gas and crude oil. As a result,
the Company's financial results can be significantly affected as these commodity
prices fluctuate widely in response to changing market forces. During 2004, the
Company used natural gas swap agreements and costless collars as a hedge to
reduce the risk of price fluctuations on a portion of its future production. In
the future, the Company will continue to use swaps and other derivative
financial instruments such as collars as a hedging strategy to manage commodity
prices associated with oil and natural gas sales and to reduce the impact of
commodity price fluctuations. The Company uses the hedge or deferral method of
accounting for these instruments and, as a result, gains and losses on commodity
derivative financial instruments are generally recognized in the same period as
the sale of the hedged production is recognized. See "Item 5 - Operating and
Financial Review and Prospects -- Hedging Transactions." The Company does not
enter into derivative financial instruments for speculative or trading purposes.
The following table shows information on the Company's zero-cost collars
and fixed price natural gas swaps in place for 2005 as of December 31, 2004:
Type of Remaining Notional Quantity Average Price Received Approximate Fair Value at
Agreement Term (MMBtu per day) per MMBtu December 31, 2004
- ----------------- ------------ ----------------- ---------------------- -------------------------
Zero cost collars Jan-Mar 2005 4,000 $6.00/$7.08* $ 45,000
Swaps Jan-Mar 2005 2,000 $ 7.58 $ 249,000
Swaps Jan-Dec 2005 2,000 $ 6.34 $ 58,000
Swaps Jan-Dec 2005 2,000 $ 7.72 $ 1,054,000
*Floor/ceiling
Interest Rate Risk. Currently, the Company has no open interest rate swap
or interest rate lock agreements. The Company's only exposure to interest rate
risk is in relation to the floating rate earned on the Company's cash balances.
Currency Exchange Rate Risk. Fluctuations in the Australian dollar/US
dollar exchange rate have not had a material impact on the underlying
performance of the Company. The Company's policy is not to hedge the Australian
dollar/US dollar exchange rate risk except through natural hedging techniques
such as maintaining cash balances in US dollar accounts to support operations
conducted in US dollars.
49
ITEM 12 - DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Not applicable.
PART II
ITEM 13 - DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
The Company had no material defaults, dividend arrearages or delinquencies
in fiscal year ended December 31, 2004.
ITEM 14 - MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF
PROCEEDS
Not applicable.
ITEM 15 - CONTROLS AND PROCEDURES
Each of our Chief Executive Officer and Chief Financial Officer has
evaluated the effectiveness of the Company's disclosure controls and procedures
as of the end of the period covered by this report. These disclosure controls
and procedures are those controls and other procedures the Company maintains,
which are designed to ensure that all of the information required to be
disclosed by the Company in all of its combined and separate periodic reports
filed with the SEC is recorded, processed, summarized and reported, within the
time periods specified in the SEC's rules and forms. Disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by the Company in their reports
filed or submitted under the Securities Exchange Act of 1934 is accumulated and
communicated to its management, including the Company's Chief Executive Officer
and Chief Financial Officer, as appropriate to allow those persons to make
timely decisions regarding required disclosure. No significant deficiencies or
material weaknesses were detected. Subsequent to the date when the disclosure
controls and procedures were evaluated, there have not been any significant
changes in our controls or procedures or in other factors that could
significantly affect such controls or procedures.
ITEM 16A - AUDIT COMMITTEE FINANCIAL EXPERT
Our Board of Directors has determined that it has at least one financial
expert serving on its Audit Committee in the person of Mr. David A. Mortimer,
Chairman of the Audit Committee. Mr. Mortimer is an independent Director of the
Company.
ITEM 16B - CODE OF ETHICS
We have adopted a code of ethics that applies to Chief Executive Officer,
Chief Financial Officer and Principal Accounting Officer. We previously filed
our code of ethics as part of our annual report on Form 20-F for the year ended
December 31, 2003. Our code of ethics is also available at our web site at
www.petsec.com.au/Ethics.htm.
ITEM 16C - PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table presents fees for professional audit services rendered
by KPMG for the audit of the Company's annual financial statements for 2003 and
2004, and fees billed for other services rendered by KPMG.
2003 2004
------- --------
Audit fees $78,506 $110,440
All other fees - -
------- --------
Total fees (1) $78,506 $110,440
------- --------
(1) Total fees include amounts billed in foreign currencies, and are translated
to US Dollars as of the date of approval of the fees.
50
ITEM 16D - EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
Not Applicable.
ITEM 16E - PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED
PURCHASERS
Not applicable.
PART III
ITEM 17 - FINANCIAL STATEMENTS
Not applicable - see Item 18 below.
ITEM 18 - FINANCIAL STATEMENTS
The US Dollar Financial Statements of the Company and the Independent
Auditors' Report are included on pages F-1 through F-29 of this Form 20-F.
ITEM 19 - EXHIBITS
EXHIBITS
1.1 Constitution of the Company.
4.1 Form of employment contract agreement for Australian-based
executives.
4.2 Form of employment contract agreement for US-based executives.
8.1 Subsidiaries of the Company.
31.1 Certification of the CFO pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of the CEO pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification of CEO pursuant to section 906 of the Sarbanes-Oxley
Act of 2002.
32.2 Certification of CFO pursuant to section 906 of the Sarbanes-Oxley
Act of 2002.
99.1 Consent of Registered Independent Public Accounting Firm.
99.2 Consent of Independent Petroleum Engineers
99.3 Code of Ethics incorporated herein by reference to Exhibit 99.3 to
Form 20-F for the Company for the year ended December 31, 2003.
51
SIGNATURES
The Registrant, Petsec Energy Ltd, hereby certifies that it meets all of
the requirements for filing on Form 20-F and that it has duly caused and
authorized the undersigned to sign this annual report on its behalf.
By: /s/ Fiona A. Robertson
----------------------
Fiona A. Robertson
Chief Financial Officer
52
P e t s e c E n e r g y L t d
ACN 000 602 700
US Dollar Financial Statements
Under US Generally Accepted
Accounting Principles
December 31, 2004
Consolidated Balance Sheets F2
Consolidated Statements of Operations F3
Consolidated Statements of Comprehensive Income (Loss) F4
Consolidated Statements of Cash Flows F5
Notes to the Consolidated Financial Statements F6
Report of Independent Registered Public Accounting Firm F29
F1
CONSOLIDATED BALANCE SHEETS
Petsec Energy Ltd and subsidiaries
December 31 December 31
(US dollars, in thousands) 2003 2004
- ---------------------------------------------------------- ----------- -----------
ASSETS (NOTE 1(b))
Current assets
Cash $ 12,462 $ 9,518
Deposits (note 13) 381 -
Trade debtors 3,663 6,930
Other receivables 104 64
Fair value of derivative financial instruments - 1,406
Deferred tax assets (note 2) - 7,975
Prepayments 367 2,016
--------- ---------
Total current assets 16,977 27,909
--------- ---------
Non-current assets
Deposits (notes 10(a) and 13) 1,734 -
Proved and unproved oil and gas properties 19,157 33,542
Investment securities (note 6) 345 543
Property, plant and equipment (note 7) 231 245
Deferred tax assets (note 2) - 1,288
--------- ---------
Total non-current assets 21,467 35,618
--------- ---------
Total assets $ 38,444 $ 63,527
--------- ---------
LIABILITIES AND SHAREHOLDERS' EQUITY (NOTE 1(b))
Current liabilities
Accounts payable and accrued liabilities (note 8) $ 7,093 $ 10,337
Share subscriptions received in advance (note 11) 7,253 -
Short-term loans (note 10(a)) 328 1,175
--------- ---------
Total current liabilities 14,674 11,512
--------- ---------
Long-term liabilities
Other accrued liabilities (note 9) 567 1,116
--------- ---------
Total long-term liabilities 567 1,116
--------- ---------
Shareholders' equity
Share capital - 250,000,000 (2003: 250,000,000)
ordinary shares of 20 Australian cents each. Shares issued
119,222,841 (2003: 105,736,041). (notes 11 and 12) 120,791 130,106
Accumulated other comprehensive loss (note 12) (2,611) (1,964)
Accumulated deficit (94,977) (77,243)
--------- ---------
Total shareholders' equity 23,203 50,899
--------- ---------
Total liabilities and shareholders' equity $ 38,444 $ 63,527
--------- ---------
See accompanying notes to consolidated financial statements.
F2
CONSOLIDATED STATEMENTS OF OPERATIONS
Petsec Energy Ltd and subsidiaries
Twelve months ended
December 31 December 31 December 31
(US dollars, in thousands except earnings per share) 2002 2003 2004
- ---------------------------------------------------------------- ----------- ----------- -----------
Oil and gas sales (net of royalties payable) $ - $ 23,270 $ 32,575
Oil and gas royalties 201 1,949 223
------- --------- ---------
Total revenues $ 201 25,219 32,798
------- --------- ---------
Operating expenses
Lease operating expenses - 1,557 1,776
Depletion, depreciation, amortization, accretion and reclamation 34 6,574 12,361
Exploration expenditure 1,176 1,329 1,452
Dry hole and abandonment costs 1,066 - 4,119
Major maintenance expense - - 592
Impairment expense - 38 201
General, administrative and other expenses 1,691 3,519 4,657
Stock compensation expense 40 90 83
------- --------- ---------
Total operating expenses 4,007 13,107 25,241
Profit (loss) on sale of assets (8) - 2
------- --------- ---------
Income (loss) from operations $(3,814) $ 12,112 $ 7,559
Other income 137 364 89
Interest expense - (10) (32)
Interest income $ 136 $ 142 $ 311
------- --------- ---------
Income (loss) before income tax (3,541) 12,608 7,927
Income tax benefit (note 2) 254 492 9,807
------- --------- ---------
Net income (loss) $(3,287) 13,100 17,734
------- --------- ---------
Earnings (loss) per common share (note 3)
- - basic $ (0.03) $ 0.12 $ 0.15
- - diluted $ (0.03) $ 0.12 $ 0.15
See accompanying notes to consolidated financial statements.
F3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Petsec Energy Ltd and subsidiaries
Twelve months ended
December 31 December 31 December 31
(US dollars, in thousands) 2002 2003 2004
- ----------------------------------------------------------- ----------- ----------- -----------
Net income (loss) $(3,287) $ 13,100 $ 17,734
------- -------- --------
Other comprehensive income (loss)
Foreign currency translation adjustments (89) (26) (413)
Deferred gain (loss) on hedging activities - (346) 1,752
Aggregate income tax benefit (expense) related to other
comprehensive income - 137 (692)
------- -------- --------
Comprehensive income (loss) $(3,376) $ 12,865 $ 18,381
------- -------- --------
See accompanying notes to consolidated financial statements.
F4
CONSOLIDATED STATEMENTS OF CASH FLOWS
Petsec Energy Ltd and subsidiaries
Twelve months ended
December 31 December 31 December 31
(US dollars, in thousands) 2002 2003 2004
- ----------------------------------------------------------- ----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (3,287) $ 13,100 $ 17,734
Adjustment to reconcile net income (loss) to cash provided by
(used in) operating activities:
- - depletion, depreciation, amortization, accretion and reclamation 34 6,574 12,361
- - dry holes and abandonments 1,066 - 4,119
- - impairment expense - 38 201
- - (gain) loss on sale of investments/assets 8 - (2)
- - employee stock compensation 40 90 83
- - provision for employee benefits 13 157 19
- - deferred income tax benefit (254) (492) (9,807)
Changes in operating assets and liabilities:
- - accounts receivable (546) (3,462) (3,267)
- - other current assets 9 17 (3,015)
- - accounts payable and accrued liabilities 189 2,567 3,606
-------- -------- --------
Net cash provided by (used in) operating activities (2,728) 18,589 22,032
-------- -------- --------
INVESTING ACTIVITIES
Additions to oil and gas properties and property, plant and
equipment (6,487) (13,372) (27,957)
Purchases of investment securities (1,698) (1,453) (209)
Proceeds from sale of fixed assets 1 - 5
Distribution proceeds from bankruptcy trustee - 82 -
Proceeds from sale of investment securities 14 1,169 2,115
-------- -------- --------
Net cash provided by (used in) investing activities (8,170) (13,574) (26,046)
-------- -------- --------
FINANCING ACTIVITIES
Repayment of short-term loans - (402) (908)
Proceeds from issuance of shares - 7,253 1,978
-------- -------- --------
Net cash provided by financing activities - 6,851 1,070
-------- -------- --------
Net increase (decrease) in cash (10,898) 11,866 (2,944)
Cash at beginning of the period 11,494 596 12,462
-------- -------- --------
CASH AT THE END OF THE PERIOD $ 596 $ 12,462 $ 9,518
-------- -------- --------
See accompanying notes to consolidated financial statements.
F5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PETSEC ENERGY LTD AND SUBSIDIARIES
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND PRACTICES
The significant accounting policies which have been adopted in the preparation
of this financial report are:
(a) DESCRIPTION OF BUSINESS
Petsec Energy Ltd is an independent exploration, development and production
company operating in the shallow waters of the Gulf of Mexico and onshore
Louisiana, U.S.A. and in the Beibu Gulf, offshore China. The primary business of
the Company is exploration, development and production of oil and natural gas;
therefore, the Company is directly affected by fluctuating economic conditions
in the oil and natural gas industry.
(b) BASIS OF PRESENTATION
The consolidated financial statements have been prepared in accordance with US
GAAP, with the US dollar as the reporting currency.
(c) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the financial statements of the
Company and its subsidiaries. All significant intercompany balances and
transactions have been eliminated on consolidation.
(d) OIL AND NATURAL GAS PROPERTIES
Successful efforts method of accounting
The Company accounts for its natural gas and crude oil exploration and
development activities utilizing the successful efforts method of accounting.
Under this method, costs of productive exploratory wells, development dry holes
and productive wells and costs to acquire mineral interests are capitalized.
Exploration costs, including personnel costs, certain geological and geophysical
expenses including seismic costs and delay rentals for oil and natural gas
leases, are charged to expense as incurred. Exploratory drilling costs are
initially capitalized, but charged to expense if and when the well is determined
not to have found reserves in commercial quantities. As detailed below,
capitalized costs are subject to impairment tests. Each part of the impairment
test is subject to a large degree of management judgment, including the
determination of a property's reserves, future cash flows, and fair value.
Impairment of oil and natural gas properties
The Company reviews its oil and natural gas properties for impairment at least
annually and whenever events and circumstances indicate a decline in the
recoverability of their carrying value. The Company estimates the expected
future cash flows of its oil and natural gas properties and compares such future
cash flows to the carrying amount of the properties to determine if the carrying
amount is recoverable. If the carrying amount exceeds the estimated undiscounted
future cash flows, the Company will adjust the carrying amount of the oil and
natural gas properties to their fair value. The factors used to determine fair
value include, but are not limited to, estimates of proved reserves, future
commodity pricing, future production estimates, anticipated capital
expenditures, and a discount rate commensurate with the risk associated with
realizing the expected cash flows projected.
Management's assumptions used in calculating oil and natural gas reserves or
regarding the future cash flows or fair value of our properties are subject to
change in the future. Any change could cause impairment expense to be recorded,
reducing our net income and the carrying value of the related asset. Future
prices received for production and future production costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of calculating
reserve estimates. There can be no assurance that the proved reserves will be
developed within the periods estimated or that prices and costs will remain
constant. Actual production may not equal the estimated amounts used in the
preparation of reserve projections. As these estimates change, the amount of
calculated reserves changes. Any change in reserves directly impacts our
estimated future cash flows from the property, as well as the property's fair
value. Additionally, as management's views related to future prices change, this
changes the calculation of future net cash flows and also affects fair value
estimates. Changes in either of these amounts will directly impact the
calculation of impairment.
Given the complexities associated with oil and natural gas reserve estimates and
the history of price volatility in the oil and natural gas markets, events may
arise that would require the Company to record an impairment of the recorded
book values associated with oil and natural gas properties. An impairment loss
of $201,000 was recorded during the year ended December 31, 2004 (2003:
$38,000).
F6
Depreciation, Depletion, and Amortization
The Company records DD&A expense on its producing oil and natural gas properties
using a units-of-production method based on the ratio of actual production to
remaining reserves as estimated by independent petroleum engineers. The effect
of any revisions to the estimated remaining reserves on DD&A is only considered
in future periods and no adjustment is made to accumulated DD&A applicable to
prior periods. Because revisions to estimated reserves are only considered
prospectively when calculating DD&A expense, DD&A expense in current and future
periods may be significantly impacted by DD&A attributable to past periods.
Asset retirement obligations
The Company recognizes a liability for the legal obligation associated with the
retirement of a long-lived assets that results from the acquisition,
construction, development, and (or) the normal operation of oil and natural gas
properties. The initial recognition of a liability for an asset retirement
obligation, which is discounted using a credit-adjusted risk-free interest rate,
increases the carrying amount of the related long-lived asset by the same amount
as the liability. In periods subsequent to initial measurement, period-to-period
changes in the liability are recognized for the passage of time (accretion) and
revisions to the original estimate of the liability. Additionally, the
capitalized asset retirement cost is subsequently allocated to expense using a
systematic and rational method over its useful life.
(e) DEPRECIATION - OTHER PROPERTY, PLANT AND EQUIPMENT
Depreciation is provided on other property, plant and equipment so as to write
off the assets progressively over their estimated useful life using the straight
line method.
Estimated
useful life in
Method years
------------- --------------
Furniture and fittings Straight line 5 to 7
Office machines and equipment Straight line 3 to 5
Leasehold improvements Straight line 5 to 7
(f) INVESTMENTS
(i) Joint operating arrangements
The Company's interest in unincorporated joint operating arrangements is brought
to account by including in the respective financial statement classes the amount
of:
- - the Company's interest in each of the individual assets employed in the joint
operating arrangements;
- - the liabilities of the Company in relation to the joint operating
arrangements; and
- - the Company's interest in the revenues earned and the expenses incurred in
relation to the joint operating arrangements.
(ii) Investment securities
Investment securities at December 31, 2004 and 2003 consist of equity
securities. The Company classifies its equity securities having a readily
determinable fair value into trading or available-for-sale.
Trading and available-for-sale securities are recorded at fair value. Unrealized
holding gains and losses, net of the related tax effect, on available-for-sale
securities are excluded from earnings and are reported as a separate component
of other comprehensive income until realized. Realized gains and losses from the
sale of available-for-sale securities are determined on a
specific-identification basis.
A decline in the market value of any available-for-sale security below cost that
is deemed to be other-than-temporary results in a reduction in carrying amount
to fair value. The impairment is charged to earnings and a new cost basis for
the security is established. To determine whether an impairment is
other-than-temporary, the Company considers whether it has the ability and
intent to hold the investment until a market price recovery and considers
whether evidence indicating the cost of the investment is recoverable outweighs
evidence to the contrary. Evidence considered in this assessment includes the
reasons for the impairment, the severity and duration of the impairment, changes
in value subsequent to year-end, and forecasted performance of the investee.
F7
Premiums and discounts are amortized or accreted over the life of the related
available-for-sale security as an adjustment to yield using the
effective-interest method. Dividend and interest income are recognized when
earned.
Unlisted shares are recorded at cost, which the Company believes is not
significantly different from fair value.
(g) REVENUE RECOGNITION
Oil and natural gas sales are brought to account net of royalties payable and
when the products are 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.
Revenue from oil and natural gas royalties are recognized on an accrual basis in
accordance with the terms of underlying royalty agreements.
(h) DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
From time to time, the Company uses derivative financial instruments, such as
natural gas swaps and costless collars, to reduce the risk of price fluctuations
on a portion of its future production. The Company will generally limit its
hedges to 50% to 60% of its anticipated production in any given period.
Derivative financial instruments qualifying for hedge accounting treatment are
recorded as an asset or liability measured at fair value and subsequent changes
in fair value are recognized in equity through other comprehensive income, net
of related taxes, to the extent the hedge is effective. The cash settlement of
effective cash flow hedges is recorded into revenue in the same period that the
underlying hedged production occurs. Derivative financial instruments not
qualifying for hedge accounting treatment, if any, are recorded in the balance
sheet and changes in fair value are recognized in earnings as derivative expense
(income). At December 31, 2004 and December 31, 2003, the Company's natural gas
swap agreements were considered effective cash flow hedges. The fair value of
these derivative financial instruments are recognized on the balance sheet as
"Fair value of derivative financial instruments" if they are assets and are
recorded in accrued liabilities (see note 8) if they are liabilities. The
Company uses a regression analysis to retrospectively test the hedging
effectiveness of these derivative financial instruments. Hedging losses recorded
during 2004 were $1.1 million (2003: less than $0.1 million; 2002: nil). (See
note 10 - Financing arrangements, liquidity and financial instruments disclosure
and concentrations).
(i) EMPLOYEE ENTITLEMENTS
The provision for employee entitlements to wages, salaries and annual leave
represents the amount of the present obligation to pay resulting from employees'
services provided up to balance date. The provision has been calculated based on
estimated wages to be paid out and salary rates and includes related on-costs.
Employer contributions to superannuation funds are charged against earnings.
Further information is set out in note 13.
A liability is recognized for employee incentive plans based on a percentage of
operating profits.
(j) INCOME TAXES
The Company accounts for income taxes following the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date. Where realization of a deferred tax
asset is not considered more likely than not, a valuation allowance is
established. See note 2 for further discussion.
(k) FOREIGN CURRENCY TRANSLATION
Substantially all of the Company's oil and natural gas operations are conducted
in US dollars. The Company generally maintains its surplus cash balances in US
dollar accounts.
Foreign currency transactions are translated at the rates of exchange ruling at
the date of the transactions. Amounts receivable and payable in foreign
currencies are translated at the rates of exchange ruling at balance date.
Exchange differences relating to amounts receivable and payable in foreign
currencies are brought to account in earnings as exchange gains or losses in the
financial period in which the exchange rates change. The Company had no
significant foreign exchange gains or losses during each of the last three
years.
F8
The balance sheets of the Company and its Australian subsidiaries are translated
at the rates of exchange ruling at balance date. The statements of operations
are translated at an average rate for the period. Exchange differences arising
on translation are taken directly to the foreign currency translation adjustment
and form part of the accumulated other comprehensive loss.
The exchange rates (US dollars for one Australian dollar) used in the
preparation of these financial statements are:
Twelve months ended
December 31,
2002 2003 2004
------ ------ ------
Average exchange rate 0.5391 0.6515 0.7341
Exchange rate at period end 0.5598 0.7431 0.7784
(l) RECLASSIFICATIONS
Certain prior period amounts have been reclassified to achieve consistency in
disclosure with the current financial year presentation.
(m) STOCK COMPENSATION
The Company has an Employee Option Plan and issues options to employees and
certain consultants of the Company to purchase stock in the Company.
The Company recognizes stock compensation expense in respect of the options
granted to the Company's employees and certain consultants in accordance with
Statement of Financial Accounting Standards No. 123 "Accounting for Stock-Based
Compensation", under which it recognizes the fair value of all stock-based
awards on the date of grant as expense over the vesting period. The amount is
recorded as an increase to share capital.
The fair value was determined using the Black-Scholes valuation method. The
calculation takes into account the exercise price, expected life, current price
of underlying stock, expected volatility of 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 2004 were 1.2 to 4.5 years (weighted average 2.6 years); 49.90% -
86.90%; 0% and 5.05% - 5.53% per annum, respectively; 1.2 to 4.5 years (weighted
average 3.4 years); 86.90%; 0% and 5.53% per annum, respectively, in 2003 and
1.3 to 4.3 years (weighted average 2.8 years); 77.10%; 0% and 4.68% per annum,
respectively, in 2002. The average fair value per option granted in 2004 using
the Black Scholes valuation method was A$0.38 per option (2003: A$0.30; 2002:
A$0.07).
(n) RECEIVABLES
The collectability of debts is assessed at reporting date and specific provision
is made for any doubtful debts.
Trade debtors
Trade debtors to be settled within 30 to 60 days are carried at amounts due.
(o) USE OF ESTIMATES
The preparation of the financial statements requires management to make
estimates and assumptions which affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expenses during
the reported period. Significant items subject to such estimates and assumptions
include impairment of oil and natural gas properties, depreciation, depletion
and amortisation of capitalised costs and income taxes. Actual results could
differ from those estimates.
(p) RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED
In December 2004, the FASB issued FASB Statement No. 123 (revised 2004),
Share-Based Payment, which addresses the accounting for transactions in which an
entity exchanges its equity instruments for goods or services, with a primary
focus on transactions in which an entity obtains employee services in
share-based payment transactions. This statement is a revision to Statement 123
and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and
its related implementation guidance. This Statement will be effective for the
Company as of January 1, 2006. We are currently assessing the impact of the
adoption of this Statement though we do not expect that the initial adoption of
this Statement will have a significant impact on our consolidated financial
position or our results of operations.
In April 2005, the FASB issued FASB Staff Position FAS 19-1,
Accounting for Suspended Well Costs, which will apply to enterprises that use
the successful efforts method of accounting as described in
F9
FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas
Producing Companies. The FSP will require the Company to apply more judgment
than was required by Statement 19 in evaluating whether the costs of exploratory
wells meet the criteria for continued capitalization. The FSP is an amendment to
Statement 19, paragraphs 31 - 34, and prescribes that exploratory well costs
should continue to be capitalized when the well has found a sufficient quantity
of reserves to justify its completion as a producing well and the Company is
making sufficient progress assessing the reserves and the economic and viability
of the project. The FSP will be effective for the Company as of 1 January 2006.
We are currently assessing the impact of the adoption of this FSP though we do
not expect that the initial adoption of this Statement will have a significant
impact on our consolidated financial position or our results of operations.
F10
2. INCOME TAXES
Income (loss) before income taxes for the years ended December 31, 2002, 2003
and 2004 were taxed under the following jurisdictions:
Twelve months ended
December 31 December 31 December 31
(US Dollars, in thousands) 2002 2003 2004
- ------------------------------------------------ ------------- --------------- ---------------
Australia $ (846) $ (1,091) $ (1,241)
U.S. (2,695) 13,699 9,168
------------- --------------- ---------------
$ (3,541) $ 12,608 $ 7,927
------------- --------------- ---------------
Income tax expense (benefit) is presented below:
Current:
Australia $ - $ - $ -
U.S. - 250 -
------------- --------------- ---------------
$ - $ 250 $ -
------------- --------------- ---------------
Deferred:
Australia $ (254) $ (742) $ -
U.S. - - (9,807)
------------- --------------- ---------------
$ (254) $ (742) $ (9,807)
------------- --------------- ---------------
Income tax benefit $ (254) $ (492) $ (9,807)
------------- --------------- ---------------
Income tax benefit differed from the amounts computed by applying an income tax
rate of 30% (the statutory rate in effect in Australia) (2003: 30%, 2002: 30%)
to income (loss) before income taxes as a result of the following:
Twelve months ended
December 31 December 31 December 31
(US Dollars, in thousands) 2002 2003 2004
- ------------------------------------------------ ------------- --------------- ---------------
Computed "expected" tax expense (benefit) $ (1,062) $ 3,782 $ 2,378
Increase (reduction) in income taxes resulting
from:
Adjustment of prior year net operating loss 604 1,099 (242)
U.S. income taxes at different rates (162) 822 485
Reversal of contingencies (166) (840) -
Change in valuation allowance 611 (5,329) (12,422)
Other (79) (26) (6)
------------- --------------- ---------------
Actual tax benefit $ (254) $ (492) $ (9,807)
------------- --------------- ---------------
The significant components of deferred income tax benefit attributable to income
from continuing operations for the years ending December 31, 2002, 2003 and 2004
are as follows:
Twelve months ended
December 31 December 31 December 31
(US Dollars, in thousands) 2002 2003 2004
- ------------------------------------------------ ------------- --------------- ---------------
Deferred tax benefit, exclusive of the effects of
other components below $ (254) $ (742) $ (35)
Decrease in beginning-of-the-year balance of
valuation allowance for deferred tax assets - - (9,772)
------------- --------------- ---------------
(254) (742) (9,807)
------------- --------------- ---------------
F11
2. INCOME TAXES (CONTINUED)
The tax effects of temporary differences that give rise to significant portions
of the deferred tax assets and deferred tax liabilities at December 31, 2003 and
2004 are presented below.
December 31 December 31
2003 2004
(US Dollars, in thousands)
--------------------------
Deferred tax assets:
Employee entitlement provisions $ 268 $ 91
Tax credit carryforward 250 250
Net operating loss carryforward 18,942 18,065
----------- -----------
Total deferred tax assets $ 19,460 $ 18,406
Less valuation allowance (17,419) (4,997)
Net deferred tax assets 2,041 13,409
Deferred tax liabilities:
Proved and unproved oil and gas properties (2,030) (3,591)
Unrealized gain on derivative financial instruments - (555)
Net unrealized foreign exchange gains transferred to the
foreign currency translation adjustment (11) -
----------- -----------
Total deferred tax liability (2,041) (4,146)
----------- -----------
Net deferred tax asset $ - $ 9,263
----------- -----------
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. The ultimate realization of deferred tax assets is
dependent upon the generation of future taxable income during the periods in
which those temporary differences and net operating loss carryforwards become
deductible. Management considers the scheduled reversal of deferred tax
liabilities, projected future taxable income and tax planning strategies in
making this assessment. At January 1, 2002, the deferred tax asset valuation
allowance was $21,137,000. The valuation allowance was required because of a
series of previous operating losses, which therefore led management to conclude
that it was more likely than not that the benefit of its existing net deferred
tax assets would not be realized in the future. During 2002, the deferred tax
asset valuation allowance was increased by $611,000 primarily because the
Company incurred a tax operating loss for the year and determined that it was
more likely than not that the benefit of these additional net operating loss
carryforwards would not be realized. In 2003, the valuation allowance was
decreased by $5,329,000 primarily as a result of the utilization of some of the
Company's net operating loss carryforwards following the Company's generation of
taxable income for that year. During 2004, the Company generated taxable income
during the year (resulting in utilization of more of its net operating loss
carryforwards) and also revised its assessment of future taxable income.
Consequently, the deferred tax asset valuation allowance decreased by
$12,422,000. The resulting net deferred tax asset could be reduced in the near
term if estimates of future taxable income (approximately $27.9 million) during
the carryforward period are reduced.
At December 31, 2004, the Company has gross operating loss carryforwards for
Australian income tax purposes of approximately US$4.4 million which are
available to offset future taxable income. These losses have no expiry.
At December 31, 2004 the Company has gross operating loss carryforwards of $47.9
million for United States Federal and State income tax purposes. The
carryforwards from previous tax periods will expire from 2016 through 2021.
The Company has alternative minimum tax credit carryforwards of $250,000, which
are available to reduce future U.S. Federal regular income taxes, if any, over
an indefinite period.
F12
3. EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per ordinary share is computed by dividing net income
(loss) by the weighted average number of ordinary shares outstanding during the
respective period. Diluted earnings per ordinary share is computed by dividing
net income by the weighted average number of ordinary shares outstanding plus
potentially dilutive ordinary shares.
December 31 December 31 December 31
2002 2003 2004
(in thousands)
-----------------------------------------
Weighted average number of ordinary shares used in the
calculation of the basic earnings per share 105,736 105,736 118,830
Incremental shares - 2,047 2,673
------- ------- -------
Weighted average number of ordinary shares used in the
calculation of the diluted earnings per share 105,736 107,783 121,503
------- ------- -------
A difference between the weighted average number of ordinary shares used for
basic and diluted earnings per share arises due to the dilutive effect of
unexercised employee stock options. The incremental common stock equivalents
were calculated using the treasury stock method. There was no difference between
the basic and diluted weighted average number of ordinary shares in 2002 as the
exercise prices of the 3,628,000 unexercised stock options were above the
average market price, and therefore were anti-dilutive.
On January 6, 2004 the Company completed a placement of 12,846,800 shares, which
was arranged in December 2003 (See note 11 - Share capital).
4. INTERESTS IN JOINT OPERATING ARRANGEMENTS
The Company accounts for joint operating arrangements proportionally in
accordance with Emerging Issues Task Force Issue 00-01, "Investor Balance Sheet
and Income Statement Display under the Equity Method for Investments in Certain
Partnerships and Other Ventures" (EITF 00-01). Adoption of FIN 46-R did not have
an impact on our accounting for these joint operating arrangements and we
continue to account for these joint operating arrangements under EITF 00-01 as
appropriate.
Included in the assets of the Company are the following items which represent
the Company's interest in the assets and liabilities in unincorporated joint
operating arrangements:
December 31 December 31
2003 2004
(US Dollars, in thousands)
----------------------------
LEASE PERMITS AND CAPITAL EXPENDITURE:
Now in production at cost
- - West Cameron 343 $ 9,063 $ 10,259
- - West Cameron 352 7,813 8,124
Less: Accumulated amortisation (6,481) (14,802)
----------- -----------
$ 10,395 $ 3,581
Not in production
- - Main Pass 89 102 121
- - Main Pass 19 - 1,536
- - Block 22/12 Beibu Gulf 981 1,370
- - Price Lake, Onshore Louisiana - -
- - St James Parish, Onshore Louisiana - 2,440
----------- -----------
1,083 5,467
----------- -----------
Total lease permit and capital expenditure $ 11,478 $ 9,048
----------- -----------
ASSET RETIREMENT OBLIGATION LIABILITY:
- - West Cameron 343 $ 199 $ 217
- - West Cameron 352 80 89
----------- -----------
$ 279 $ 306
----------- -----------
F13
4. INTERESTS IN JOINT OPERATING ARRANGEMENTS (CONTINUED)
December 31 December 31 December 31
2002 2003 2004
(US Dollars, in thousands)
--------------------------------------------
THE CONTRIBUTION OF THE COMPANY'S JOINT OPERATING
ARRANGEMENTS TO INCOME FROM OPERATIONS
- - West Cameron 343 $ - $ 11,589 $ 7,342
- - West Cameron 352 - 3,630 1,117
- - Block 22/12 Beibu Gulf - (302) (1,567)
- - Price Lake, Onshore Louisiana - - (3,188)
---------- ----------- -----------
$ - $ 14,917 $ 3,704
---------- ----------- -----------
The principal activity of all the joint operating arrangements is oil & natural
gas exploration. Listed below is the name of each of the joint operating
arrangements and the percentage interest held in the joint operating arrangement
by the Company:
Working interest held
2003 2004
------------- ------------
Main Pass 89 30.0% 30.0%
Main Pass 19 - 55.0%
West Cameron 343 75.0% to 100% 75.0% to 100%
West Cameron 352 56.3% to 75.0% 56.3%
Block 22/12 Beibu Gulf 25.0% 25.0%
Price Lake, Onshore Louisiana - 25.0%
St James Parish, Onshore Louisiana - 50.0%
5. WHOLLY OWNED INTERESTS NOW IN PRODUCTION
December 31 December 31
2003 2004
(US Dollars, in thousands)
--------------------------
LEASE PERMITS AND CAPITAL EXPENDITURE:
Now in production at cost
- - Vermilion 258 (1) $ 7,160 $ 21,945
Less: Accumulated amortisation - (3,963)
----------- -----------
$ 7,160 $ 17,982
ASSET RETIREMENT OBLIGATION LIABILITY:
- - Vermilion 258 (1) $ - $ 469
----------- -----------
CONTRIBUTION OF AREA OF INTEREST TO INCOME FROM OPERATIONS:
- - Vermilion 258 (1) $ - $ 10,608
----------- -----------
(1) Commenced production in July 2004.
6. INVESTMENTS
Non-current
Listed shares at fair value $ 15 $ 16
Unlisted shares at cost 330 527
----------- -----------
$ 345 $ 543
----------- -----------
7. PROPERTY, PLANT AND EQUIPMENT
- - at cost $ 541 $ 611
- - accumulated depreciation (310) (366)
----------- -----------
$ 231 $ 245
----------- -----------
F14
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
December 31 December 31
2003 2004
(US Dollars, in thousands)
--------------------------
Current
Trade creditors $ 1,038 $ 1,984
Employee related liabilities 384 1,057
Fair value of derivative financial instruments 346 -
Exploration and development accruals 3,457 5,515
Operational accruals 1,444 1,635
MMS/P&A bond accruals 145 146
Other 279 -
----------- -----------
$ 7,093 $ 10,337
----------- -----------
9. OTHER ACCRUED LIABILITIES - NON-CURRENT
Employee entitlements provision $ 286 $ 305
Asset retirement obligations 281 811
----------- -----------
$ 567 $ 1,116
----------- -----------
The Company adopted Statement No. 143, "Accounting for Asset Retirement
Obligations" effective January 1, 2003. The retirement obligations arise out of
the legal requirement for the Company to plug wells and remove facilities and
equipment from the property at the end of the property's useful life. The
associated asset retirement costs were also capitalised as part of the carrying
amount of the oil and natural gas properties. The liabilities for the asset
retirement obligations were discounted and accretion expense was recognised
using the credit-adjusted risk-free interest rate in effect when the liabilities
were initially recognised (ranging from 9% to 12% per annum). The Company had no
asset retirement obligation on the date of adoption.
The following table shows the changes to our asset retirement obligations during
2003 and 2004:
December 31 December 31
2003 2004
(US Dollars, in thousands)
--------------------------
Asset retirement obligations at beginning of year $ - $ 281
Liabilities incurred during the period 263 480
Accretion expense 18 50
----------- -----------
Asset retirement obligation at the end of the period $ 281 $ 811
----------- -----------
10. FINANCING ARRANGEMENTS, LIQUIDITY, FINANCIAL INSTRUMENTS DISCLOSURES AND
SIGNIFICANT CONCENTRATIONS
(a) FINANCING ARRANGEMENTS
At December 31, 2004, the Company had a short-term loan relating to its U.S. oil
and natural gas operations of $1,175,000 (2003: $328,000), held in the accounts
of Petsec Energy Inc. a wholly owned subsidiary. The interest charge on this
liability is 5.15% pa. (2003: 4.9%). The loan which is due to expire in August
2005, is repaid through monthly installments of $150,000.
Effective February 20, 2004, PEI entered into a $2.0 million credit agreement
with a U.S. bank for the purpose of securing letters of credit issued by the
bank and also to allow the refund of $1.7 million of cash collateral previously
posted to secure surety bonds issued to the Minerals Management Service. This
facility was subsequently increased to $3.0 million on July 2, 2004 and to $6.0
million on December 21, 2004.
F15
10. FINANCING ARRANGEMENTS, LIQUIDITY, FINANCIAL INSTRUMENTS DISCLOSURES AND
SIGNIFICANT CONCENTRATIONS (CONTINUED)
PEI incurs fees of 1 3/4% per annum on the amount of letters of credit issued
by the bank. Any call made against a letter of credit by a beneficiary will
constitute a loan under the credit agreement. Principal payments on any such
loan will be payable at the end of each calendar quarter in an amount determined
by the bank. Interest on any outstanding loans will accrue, at PEI's election,
at either (i) the banks prime rate plus 1/2% pa, but no less than 4 1/2% pa or
(ii) at Libor rate plus 3 1/2% pa. Upon final maturity of the credit agreement,
all loans and interest outstanding become due. The final maturity date of the
credit agreement, which was recently extended by one year, is March 31, 2007. To
date, there have been no loans under the credit agreement.
The credit facility is secured by mortgages on PEI's interest in oil and natural
gas properties. The credit facility also contains financial covenants that
require PEI to:
(i) maintain its tangible net worth to be not less than 90% of the tangible
net worth at the closing date plus 50% of any advances to PEI from PEL,
and
(ii) a ratio of current assets to current liabilities of at least one to one.
The terms of the financial covenants governing the credit facility are currently
being met.
See note 13 - Commitments and contingencies.
(b) INTEREST RATE RISK EXPOSURES
At December 31, 2004, the weighted average interest rate for cash deposits was
2.1% per annum (2003: 3.2%). During the year, cash deposits were primarily held
in US dollars.
Other financial assets and liabilities detailed in the financial statements
(receivables excluding cash deposits, payables, short-term financing of
insurance premiums and investments) are all non-interest bearing.
(c) FOREIGN EXCHANGE EXPOSURES
During 2002, 2003 and 2004, operating costs were incurred in both Australian and
US dollars.
Throughout 2002, 2003, and 2004, the Company predominantly held the majority of
its liquid funds in US dollars.
Fluctuations in the Australian dollar/US dollar exchange rate have not had a
material impact on the underlying performance of the Company. The Company's
policy is not to hedge the Australian dollar/US dollar exchange rate risk except
through natural hedging techniques such as maintaining cash balances in US
dollar accounts to support operations conducted in US dollars.
(d) COMMODITY PRICE EXPOSURES AND HEDGES
The income of the Company is affected by changes in natural gas and crude oil
prices, and from time to time, the Company undertakes various operating and
financial transactions (such as forward sales agreements and swap contracts
involving NYMEX commodity prices for natural gas) to reduce its exposure to
these changes. While these hedging arrangements limit the downside risk of
adverse price movements, they may also limit future revenues from favorable
price movements. The Company has proved reserves of these commodities sufficient
to cover all these transactions and it only enters into such transactions to
match a portion of its anticipated physical production and reserves.
At December 31, 2004, the Company had no outstanding forward contract
commitments (2003: 4,000 MMbtu/day of production for the period January 1, 2004
through to February 29, 2004 at a net realised fixed price of $4.87/MMbtu
(million British thermal units). The Company accounts for forward sales
agreements as ordinary sales.
F16
10. FINANCING ARRANGEMENTS, LIQUIDITY, FINANCIAL INSTRUMENTS DISCLOSURES AND
SIGNIFICANT CONCENTRATIONS (CONTINUED)
Swaps and costless collars
In a natural gas swap agreement the Company 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 Company will pay the difference to the
counterparty.
In a natural gas costless collar agreement, a floor price and a ceiling price is
established. The Company receives from the counterparty the difference between
the agreed floor price and the NYMEX penultimate closing price if the latter is
lower than the agreed floor price. If the NYMEX penultimate closing price is
higher than the agreed ceiling price, the Company will pay the difference to the
counterparty.
At December 31, 2004, the Company had the following outstanding natural gas
hedges in place:
WEIGHTED AVERAGE
PRODUCTION PERIOD HEDGE TYPE DAILY VOLUME USD PRICE
- ------------------- --------------- ------------ ----------------
First quarter 2005 Costless collar 4,000 MMBtu $ 6.00/7.08(1)
Swap 6,000 MMBtu 7.89
Second quarter 2005 Swap 4,000 MMBtu 6.61
Third quarter 2005 Swap 4,000 MMBtu 6.59
Fourth quarter 2005 Swap 4,000 MMBtu 6.87
(1) Floor/Ceiling
The Company has determined that its hedge agreements are highly effective and
thus qualify for hedge accounting treatment. Accordingly, gains or losses are
included in oil and natural gas revenues when the hedged production is
delivered.
During 2004, the Company realized hedging losses totaling $1.1 million (2003:
less than $0.1 loss; 2002: nil), which were netted against oil and natural gas
revenues.
The Company estimates that the effect on the group to settle hedge agreements on
December 31, 2004 would have been a pre-tax gain of $1.4 million (2003: Loss of
$0.3 million), representing the fair value of the contracts at that date. The
fair values for swap agreements will vary with movements in market prices until
the contracts mature.
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 risk
on derivative contracts is minimized as counterparties are recognized financial
intermediaries with acceptable credit ratings determined by a recognized ratings
agency. The credit worthiness of counterparties is subject to continuing review
and full performance is anticipated. The Company has limited the term of the
transactions and the percentage of the Company's expected aggregate oil and
natural gas production that may be hedged.
F17
10. FINANCING ARRANGEMENTS, LIQUIDITY, FINANCIAL INSTRUMENTS DISCLOSURES AND
SIGNIFICANT CONCENTRATIONS (CONTINUED)
(f) CONCENTRATIONS AND OTHER CREDIT RISK EXPOSURES
Financial instruments that potentially expose the Company to credit risk consist
primarily of cash and trade accounts receivable. The Company places its cash on
deposit with major financial institutions. The Company does not believe
significant credit risk exists with respect to these cash deposits at December
31, 2004.
All of the Company's revenues are related to the production and sales of oil and
natural gas in the Gulf of Mexico. During 2004, approximately 55% of the
Company's oil and natural gas sales were made to Chevron USA Inc., 22% were made
to Louis Dreyfus Inc., and 20% were made to Reliant Energy Services Inc. The
Company typically sells all of its monthly natural gas production to only one or
two purchasers. At December 31, 2004, 82% of the Company's outstanding accounts
receivable were due from Chevron USA Inc.
During 2003, approximately 67% of the Company's oil and gas sales were made to
Occidental Energy Marketing, Inc. and 32% were made to Reliant Energy Services,
Inc. At December 31, 2003, substantially all of the Company's outstanding
accounts receivable were due from Reliant Energy.
For 2002, the Company only had production from properties in which it had an
overriding royalty interest.
The Company monitors its purchasers for developments that may indicate whether
the purchaser is having financial difficulty. Also, if deemed appropriate, the
Company may require the parent companies of our purchasers to provide a
guarantee that the parent will pay any delinquent obligations of their
subsidiary. If factors indicate that collection of accounts receivable are
doubtful, the Company will record a bad debt provision. However, for the years
presented, the Company has not recorded any bad debt expense.
The Company also obtains insurance and related products to reduce its exposure
to certain operating risks that are inherent to oil and natural gas operations.
The level of insurance coverage obtained is based on the Company's judgment of
what is reasonable and appropriate, industry practice and legal and contractual
requirements. To reduce the risk that an insurer would be unable to pay on
future claims, if any, the Company only obtains its insurance from underwriters
with acceptable credit ratings determined by a recognized ratings agency.
(g) FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
The carrying values of cash and cash equivalents, receivables, accounts payable
and other financial liabilities are estimated to approximate fair values because
of their short maturity.
11. SHARE CAPITAL
December 31 December 31
2003 2004
(US Dollars, in thousands)
--------------------------
Issued capital
Stated value A$0.20 per share (250,000,000 shares)
119,222,841 shares outstanding (2003: 105,736,041 shares)
Ordinary shares fully paid $ 120,791 $ 130,106
----------- -----------
Holders of ordinary shares are entitled to receive dividends as declared from
time to time and are entitled to one vote per share at shareholders' meetings.
In the event of winding up of the Company ordinary shareholders rank after
creditors and are fully entitled to any proceeds of liquidation.
On January 6, 2004 the Company completed a placement of 12,846,800 shares at
A$0.95 per share, raising a total of A$11.6 million or US$8.6 million of which
A$9.8 million or US$7.3 million had been received prior to the end of the 2003
financial year and was recorded as a current liability in share subscriptions
received in advance.
F18
11. SHARE CAPITAL (CONTINUED)
At its general meeting on November 29, 1994, the Company approved the
establishment of an Employee Share Plan and an Employee Option Plan. The plans
are administered by a committee appointed by the Board. The Employee Share Plan
(and associated loan scheme) provides for the issue of ordinary shares in the
Company at the ruling market price to employees and directors of the Company.
The purchases of the shares are financed by interest-free loans from the Company
to the employees and directors. The Employee Share Plan is currently inactive.
The Employee Option Plan provides for the issue of options to buy shares in the
Company to employees and directors of the Company. The exercise prices of the
options are the ruling market prices when the options are issued with a hurdle
price at a higher level. The total shares and options issued to employees over a
five-year period are not to exceed 6,987,567. As of December 31, 2004, the
number of further shares or options which could be issued within the limit was
3,349,567 (2003: 2,909,567).
At December 31, 2004, there were the following unexercised employee options to
purchase the Company's ordinary shares:
Weighted
average
Remaining
Exercise Number contractual life Number
prices outstanding (years) exercisable Expiry dates
- --------------- ----------- ---------------- ----------- -----------------------------
A$0.30 3,020,000 2.4 1,154,000 June 1, 2007
A$0.40 213,000 3.0 100,000 December 1, 2007 - April 1, 2008
A$0.82 175,000 3.0 75,000 December 31, 2007
A$0.83 15,000 3.9 4,000 November 30, 2008
A$1.00 150,000 4.5 - June 30, 2009
A$1.25 65,000 4.4 - March 1, 2009 - July 30, 2009
--------- --- ---------
A$0.30 - A$1.25 3,638,000 2.6 1,333,000
--------- --- ---------
The options become exercisable at various dates and after various share price
hurdles of the Company have been reached. During the year ended December 31,
2004, 230,000 additional options were granted to employees; 640,000 options were
exercised and converted to ordinary shares; 15,000 options were cancelled as a
result of the termination of the services of a number of employees. During 2004,
the Company recorded $83,000 of compensation expense related to the option plan
(2002: $40,000; 2003: $90,000) determined using the Black Scholes option-pricing
model with an expected life of 1.2 years to 4.5 years (weighted average 2.6
years), volatility range of 49.90% - 86.90% and dividend yield and risk-free
interest rate range of 0% and 5.05% - 5.53% per annum, respectively. At December
31, 2004 the balance of unearned stock compensation expense to be recorded in
future periods was $115,000.
OUTSTANDING OPTIONS:
Number of Weighted
outstanding average
options exercise price
----------- --------------
As at December 31, 2001 549,000 A$0.41
Granted 3,545,000 A$0.30
Cancelled (466,000) A$0.41
--------- ------
As at December 31, 2002 3,628,000 A$0.30
Granted 450,000 A$0.58
Cancelled (15,000) A$0.30
--------- ------
As at December 31, 2003 4,063,000 A$0.33
Granted 230,000 A$1.06
Exercised (640,000) A$0.34
Cancelled (15,000) A$0.40
--------- ------
As at December 31, 2004 3,638,000 A$0.38
--------- ------
Exercisable at December 31, 2004 1,333,000 A$0.34
Exercisable at December 31, 2003 829,000 A$0.31
F19
12. SHAREHOLDERS' EQUITY (DEFICIENCY)
Twelve months
ended
December 31 December 31 December 31
(Unless stated otherwise, US dollars, in thousands) 2002 2003 2004
- --------------------------------------------------- -------------- -------------- --------------
Issued capital $ 120,701 $ 120,791 $ 130,106
Accumulated other comprehensive loss (2,376) (2,611) (1,964)
Accumulated deficit (108,077) (94,977) (77,243)
------------- ------------- -------------
Total shareholders' equity $ 10,248 $ 23,203 $ 50,899
------------- ------------- -------------
Movements during the financial period
Issued capital (number of shares)
Balance at the beginning of the financial period 105,736,041 105,736,041 105,736,041
Shares issued for cash pursuant to placement - - 12,846,800
Shares issued from exercise of options under
Employee Option Plan - - 640,000
------------- ------------- -------------
Balance at the end of the financial period 105,736,041 105,736,041 119,222,841
------------- ------------- -------------
Issued capital
Balance at the beginning of the financial period $ 120,661 $ 120,701 $ 120,791
Shares issued for cash pursuant to placement - - 9,064
Shares issued from exercise of options under
Employee Option Plan - - 168
Stock compensation expense 40 90 83
------------- ------------- -------------
Balance at the end of the financial period $ 120,701 $ 120,791 $ 130,106
------------- ------------- -------------
Accumulated deficit
Balance at the beginning of the financial period $ (104,790) $ (108,077) $ (94,977)
Net income (loss) (3,287) 13,100 17,734
------------- ------------- -------------
Balance at the end of the financial period $ (108,077) $ (94,977) $ (77,243)
------------- ------------- -------------
Accumulated other comprehensive loss
Unrealized loss on investment securities
Balance at the beginning of the financial period $ (16) $ (16) $ (16)
------------- ------------- -------------
Balance at the end of the financial period $ (16) $ (16) $ (16)
------------- ------------- -------------
Foreign currency translation adjustment
Balance at the beginning of the financial period $ (2,271) $ (2,360) $ (2,386)
Current period change (89) (26) (413)
------------- ------------- -------------
Balance at the end of the financial period $ (2,360) $ (2,386) $ (2,799)
------------- ------------- -------------
Unrealized gain (loss) on derivative financial
instruments
Balance at the beginning of the financial period $ - - (209)
Net change in fair value of hedges (net of tax) - (209) 1,060
------------- ------------- -------------
Balance at the end of the financial period $ - $ (209) $ 851
------------- ------------- -------------
------------- ------------- -------------
Balance at the end of the financial period $ (2,376) $ (2,611) $ (1,964)
------------- ------------- -------------
F20
13. COMMITMENTS AND CONTINGENT LIABILITIES
(a) Contingent liabilities
As at December 31, 2004, the estimated maximum contingent liability of the Group
in respect of securities issued in compliance with the conditions of various
agreements and permits granted to controlled entities pursuant to governmental
acts and regulations is $105,000 (2003: $100,000).
The Company is a defendant from time to time in legal proceedings. Where
appropriate the Company takes legal advice. The Company does not consider that
the outcome of any current proceedings is likely to have a material effect on
its operations or financial position.
The production, handling, storage, transportation and disposal of oil and
natural gas, by-products thereof and other substances and materials produced or
used in connection with oil and natural gas operations were subject to
regulation under U.S. federal, state and local laws and regulations primarily
relating to protection of human health and environment. To date, expenditure
related to complying with these laws and for remediation of existing
environmental contamination has not been significant in relation to the results
of operations of the Group.
The Company's U.S. subsidiary, Petsec Energy Inc. ("PEI") is required to provide
bonding or security for the benefit of U.S. regulatory authorities in relation
to its obligations to pay lease rentals and royalties, the plugging and
abandonment of oil and natural gas wells, and the removal of related facilities.
As of December 31, 2004 the Company was contingently liable for $3,875,000 of
surety bonds (2003: $2,175,000) issued through a surety company to secure those
obligations to the authorities. $2,625,000 of these bonds (2003: $1,725,000)
were collateralized by letters of credit.
From time to time, PEI must also provide cash collateral to the hedging
instruments counterparty. At December 31, 2004, PEI had no such cash collateral
requirement (2003: $381,000).
(b) Lease commitments
Until it begins exploration or production, the Company pays an annual delay
rental on the Gulf of Mexico properties in which it holds a working interest.
The Company also leases office space and operating equipment under
non-cancelable operating leases expiring from one to two years. Leases generally
provide the Company with a right of renewal at which time all terms are
renegotiated. Lease payments comprise a base amount plus an incremental
contingent rental. Contingent rentals are based on either movements in the
Consumer Price Index or operating criteria.
Rent expense for the years ended December 31, 2002, 2003 and 2004 was $180,000,
$490,000 and $554,000 respectively.
The following table presents the remaining aggregate lease commitments as of
December 31, 2004 under operating leases, including Gulf of Mexico properties,
having initial non-cancellable terms in excess of one year:
December 31
(US dollars, in thousands) 2004
- -------------------------- -----------
2005 $ 306
2006 251
2007 208
2008 98
2009 31
-----
$ 894
-----
(c) Exploration commitments
In addition to the contractual cash obligations listed above, the Company
has committed to expending approximately $7.9 million in total during 2005 for
exploration within the U.S. and China in respect of its joint operating
arrangement commitments.
F21
13. COMMITMENTS AND CONTINGENT LIABILITIES (CONTINUED)
(d) Superannuation commitments, incentive compensation, and directors'
retirement obligation
For its Australian employees, the Company contributes to several defined
contribution employee superannuation plans. Employee contributions are based on
various percentages of their gross salaries.
During the years ended December 31, 2002, 2003 and 2004, superannuation
contributions by the Company were $23,000, $29,000 and $28,000 respectively.
On May 23, 2003 the Company established an incentive compensation plan for its
U.S. based employees. Under the plan, the Company will accrue up to 6 1/2
percent of the annual profit of the U.S. operations (operating profit before
interest, taxes and incentive compensation). The bonus is paid annually in the
first quarter of the year following determination of the annual results. During
2004, the Company recorded $1.0 million of compensation expense (2003: $0.9
million).
The Company provides non-executive directors first appointed before April 1,
2003 with a benefit on retirement equivalent to the total remuneration received
in the three years preceding retirement.
In 2003, the Nomination and Remuneration Committee approved a retirement benefit
for directors appointed after April 1, 2003 which is proportional to the length
of service, with a maximum benefit equivalent to the remuneration received in
the three years preceding retirement.
The Company's liability for directors' retirement benefit is included in other
accrued liabilities under the long-term liabilities classification in the
consolidated balance sheet.
During 2004, the Company recorded no expense for the directors' retirement
benefit (2003: $98,000). The total amount accrued for director retirement is
$220,000.
F22
\
14. SEGMENT REPORTING
The company's operating segments are based on management's approach for making
decisions about allocating resources and assessing performance, which is on a
geographic basis. The key measure of segment result is income before tax.
Segment assets are defined as cash, and proved and unproved oil and gas
properties. The accounting policies used by the operating segments are
consistent with the consolidated financial statements. There are no
inter-segment transactions. Reconciling items relate solely to the Company's
corporate headquarters, which is located in Australia, and is not considered to
be an operating segment under US GAAP.
Other than as set out below, there are no significant tangible assets for the
China and USA segments.
CHINA USA RECONCILING ITEMS
US DOLLARS, THOUSANDS 2002 2003 2004 2002 2003 2004 2002 2003 2004
- ------------------------------------------ ------- ----- ------- ------- ------- ------- ----- ------- -------
Oil & Gas sales (net of royalties) - - - - 23,270 32,575 - - -
Oil & Gas royalties - - - 201 1,949 223 - - -
------ ----- ------ ------ ------ ------ ---- ------ ------
Revenue from customers (1) - - - 201 25,219 32,798 - - -
====== ===== ====== ====== ====== ====== ==== ====== ======
Depreciation, depletion and amortization - - - 16 6,553 12,335 18 21 26
------ ----- ------ ------ ------ ------ ---- ------ ------
Interest income - - - - 43 37 136 99 274
------ ----- ------ ------ ------ ------ ---- ------ ------
Interest expense - - - - (10) (32) - - -
------ ----- ------ ------ ------ ------ ---- ------ ------
Income (loss) before tax (1,041) (302) (1,373) (1,654) 14,001 10,541 (846) (1,091) (1,241)
====== ===== ====== ====== ====== ====== ==== ====== ======
Cash - - - 70 3,983 6,916 526 8,479 2,602
------ ----- ------ ------ ------ ------ ---- ------ ------
Proved and unproved oil and gas properties 125 981 1,370 10,526 18,176 32,172 - - -
------ ----- ------ ------ ------ ------ ---- ------ ------
Expenditure for additions to long lived
assets 1,123 856 1,715 8,653 14,037 30,074 46 1 25
------ ----- ------ ------ ------ ------ ---- ------ ------
CONSOLIDATED
US DOLLARS, THOUSANDS 2002 2003 2004
- ------------------------------------------ ------- ------- -------
Oil & Gas sales (net of royalties) - 23,270 32,575
Oil & Gas royalties 201 1,949 223
------ ------ ------
Revenue from customers (1) 201 25,219 32,798
====== ====== ======
Depreciation, depletion and amortization 34 6,574 12,361
------ ------ ------
Interest income 136 142 311
------ ------ ------
Interest expense - (10) (32)
------ ------ ------
Income (loss) before tax (3,541) 12,608 7,927
====== ====== ======
Cash 596 12,462 9,518
------ ------ ------
Proved and unproved oil and gas properties 10,651 19,157 33,542
------ ------ ------
Expenditure for additions to long lived
Assets 9,822 14,894 31,814
------ ------ ------
F23
15. RELATED PARTY DISCLOSURES
Directors
The names of persons who were directors of the Company during the year ended
December 31, 2004 are Messrs T.N. Fern, D.A. Mortimer and P.E. Power.
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 year and no such loans are outstanding.
A company associated with a director provided management services to the Group
in the ordinary course of business and on normal terms and conditions. The terms
include provision for compensation in the event of termination without due
notice. The cost of the services provided to the Group during the year by this
company was $440,000 (2003: $530,000; 2002: $254,000).
The Company holds unlisted shares in an investment fund of which Mr. Mortimer is
Chairman. At December 2004 the Company had invested $528,000 in the fund and has
a total commitment to the fund of up to $778,000.
16. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Twelve months ended
December 31 December 31 December 31
(US dollars, in thousands) 2002 2003 2004
- ------------------------------------------------ ----------- ----------- ------------
Cash paid during the period for:
Interest $ - $ 10 $ 32
Income taxes paid (refunded) - 250 -
Non-cash items:
Insurance premiums financed with short-term debt $ - $ 730 $ 1,754
17. PRINCIPAL DIFFERENCES BETWEEN AUSGAAP AND US GAAP
The principal differences between AUS GAAP and US GAAP which are material to the
preparation of the consolidated financial statements of the Group are set out
below in this note. See note 1 for a description of US GAAP policies related to
the discussion below.
EXPLORATION AND DEVELOPMENT EXPENDITURE
Under AUS GAAP, all exploration and development expenditure is capitalized to
the extent that it is expected to be recouped through successful exploitation of
an area or sale, or where exploration and evaluation activities have not yet
reached a stage which permits a reasonable assessment of the existence of
economically recoverable reserves, and significant activities are continuing.
The main difference from AUS GAAP is that under US GAAP all general, geological
and geophysical costs are expensed as incurred. Under both US GAAP and AUS GAAP
drilling costs of successful wells are capitalized and drilling costs relating
to unsuccessful exploration wells are written off.
INCOME TAXES
Accounting under AUS GAAP is under the liability method and is equivalent in
most major respects to FASB Statement No. 109, "Accounting for Income Taxes".
However for AUS GAAP, deferred tax assets related to temporary differences are
brought to account only when they are "assured beyond a reasonable doubt" and
net operating losses only when they are considered to be "virtually certain" of
recovery. Under US GAAP temporary differences and net operating losses are
brought to account only when recovery is considered "more likely than not".
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.
F24
17. PRINCIPAL DIFFERENCES BETWEEN AUSGAAP AND US GAAP (CONTINUED)
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.
The Company use the fair value method as prescribed in SFAS No. 123, Accounting
for Stock-Based Compensation. The fair value method results in compensation
expense related to the issuance of employee shares and options or rights being
recorded in the statement of financial performance over the vesting period.
ASSET RETIREMENT OBLIGATIONS
Under AUS GAAP, restoration and reclamation provisions are accrued on a unit of
production basis. 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.
The Company adopted Statement No. 143, "Accounting for Asset Retirement
Obligations" effective January 1, 2003. SFAS No. 143 requires the Company to
record the fair value of its retirement obligations as a liability. The
associated asset retirement costs are also capitalised as part of the carrying
amount of the oil and natural gas properties and amortized on a unit of
production basis. The liability is discounted and accretion expense is
recognised using a credit-adjusted risk-free interest rate in effect when the
liability was initially recognised. Under US GAAP changes in estimated
restoration provisions are accounted for on a prospective basis and affect
future provisions.
18. 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 December 2004 and 2003 were
based on studies performed by Ryder Scott Company L.P.
As at December 31, 2001 the Company had no proved or proved developed reserves.
No major discovery or other favourable or adverse event subsequent to December
31, 2004 is believed to have caused a material change in the estimates of proved
or proved developed reserves as of that date.
F25
18. SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)
ESTIMATED NET QUANTITIES OF OIL AND NATURAL GAS RESERVES
The following table sets forth the Company's net proved reserves, including the
changes therein, and proved developed reserves (all within the United States),
as estimated by Ryder Scott Company L.P.
CRUDE
OIL GAS
(Mbbl) (MMcf)
Proved developed and undeveloped reserves:
December 31, 2001 - -
Extensions, discoveries and other additions 24 7,804
Production (1) (40)
--- ------
December 31, 2002 23 7,764
Revisions of previous estimates 23 (1,305)
Extensions, discoveries and other additions 12 8,681
Production (19) (4,403)
--- ------
December 31, 2003 39 10,737
Revisions of previous estimates 39 5,444
Extensions, discoveries and other additions - 1,683
Production (15) (5,595)
--- ------
December 31, 2004 63 12,269
Proved developed reserves :
December 31, 2002 23 7,764
December 31, 2003 32 3,725
December 31, 2004 63 12,269
CAPITALIZED COSTS OF NATURAL GAS AND OIL PROPERTIES
December 31, December 31, December 31,
2002 2003 2004
------------ ------------ ------------
(US dollars, in thousands)
Capitalised costs for oil and gas producing activities
of the following:
Proved properties $ 7,627 $ 24,036 $ 45,827
Unproved properties 3,024 1,602 6,412
-------- -------- --------
Total capitalised costs 10,651 25,638 52,239
Accumulated depletion, depreciation and
Amortization - (6,481) (18,697)
-------- -------- --------
Net capitalised costs $ 10,651 $ 19,157 $ 33,542
-------- -------- --------
COSTS INCURRED FOR OIL AND NATURAL GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
Twelve months ended
December 31, December 31, December 31,
2002 2003 2004
------------ ------------ ------------
(US dollars, in thousands)
Costs incurred for oil and gas property acquisition,
exploration and development activities were as
follows:
Lease acquisition $ 125 $ 519 $ 3,973
Exploration 2,149 6,586 11,943
Development 7,627 8,987 15,898
------- ------- -------
Total costs incurred $ 9,901 $16,092 $31,814
------- ------- -------
F26
18. SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)
Standardized measure of discounted future net cash flows relating to proved oil
and natural gas reserves
The following information has been developed utilizing procedures prescribed by
Statement of Financial Accounting Standards No. 69 (SFAS No. 69) "Disclosures
about Oil and Gas Producing Activities" and based on natural gas and crude oil
reserve and production volumes estimated by Ryder Scott Company L.P. It may be
useful for certain comparative purposes, but should not be solely relied upon in
evaluating the Group 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 Group.
The Company believes that the following factors should be taken into account in
reviewing the following information: (1) future costs and selling prices will
probably differ from those required to be used in these calculations; (2) due to
future market conditions and governmental regulations, actual rates of
production achieved in future years may vary significantly from the rate of
production assumed in the calculations; (3) selection of a 10% annual discount
rate is arbitrary and may not be reasonable as a measure of the relative risk
inherent in realizing future net oil and natural gas revenues; and (4) future
net revenues may be subject to different rates of income taxation.
Under the standardized measure, future cash inflows were estimated by applying
period end oil and natural gas prices, adjusted for contractual arrangements in
existence at year end if any, to the estimated future production of period end
proved reserves. Future cash inflows were reduced by estimated future
development, abandonment and production costs based on period-end costs in order
to arrive at net cash flow before tax. Future income tax expense has been
computed by applying period-end statutory tax rates to aggregate future pre-tax
net cash flows, reduced by the tax basis of the properties involved and tax
carry forwards. Use of a 10% annual discount rate is required by SFAS No. 69.
Management does not rely solely upon the following information in making
investment and operating decisions.
Such decisions are based upon a wide range of factors, including estimates of
probable as well as proved reserves and varying price and cost assumptions
considered more representative of a range of possible economic conditions that
may be anticipated.
The standardized measure of discounted future net cash flows relating to proved
oil and natural gas reserves was as follows:
Twelve months ended
December 31 December 31 December 31
2002 2003 2004
----------- ----------- -----------
(US Dollars, in thousands)
Future cash inflows $ 36,160 $ 65,612 $ 78,599
Less: Future production and development costs (6,260) (21,085) (14,467)
Future income tax expense - - -
-------- -------- --------
Future net cash flows after income taxes 29,900 44,527 64,132
Less: 10% annual discount for estimated timing of cash flows (3,744) (9,032) (6,240)
-------- -------- --------
Standardized measure of discounted future net cash flows $ 26,156 $ 35,495 $ 57,892
-------- -------- --------
Summary of the changes in standardized measure of discounted
future net cash flows applicable to proved oil and gas reserves
Beginning of the period $ $ 26,156 $ 35,495
Sales and transfers of oil and gas produced, net of production costs (201) (23,662) (32,080)
Changes in prices and production costs - 7,982 1,353
Extensions, discoveries and improved recoveries
net of future productions and development costs 26,357 25,978 19,625
Development costs incurred during the period - 3,293 12,258
Changes in estimated development costs - (1,906) (3,561)
Revisions of previous quantity estimates - (5,207) 14,982
Accretion of discount - 1,780 2,953
Other - 1,081 6,867
-------- -------- --------
Net increase (decrease) - 9,339 22,397
-------- -------- --------
End of the period $ - $ 35,495 $ 57,892
-------- -------- --------
F27
18. SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)
The computation of the standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves at December 31, 2004 was based
on average natural gas prices of approximately $6.18 per Mcf and on average
liquids of approximately $43.13 per barrel, before hedging effects.
19. EVENTS SUBSEQUENT TO BALANCE SHEET DATE
In September 2004, the Company agreed to earn a 25% working interest in the
Price Lake field in Cameron Parish, Louisiana by participating in the drilling
of three wells. The first two wells spudded in September 2004 and December 2004,
respectively, and encountered hydrocarbon-bearing sands during the first quarter
2005. The wells were completed for production, however the reserves discovered
have subsequently proved to be uneconomic and as a result, the wells have been
determined to be dry holes and the total costs incurred and previously
capitalized through December 31, 2004 of $3.2 million have been written-off and
expensed as of December 31, 2004. Drilling of the third well in the Price Lake
field is expected to commence in the second or third quarter of 2005.
F28
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Petsec Energy Ltd and subsidiaries
The Board of Directors and Stockholders of Petsec Energy Ltd
We have audited the accompanying consolidated balance sheets of Petsec Energy
Ltd and subsidiaries as of December 31, 2004 and 2003, and the related
consolidated statements of operations, comprehensive income (loss), and cash
flows for each of the years in the three-year period ended December 31, 2004.
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 the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Petsec Energy Ltd
and subsidiaries as of December 31, 2004 and 2003, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2004, in conformity with U.S. generally accepted accounting
principles.
KPMG
MAY 31, 2005
SYDNEY, AUSTRALIA
F29
EXHIBIT INDEX
1.1 Constitution of the Company.
4.1 Form of employment contract agreement for Australian-based executives.
4.2 Form of employment contract agreement for US-based executives.
8.1 Subsidiaries of the Company
31.1 Certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2 Certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32.1 Certification of CEO pursuant to section 906 of the Sarbanes-Oxley Act of
2002.
32.2 Certification of CFO pursuant to section 906 of the Sarbanes-Oxley Act of
2002.
99.1 Consent of Independent Registered Public Accounting Firm
99.2 Consent of Independent Petroleum Engineers
99.3 Code of Ethics, incorporated herein by reference to Exhibit 99.3 to Form
20-F for the Company for the year ended December 31, 2003.
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