Petsec Energy 20F/A 2005 Annual report (foreign) (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F/A

(Mark One)


o		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period from to


o		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

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 class None		Name of each exchange on which registered 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.
121,389,341 Ordinary Shares

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.

Yes o No þ

If this report is an annual or transition report, indicate by check mark if the registrant is not
required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes o No þ

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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.
See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 o Item 18 þ

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 þ No o

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

EXPLANATION OF AMENDMENT

We are amending our Annual Report on Form 20-F for the fiscal year ended December 31, 2005, which was originally filed on May 22, 2006 (the “Original Report”) in response to comments received from the Securities and Exchange Commission (the “Commission”) in their letters dated September 14, 2006 and November 8, 2006.

As a result of the Commission’s comments, we have revised the following disclosures:

Part I—Item 3—Key Information, D. Risk Factors, pages 8, 10, and 11;
Part I—Item 4—Information on the Company, A. History and development of the Company, page 15;
Part I—Item 4—Information on the Company, B. Business overview, page 16;
Part I—Item 5—Operating and Financial Review and Prospects, A. Operating results, page 26;
Part III—Item 15—Financial Statements, pages F26 and F28.

This Amendment should be read in conjunction with any reports filed on Form 6-K subsequent to the date of the Original Report. In addition, in accordance with applicable SEC rules, this Amendment includes updated certifications from our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) as Exhibits 12.1, 12.2, 13.1, and 13.2.

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 — 12
Item 4.	Information on the Company		13 — 21
Item 4A.	Unresolved Staff Comments		21
Item 5.	Operating and Financial Review and Prospects		22 — 32
Item 6.	Directors, Senior Management and Employees		33 — 37
Item 7.	Major Shareholders and Related Party Transactions		38 — 39
Item 8.	Financial Information		39
Item 9.	The Offer and Listing		40 — 41
Item 10.	Additional Information		42 — 50
Item 11.	Quantitative and Qualitative Disclosure about Market Risk		51
Item 12.	Description of Securities Other Than Equity Securities		51

PART II

Item 13.	Defaults, Dividend Arrearages and Delinquencies		51
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds		51
Item 15.	Controls and Procedures		52
Item 16A.	Audit Committee Financial Expert		52
Item 16B.	Code of Ethics		52
Item 16C.	Principal Accountant Fees and Services		52
Item 16D.	Exemptions from the Listing Standards For Audit Committee		52
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		52


		Page

PART III

Item 17.	Financial Statements		52
Item 18.	Financial Statements		52
Item 19.	Exhibits		53

Signatures			54
Exhibit Index			84
Subsidiaries of the Company
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Consent of Independent Registered Public Accounting Firm
Consent of Independent Petroleum Engineers

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 in accordance with Australian Accounting Standards. The Company also publishes consolidated financial statements in U.S. dollars and under U.S. generally accepted accounting principles (“U.S. GAAP”) as set out under Item 18 in this Form 20-F. All financial information in this Form 20-F is based on U.S. GAAP.

This report covers the years ended December 31, 2003, 2004 and 2005.

References to “U.S.”, “USA” and “U.S.A.” are to the United States of America. References to “U.S. dollars” or “US$” or “$” are to United States dollars and references to “A$” are to Australian dollars.

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.

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

ITEM 3 — KEY INFORMATION

A. Selected Financial Data

The following table sets forth in U.S. dollars and under U.S. 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, 2001, 2002, 2003, 2004 and 2005 is derived from the Company’s U.S. Dollar Financial Statements, which were prepared under U.S. 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
	2001⁽¹⁾			2002			2003			2004			2005
	(In thousands, except per share and per ADR data)

INCOME STATEMENT DATA
Oil and gas sales (net of royalties incurred)	$	—		$	—		$	23,270		$	32,575		$	45,130
Oil and gas royalties earned		—			201			1,949			223			332

Total revenues	$	—		$	201		$	25,219		$	32,798		$	45,462


Lease operating expenses		—			—			1,557			1,776			2,465
Depletion, depreciation, amortization and rehabilitation		28			34			6,574			12,361			15,597
Exploration expenditure		422			1,176			1,329			1,452			5,844
Dry hole and abandonment costs		877			1,066			—			4,119			5,290
Major maintenance expense		—			—			—			592			—
Impairment expense		—			—			38			201			—
General, administrative and other expenses		1,264			1,691			3,519			4,657			5,814
Hurricane-related business interruption insurance proceeds		—			—			—			—			(867	)
Stock compensation expense		11			40			90			83			88

Total operating expenses		2,602			4,007			13,107			25,241			34,231


Income (loss) from operations		(2,602	)		(3,806	)		12,112			7,557			11,231

Other income and expense
Interest expense		—			—			(10	)		(32	)		(23	)
Interest income		447			136			142			311			393
Other income, net		209			129			364			91			403
Derivative losses from discontinued hedges		—			—			—			—			(4,615	)

Total other income (expense)		656			265			496			370			(3,842	)



Income (loss) before income tax and extraordinary items		(1,946	)		(3,541	)		12,608			7,927			7,389
Income tax benefit		8			254			492			9,807			598


Net income (loss) before extraordinary items	$	(1,938	)	$	(3,287	)	$	13,100		$	17,734		$	7,987
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)	$	36,312		$	(3,287	)	$	13,100		$	17,734		$	7,987


BASIC AND DILUTED EARNINGS PER SHARE
Earnings (loss) before extraordinary items per share	$	(0.02	)	$	(0.03	)	$	0.12		$	0.15		$	0.07
Extraordinary items per share		0.36			—			—			—			—

Earnings (loss) per share	$	0.34		$	(0.03	)	$	0.12		$	0.15		$	0.07


Earnings (loss) before extraordinary items per ADR⁽²⁾	$	(0.10	)	$	(0.17	)	$	0.62		$	0.74		$	0.33
Extraordinary items per ADR		1.82			—			—			—			—

Earnings (loss) per ADR	$	1.72		$	(0.17	)	$	0.62		$	0.74		$	0.33


Weighted average number of ordinary shares outstanding		105,752			105,736			105,736			118,830			120,112

CASH FLOW DATA
Net cash from operating activities	$	(1,166	)	$	(2,728	)	$	18,589		$	22,032		$	34,915
Net cash from investing activities		104			(8,170	)		(13,574	)		(26,046	)		(33,651	)
Net cash from financing activities		—			—			6,851			1,070			(644	)


	Year ended December 31
	2001⁽¹⁾		2002		2003		2004		2005
	(In thousands, except per share and per ADR data)
BALANCE SHEET DATA (at period-end)
Total assets	$	15,096	$	14,206	$	38,444	$	63,527	$	87,294
Total current assets		12,006		3,100		16,977		27,909		35,184
Total current liabilities		390		2,989		14,674		11,512		31,465
Total shareholders equity		13,584		10,248		23,203		50,899		54,263
Share capital		120,661		120,701		120,791		130,106		130,725

Number of ordinary shares outstanding		105,736		105,736		105,736		119,223		121,389


⁽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 U.S. 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 U.S. dollars (unless otherwise indicated) have been made at the appropriate Noon Buying Rate as specified. The Noon Buying Rate at May 1, 2006 was 0.7525.

The following table sets forth certain information with respect to historical exchange rates, using the Noon Buying Rates for Australian dollars expressed in U.S. dollars per Australian dollar:


	U.S. Dollar per Australian Dollar
Period	Average *		High		Low		End of Period


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
Year ended December 31, 2005		0.7614		0.7985		0.7308		0.7336
November 2005		0.7352		0.7473		0.7312		0.7378
December 2005		0.7418		0.7564		0.7308		0.7336
January 2006		0.7494		0.7587		0.7325		0.7587
February 2006		0.7414		0.7537		0.7356		0.7380
March 2006		0.7264		0.7454		0.7049		0.7155
April 2006		0.7351		0.7558		0.7139		0.7558


*		Average of Noon Buying Rates for the period based on month end rates

Fluctuations in the Australian dollar/U.S. dollar exchange rate will affect the U.S. 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 U.S. 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 U.S. 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 U.S. dollars. For the foreseeable future, therefore, fluctuations in the Australian dollar/U.S. dollar exchange rate are expected to have only a small effect on the Company’s underlying performance, as measured in U.S. dollars, and on the Company’s financial statements prepared in U.S. 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, 2001, 2002, 2003, 2004 and 2005.

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, 2005, 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 two were producing at December 31, 2005. 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 and additional equity offerings.

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 $31.7 million during 2005. We expect our total capital expenditures in 2006 to be $50.0 million or more, including $2.3 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 that 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 $10 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 1, 2006, the Company’s primary operating subsidiary, PEI, had 15 employees. 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.

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 — B. Business Overview - - Competition.”

Substantially all of our outstanding accounts receivable may be from a small number of purchasers and third-party participants in our joint operating arrangements.

We sell all of our monthly oil and natural gas production to a small number of purchasers. 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.

We also incur significant expenditures under our joint operating arrangements that are reimbursable to us by the joint operating arrangement participants.

If any of our purchasers or joint operating arrangement participants are unable to pay for amounts receivable by us, we could incur a significant amount of bad debt expense.

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;

	•		technological advances affecting oil and gas consumption;

	•		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.

Our hedging activities may limit our potential income and liquidity.

Our hedging activity is intended to reduce the risk of downward price fluctuations on a portion of our future production. However, such hedging activity may limit our potential income when oil and gas prices rise above a level established by our hedges. For example, in 2005, our hedges reduced the benefits we received from increased natural gas prices by approximately $1.6 million. In addition, our hedging transactions expose us to the risk of financial loss if our production is less than the quantity hedged. For example, because of widespread damage to third-party facilities that Hurricane Rita caused, a substantial amount of our production was shut in during the fourth quarter of 2005. Consequently, we had to settle expiring hedge agreements without the benefit of incoming cash flow from the underlying physical production, which resulted in derivative losses from discontinued hedges of approximately $4.6 million. Our hedges also expose us to basis risk. A widening of the difference between NYMEX Henry Hub natural gas futures settlement and the prices at which we sell our gas will reduce the effectiveness of our hedges. Finally, we could incur substantial losses if our counterparty to the hedges fails to perform its obligations under the hedge agreements.

Our counterparties require collateral when the mark-to-market value of our hedge instruments is in the counterparties favor and exceeds our credit limits with such counterparties. As a result, we may have to provide

substantial security to the counterparties when commodity prices change significantly. The security we provide may be in the form of cash or letters of credit, and thus, could have a significant impact on our liquidity.

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, delays in the delivery, or high cost 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.

We participate in certain of our leases with third-party participants under joint operating arrangements. Adverse changes in the financial and operational condition of a third party could restrict their ability to participate in or fund their share of drilling and production activities, which could cause us to shorten, delay, or cancel such activities.

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, blowouts and surface cratering, lost or damaged oilfield drilling and service tools, pipe or cement failures, 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.

We are dependent on facilities that are owned or operated by others.

Third parties own or operate the transportation (pipelines) and processing facilities that we rely on for the marketing and selling of our production. If any of these facilities are shut down due to fire, explosion, equipment failure, leaks, repairs, weather conditions, weather related damage, and environmental hazards, then we may not be able to sell our production until the facilities are repaired or otherwise brought back on line or until we make significant capital expenditures so that we can deliver our production to other facilities.

For example, in September 2005, Hurricane Rita caused major damage to an onshore separation facility that our Vermilion 258 production must pass through. The repair of that facility lasted for over two months, and we were unable to produce from our Vermilion 258 lease during that time.

Our insurance may not protect us against our operating and business risks.

In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating and business risks. We cannot assure you that our insurance will be adequate to cover all of our losses or liabilities. In addition, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The impact of Hurricanes Katrina and Rita have resulted in escalating insurance costs and less favorable coverage terms.

Our operations are exposed to the additional risk of hurricanes and other tropical weather disturbances.

Most of our oil and gas operations are located in the Gulf of Mexico and in Louisiana and are exposed to the risk of tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to our facilities and to third-party facilities that we rely on for transporting, handling, and processing our oil and gas production. As a result, we may experience significant delays and loss of income due to our inability to produce oil and gas due to such damage.

For example, in August and September 2005, Hurricanes Katrina and Rita caused widespread damage to third-party facilities. We estimate that in 2005, we experienced an approximate 1.4 Bcf deferral of our natural gas production due to the damages and delays caused by hurricanes. During the periods of shut in production, gas prices averaged approximately $11.00 per Mcf. Additionally, we recorded derivative losses of approximately $4.6 million because the hurricanes caused our production to be less than the quantity hedged.

Widespread disruptions may also create increased volatility of oil and gas prices, create higher demand for oil and gas service equipment and personnel, and create shortages of such equipment and personnel.

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 11^th attacks”). Since the September 11^th 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 is derived from assets that are concentrated in a geographic area.

As of January 1, 2006, nearly all of our production and revenues are derived from wells located on two platforms in the Gulf of Mexico. One platform, with one producing well, is located at West Cameron 352 and the other platform, with four producing wells, is located at Vermilion 258. In 2006, we will also have production and revenue derived from wells at our Main Pass 19 platform. Future wells are also planned for the Gulf of Mexico. Accordingly, if the level of production from one or more of these platforms substantially declines because 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.

Our cash balances held in Australian dollars are exposed to currency exchange rate fluctuations between the U.S. dollar and the Australian dollar.

Since most of our operations are conducted in U.S. dollars, we generally maintain a substantial portion of our cash balances in U.S. dollar accounts. Occasionally, however, we may have substantial cash deposits in Australian dollar accounts. Until these funds are converted to U.S. dollars, the U.S. 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 permitting and other approvals 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; requirements for reports to federal and state agencies concerning our 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 in the past 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 — B. Business Overview.”

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/U.S. 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.

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. The Company is a public company registered under the Corporations Act 2001 of the Commonwealth of Australia (Corporations Act). It is an Australian public company incorporated on December 7, 1967 in New South Wales, Australia 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. The Vermilion 244 and 259 leases intersect certain discoveries in the Company’s Vermilion 258 lease. The Company acquired the two leases to protect its interests in those discoveries.

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 and $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 subsequently proved to be uneconomic. Consequently, in accordance with U.S. GAAP, the Company recorded to expense $4.1 million in the period ended December 31, 2004. Additionally, capital expenditure incurred subsequent to December 31, 2004 totalling $5.3 million was expensed by the Company in respect of this joint operating arrangement in 2005 and the Company subsequently relinquished its entire 25% working interest.

In December 2004, the Company purchased the right to participate in a 3-D seismic survey over 94 square miles (240 square kilometres) in St. James Parish, on shore Louisiana, which is approximately 50 miles west of New Orleans, Louisiana (the “Moonshine Project”). The Company holds a 50% working interest in the Moonshine Project and acts as operator. In 2004, the Company expended $2.4 million on the Moonshine Project.

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 now holds a 100% working interest.

During the second quarter of 2005, the Company drilled three successful wells on the Main Pass 19 lease in the Gulf of Mexico, USA. The Company subsequently completed the refurbishment, construction and installation of a platform, pipeline and production facilities. Following the installation, the Company completed the three wells and started production in January 2006. The total amount expended in 2005 to case, suspend, and complete the three wells, and to construct and install the facilities was $14.8 million. The Company expects to expend approximately $1.0 million on the project in 2006.

During the third quarter 2005, the Company completed the 3D seismic survey on the Moonshine Project. The processed data, the quality of which was good, was delivered in the fourth quarter of 2005. Drilling of prospects generated from interpretation of the 3D seismic data is expected to commence in the second half of 2006. Total cost expended in 2005 on the project was $5.1 million. The cost of the seismic survey was expensed as an exploration expense.

In December 2005, the Company commenced a new four-well drilling programme at Main Pass 19/18 from the Main Pass 19 platform. All four wells were successful and have met pre-drill expectations. Three of the four wells have been completed and brought into production. Completion of the Main Pass 18 G-6 well has been halted subject to the resolution of a dispute with a joint operating arrangement participant over the use of Main Pass 19 facilities. Legal action has been initiated against the Company which has resulted in the granting of a preliminary injunction to prevent production of the G-6 well from the Main Pass 19 platform. The Company believes that the ultimate outcome of this matter may increase the cost of the programme but will not have a material adverse effect on our future results of operations or business. The Company expects to expend $19.3 million in 2006 on the project excluding possible additional cost incurred to resolve the dispute surrounding the G-6 well.

At the March 2006 lease sale held in New Orleans, Louisiana by the MMS, the Company was high bidder for four additional exploration leases in the Gulf of Mexico. Total bids on the leases at Main Pass 7, Main Pass 91, Vermilion 41 and Vermilion 148 were $2.3 million. The Company will have a 100% working interest in these new leases, if they are awarded by the MMS.

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 of the development economics. 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 well 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, was 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.

Pre-feasibility studies, conducted jointly by China National Offshore Oil Corp. (“CNOOC”) and the joint operating arrangement, were completed in January 2005. Consequently, the joint venture agreed to undertake a feasibility study, again jointly with CNOOC. If successful, this will lead to the lodging of an Overall Development Programme (ODP) which contemplates the development of the 12.8 West field in 2006 with anticipated start of production in 2007. This may be followed by the development of the East field possibly in 2007.

The feasibility study addressed the use of a lightweight platform at 12-8 West, piping liquids to the 12-1-1 platform for processing and piping the oil through CNOOC’s existing pipeline to Weizhou Island for sale.

The feasibility study was completed in the fourth quarter of 2005 and commercial discussions for economic access to CNOOC’s production and sales facilities continue.

The joint operating arrangement commenced drilling the 6.12 South prospect on April 25, 2006. The prospect is located immediately south of the 6.12.1 oil discovery made by the joint operating arrangement in 2002. The well reached total depth of 8,365 feet on May 8, 2006. On May 10, 2006, the operator advised that preliminary analysis of the initial log data indicated that there exists a number of oil-bearing sands each up to a net 25 meters in thickness amounting to approximately 100 meters of net oil pay within a gross reservoir interval in excess of 500 meters. The operator also stated that it would take a number of weeks for collection and analysis of all the data before the commercial significance of the discovery can be ascertained.

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 2005 were $45.4 million, comprising $45.1 million of oil and natural gas sales, net of royalties incurred, and $0.3 million from overriding royalty interests. For 2004, the Company recorded revenues of $32.8 million, comprising $32.6 million of oil and natural gas sales, net of royalties incurred, and $0.2 million from overriding royalty interests. In 2003, the Company recorded revenues of $25.2 million, comprising $23.3 million of oil and natural gas sales, net of royalties incurred, and $1.9 million from overriding royalty interests.

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

In the Gulf of Mexico, U.S.A. the Company is currently planning to drill:

	•		2-3 wells at Vermilion 257//258 (expected to commence in June 2006);

	•		1-3 wells at Main Pass 18/103 (expected to be drilled during the third quarter of 2006);

	•		2-3 wells at Moonshine (expected to be drilled late 2006).

In China, commercial discussions for economic access to CNOOC’s production and sales facilities are ongoing and drilling of an exploration well at the 6.12 South prospect commenced on April 25, 2006. On May 10, 2006, the operator advised that the well intersected numerous oil-bearing sands and that further analysis would be required to determine the commercial significance of the discovery.

Any other exploration and development undertaken in 2006 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.”

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, 2003, 2004 and 2005. 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. Proved oil and gas reserves are 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,i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The present value of estimated future net revenues has been calculated using a discount factor of 10% per annum.


	As of December 31,
	2003		2004		2005
TOTAL NET PROVED:
Oil (Mbbls)		39		63		148
Gas (MMcf)		10,737		12,269		17,919

Total (MMcfe)		10,971		12,647		18,807


NET PROVED DEVELOPED:
Oil (Mbbls)		32		63		108
Gas (MMcf)		3,725		12,269		15,901

Total (MMcfe)		3,916		12,647		16,549


Estimated future net revenues before income taxes (in thousands)	$	44,527	$	64,132	$	145,645
Present value of estimated future net revenues before income taxes (in thousands) (1)	$	35,495	$	57,892	$	122,100
Standardized measure of discounted future net cash flows (in thousands) (2)	$	35,495	$	57,892	$	99,477

Average prices used in calculating the net present values:
Oil ($ per Bbl)	$	32.41	$	43.13	$	61.47
Gas ($ per Mcf)	$	5.99	$	6.18	$	9.72


(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. The available use of net operating loss carryforwards is considered in the discounted future net cash flows.

See “Supplementary oil and gas disclosures — unaudited, Estimated net quantities of oil and natural gas reserves” in Note 18 of the Notes to Consolidated Financial Statements included elsewhere in this annual report.

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.

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,
	2003		2004		2005
	(In Thousands)

Acquisition costs	$	519	$	3,973	$	2,191
Exploration costs		6,586		11,943		19,710
Development costs		8,987		15,898		20,117

Total costs incurred	$	16,092	$	31,814	$	42,018

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, 2005:


	Gross		Net
Productive wells (1):
Oil		—		—
Gas		9		7.2

Total		9		7.2


Developed Acreage (1)		25,151		21,164
Undeveloped Acreage (1) (2)		134,488		47,191

Total		159,639		68,355


(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. Eight (6.2 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 4% of the Company’s undeveloped acreage will expire in 2006, 21% will expire in 2008, 16% will expire in 2009, and 59% 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,
	2003				2004				2005
	Gross		Net		Gross		Net		Gross		Net

Gulf of Mexico
Exploratory wells		—		—		2		2		3		1.65
Development wells		2		1.75		1		1		1		1
Dry holes		—		—		—		—		2		0.50

Beibu Gulf, China
Exploratory wells		—		—		1		0.25		—		—
Dry holes		—		—		2		0.50		—		—

Total		2		1.75		6		3.75		6		3.15

Present activity. At December 31, 2005, the Company had one development well at Main Pass 19 in the process of being completed. The Company holds a 55% working interest in the well.

In China, a feasibility study addressing the use of a lightweight platform at 12.8 West, piping liquids to the 12.1.1 platform for processing and piping the oil through CNOOC’s existing pipeline to Weizhou Island for sale, was completed and commercial discussions for economic access to CNOOC’s production and sales facilities continue.

Production. See “Overview” in “Item 5 — Operating and Financial Review and Prospects A. Operating results” for oil and natural gas production information of the Company.

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 2005, approximately 59% of the Company’s oil and natural gas sales were made to Bridgeline Gas Marketing, approximately 17% were made to Chevron USA Inc., and 13% were made to Louis Dreyfus 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, 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.

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. In addition, 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. In August, 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as the Company, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas. The implementation of these orders has not had a material adverse effect on our results of operations.

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 persons allegedly 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 cleanup costs and a variety of public and private damages. While OPA establishes liability limits for offshore facilities at 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, or 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.

To cover at least some costs in a potential spill, 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). Higher amounts of financial responsibility of up to $150 million may 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 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. It is also 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 coordinator 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 cooperation 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.

On March 26, 2006, China’s National Development and Reform Commission (the “NDRC”) issued the Circular on Adjustment of Oil Products Prices indicating that the PRC has decided to levy a windfall tax upon oil producers selling crude oil produced in China.

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.

D. Property, plant and equipment

At December 31, 2005, the Company had working interests in 11 oil and natural gas leases located in the shallow waters of the Gulf of Mexico offshore Louisiana. The interests in nine of the Company’s offshore leases collateralize a significant portion of PEI’s $10.0 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.

ITEM 4A. UNRESOLVED STAFF COMMENTS

Not applicable.

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, 2003, 2004 and 2005, and its financial position at December 31, 2005. 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.

In the first quarter of 2005, the first two wells of the three-well programme at the Price Lake field, onshore Louisiana, which commenced drilling in September 2004 and December 2004, were completed for production. The reserves discovered were subsequently determined to be uneconomic, and as a result, the wells were determined to be dry holes. All related costs incurred in 2005 were expensed. The Company was released from its commitment to drill the third well in exchange for its working interest in the programme.

In December 2004, the Company purchased the right to participate in the Moonshine Project, which included a 3-D seismic survey over a 94 square mile area approximately 50 miles west of New Orleans, Louisiana. During 2005, the Company commenced and completed the 3-D seismic survey and data processing phase of the Moonshine Project. The data acquired in the survey is currently being evaluated. The Company owns a 50% working interest in the project and is the operator.

Following its completion in the second quarter of 2005, the Company commenced production from the Vermilion 244 G-3 well. Also during the second quarter of 2005, the Company commenced drilling of three wells at Main Pass 19. All three wells made commercial discoveries and were completed for production awaiting the installation of production facilities and a gas pipeline. The Company owns a 55% working interest in the three wells and is the operator.

In the third quarter of 2005, two major hurricanes, Katrina and Rita, entered the Gulf of Mexico and caused significant disruptions to the Company’s production operations and development activities. Both Katrina and Rita contributed to delays in installing production facilities at Main Pass 19. Rita caused significant damage to third party onshore facilities. As a result, a substantial amount of Petsec’s production was shut in during the fourth quarter of 2005 while the third party facilities were being repaired. Petsec estimates that approximately 1.0 to 1.5 Bcfe of its production was deferred due to the shut-ins.

Because of the widespread production and transportation disruptions that Hurricanes Katrina and Rita caused in the Gulf Coast region, natural gas prices rose to historic levels. Moreover, as a result of Petsec’s production shut-ins caused by Hurricane Rita, the Company did not have production underlying approximately 0.8 Bcf of natural gas swaps. As a result high natural gas prices and Petsec’s production shut-ins, the Company recorded approximately $4.6 million in derivative losses in 2005.

Hurricanes Katrina and Rita also directly and indirectly led to increased demand for drilling rigs and other oil and gas equipment and services. As a result of the increased demand, the costs to explore, develop, and operate have risen significantly.

Following the November 2005 installation of the platform at Main Pass 19, the Company commenced a four-well development drilling program from the platform. The G—4, G—5, and G—7 wells target reserves in Main Pass 19 (55% Petsec working interest), and the G—6 well targets reserves in Main Pass 18 (100% Petsec working interest). The G—7 well, was drilled to its target depth in December 2005 and was suspended for completion. The G—4 well commenced drilling in late December 2005. The remaining two wells were drilled in the first quarter of 2006. All four wells made commercial discoveries of hydrocarbons. The three Main Pass 19 wells have been completed and were brought into initial production from April 23, 2006. Completion of the Main Pass 18 G—6 well has been halted subject to the resolution of a dispute with a joint operating arrangement participant over the use of the Main Pass 19 facilities. Legal action has been initiated against the Company which has resulted in the granting of a preliminary injunction to prevent production from the G—6 well from the Main Pass 19 platform. The Company believes that the ultimate outcome of this matter may increase the cost of the programme but will not have a material adverse effect on our future results of operations or business.

In the Beibu Gulf 22/12 contract area, China, pre-feasibility studies, conducted jointly by CNOOC and the joint operating arrangement, were completed in January 2005. Consequently the joint venture agreed to undertake a feasibility study, again jointly with CNOOC. If the study determines the project is economical, this will lead to the lodging of an Overall Development Programme (ODP) which contemplates the development of the 12.8 West field (approximately 10 million barrels of recoverable oil, 1.25 million barrels net to Petsec) in 2006 with anticipated start of production in 2007. This may be followed by the development of the East field (approximately 10 to 15 million barrels of recoverable oil) possibly in 2007.

The feasibility study addresses the use of a lightweight platform at 12.8 West, piping liquids to the 12.1.1 platform for processing and piping the oil through CNOOC’s existing pipeline to Weizhou Island for sale. The feasibility study was completed in the fourth quarter of 2005 and commercial discussions for economic access to CNOOC’s production and sales facilities continue.

The joint operating arrangement commenced drilling the 6.12 South prospect on April 25, 2006. The prospect has 3D seismic mapped potential of 10 to 20 million barrels of oil recoverable (1.25 to 2.5 million bbls net to Petsec Energy) and is located immediately south of the 6.12.1 oil discovery made by the joint operating arrangement in 2002. The well reached total depth of 8,365 feet on May 8, 2006. On May 10, 2006, the operator advised that preliminary analysis of the initial log data indicated that there exists, a number of oil-bearing sands each up to a net 25 meters in thickness amounting to approximately 100 meters of net oil pay within a gross reservoir interval in access of 500 meters. The operator also stated that it would take a number of weeks for collection and analysis of all the data before the commercial significance of the discovery can be ascertained.

At December 31, 2005, the Company held working interests and/or overriding royalty interests in 15 leases in the U.S.A. and one in China. In the U.S.A., five of the leases are currently held by production, exploration, or development activities.

At the March 2006 lease sale held in New Orleans, Louisiana by the MMS, the Company was the high bidder for four additional exploration leases in the Gulf of Mexico. Total bids on the leases were $2.3 million. Final award of the leases is pending the MMS’ approval. If awarded, the Company will hold a 100% working interest in each of the leases.

Under U.S. 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
	2003(1)		2004(2)		2005(3)

Net production
Oil (Mbbls)		19		15		20
Gas (MMcf)		4,403		5,595		6,335

Total (MMcfe)		4,517		5,685		6,454

Net sales data (in thousands)⁽⁴⁾:
Oil	$	582	$	669	$	1,050
Gas		24,637		32,129		44,412

Total	$	25,219	$	32,798	$	45,462

Average sales price⁽⁴⁾:
Oil (per Bbl)	$	30.84	$	44.79	$	53.11
Gas (per Mcf)		5.60		5.74		7.01

Total (per Mcfe)	$	5.58	$	5.77	$	7.04

Average costs (per Mcfe):
Lease operating expenses⁽⁵⁾	$	0.34	$	0.31	$	0.38
Depletion, depreciation, amortisation and rehabilitation		1.46		2.17		2.42
General, administrative and other expenses		0.81		0.82		0.91


⁽¹⁾		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.

⁽²⁾		Production commenced at Vermilion 258 from two wells in July 2004 and one well in November 2004.

⁽³⁾		Production commenced from a fourth well at Vermilion 258 in May 2005.

⁽⁴⁾		Includes derivative gains/losses on effective hedges.

⁽⁵⁾		Excludes major maintenance expense.

Results of Operations

The following table sets forth in U.S. dollars and under U.S. GAAP, selected consolidated financial data for the Company for the periods indicated.


	Year ended December 31
	2003			2004			2005
	(In thousands)
INCOME STATEMENT DATA
Oil and gas sales (net of royalties incurred)	$	23,270		$	32,575		$	45,130
Oil and gas royalties earned		1,949			223			332

Total revenues	$	25,219		$	32,798		$	45,462


Lease operating expenses		1,557			1,776			2,465
Depletion, depreciation, amortization and rehabilitation		6,574			12,361			15,597
Exploration expenditure		1,329			1,452			5,844
Dry hole and abandonment costs		—			4,119			5,290
Major maintenance expense		—			592			—
Impairment expense		38			201			—
General, administrative and other expenses		3,519			4,657			5,814
Hurricane-related business interruption insurance proceeds		—			—			(867	)
Stock compensation expense		90			83			88

Total operating expenses		13,107			25,241			34,231


Income from operations		12,112			7,557			11,231

Interest expense		(10	)		(32	)		(23	)
Interest income		142			311			393
Other income, net		364			91			403
Derivative losses from discontinued hedges		—			—			(4,615	)

Total other income (expense)		496			370			(3,842	)



Income before income tax		12,608			7,927			7,389

Income tax benefit		492			9,807			598

Net income	$	13,100		$	17,734		$	7,987

The following discussion relates to the operating information and financial data tabled above and on the previous page:

Year Ended December 31, 2005 compared to Year Ended December 31, 2004

General.Production and revenues in 2005 were higher than in 2004 as the Company benefited from increased production from the Vermilion 258 gas field. The increase in production was achieved despite the impact of Hurricanes Katrina and Rita which effectively shut-in production for much of the fourth quarter of 2005. The Company recorded total revenues for the year of $45.4 million from net production of 6.5 Bcfe (5.7 Bcfe in 2004) at an average price received of $7.04/Mcfe ($5.77/Mcfe in 2004). This represents an increase of $12.6 million, or 38.4%, on 2004 revenues.

Lease operating expenses were $2.5 million in 2005. This compares to $1.8 million in 2004. The increase primarily relates to the increased production and hurricane-related repair costs at West Cameron and Vermilion.

Exploration Expenditures, Dry Hole and Abandonment Cost, Impairment Expense and Major Maintenance Expense.In 2005, $5.8 million was expensed for exploration expenditures and $5.3 million was expensed as incurred for dry hole costs and abandonments. A substantial portion of the exploration expenditure ($5.1million) was for the Company’s Moonshine seismic shoot in St. James Parish, Louisiana. The dry hole costs and abandonments relate to 2005 expenditures incurred in respect of the two previously reported dry holes drilled in the Price Lake field in late 2004. In 2004, $1.5 million in relation to exploration 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.

General and Administrative Expense.General and administrative expense in 2005 of $5.8 million increased $1.1 million or 34% from $4.7 million in 2004 primarily due to the Company’s continued expansion of exploration, operational, and production activities in the Gulf of Mexico.

Depreciation, Depletion, Amortization and Rehabilitation.Depreciation, depletion, amortization and rehabilitation expense (“DD&A”) increased $3.2 million, or 26%, to $15.6 million in 2005 from $12.4 million in 2004. Higher DD&A in 2005 closely reflects the increase in production and related capital expenditure for the year. DD&A in 2005 per Mcfe was $2.42 compared to $2.17 in 2004.

Income Tax Benefit.The Company recognized an income tax benefit of $0.6 million in 2005 compared to an income tax benefit of $9.8 million in 2004. The 2005 income tax benefit includes a further reduction of the deferred tax asset valuation allowance by $3.2 million based on management’s current assessment of realizing the benefit of certain deferred tax assets in the future in the U.S. The 2004 income tax benefit included a $9.8 million reduction of the deferred tax asset valuation allowance. The valuation allowance in relation to the U.S. deferred tax assets at December 31, 2005 is nil.

Net Income.Net income in 2005 of $8.0 million is $10.2 million, or 58% lower than net income in 2004 of $17.7 million. The decrease is largely attributable to the recognition of hedging and derivative losses of $6.2 million ($1.6 million from effective hedges, netted against oil and gas sales and $4.6 million from ineffective hedges, which is reflected in other income and expense), additional dry hole costs related to Price Lake exploration ($5.3 million in 2005 compared to $4.1 million in 2004), increased exploration expenditures due to the Moonshine seismic shoot, and a lower income tax benefit in 2005 compared to 2004. This was partially offset by increases in revenues of $12.6 million, due to higher production and realized gas prices for the year, and other income of $1.2 million, which includes $0.9 million in hurricane-related business interruption insurance proceeds.

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 in relation to exploration was expensed for seismic, geological and geophysical expenditures. Dry hole and abandonment costs and major maintenance expense were nil in 2003.

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, Amortization and Rehabilitation.Depreciation, depletion, amortization and rehabilitation 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 management’s assessment of the likelihood 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.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.

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. During 2005, the Company hedged approximately 42% of its natural gas sales. 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 creditworthiness of counterparties is subject to continuing review and full performance is anticipated. In addition, the use of hedging transactions involves the risk that unexpected disruptions in the production of oil and natural gas may result in sales volumes that are lower than hedged volumes for a given period, which could result in derivative losses without the benefit of such losses being partially offset by sales. To reduce the impact of both these risks 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.

At December 31, 2005, the Company had the following outstanding natural gas hedges in place:

Weighted average

Production period

Hedge type

Daily volume

USD Price/MMBtu

First quarter 2006

Swap

10,000 MMBtu

8.58

Second quarter 2006

Swap

6,000 MMBtu

7.82

Third quarter 2006

Swap

6,000 MMBtu

7.85

Fourth quarter 2006

Swap

6,000 MMBtu

8.21

The Company estimates that these swaps hedge approximately 25% to 35% of its 2006 estimated production.

At December 31, 2005, the Company estimated that it would have realized a loss of approximately $6.7 million if it had elected to settle the swap agreements before their expiration. The Company currently does not intend to settle any swaps before their expiration. See “Item 11— Quantitative and Qualitative Disclosures About Market Risk.”

New Accounting Pronouncements Not Yet Adopted

In December 2004, the Financial Accounting Standards Board (“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. The Company is currently assessing the impact of the adoption of this revised Statement though it does not expect that the initial adoption of this revised Statement will have a significant impact on the Company’s consolidated financial statements.

In December 2004, the FASB issued FASB Statement No. 153,Exchanges of Nonmonetary Assets, which eliminates an exception in APB 29 for recognizing nonmonetary exchanges of similar productive assets at fair value and replaces it with an exception for recognizing exchanges of nonmonetary assets at fair value that do not have commercial substance. This Statement will be effective for the Company for nonmonetary asset exchanges occurring on or after January 1, 2006. The adoption of this Statement will not have a significant effect on the Company’s consolidated financial statements.

In April 2005, the FASB issued FASB Staff Position FAS 19-1,Accounting for Suspended Well Costs(FSP 19-1), 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. FSP 19-1 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. FSP 19-1 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 viability of the project. FSP 19-1 will be effective for the Company as of 1 January 2006. The Company is currently assessing the impact of the adoption of this FSP though it does not expect that the initial adoption of this FSP will have a significant impact on the Company’s consolidated financial statements.

In May 2005, the FASB issued FASB Statement No. 154,Accounting Changes and Error Corrections. Statement 154 establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to a newly adopted accounting principle. This Statement will be effective for the Company for all accounting changes and any error corrections occurring after January 1, 2006.

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 May 1, 2006, the Company had posted $6.9 million of required bonding with the MMS. $2.9 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.

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;

	•		our outlook on operating, exploration, and development costs;

	•		estimates of our oil and natural gas reserves;

	•		replacement 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, the impact of weather and the occurrence of natural disasters such as fires, floods and other catastrophic events, 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, the impact of developments in oil-producing and natural gas producing countries, 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 $10.1 million at December 31, 2005. On March 3, 2006, the Company completed a placement of 15,000,000 shares at A$2.00 per share to raise a net A$29.3 million (net of A$0.75 million equity raising costs) or approximately U.S.$21.5 million to partially fund an accelerated exploration and development programme in 2006. The shares were issued in a private placement under Part 6D.2 of the Australian Corporations Act 2001 (“Act”).

At May 1, 2006, the Company’s cash balances were approximately $28.5 million. The Company believes that, based on its committed capital expenditures and forecast cash flows from operations, its current cash and sources of liquidity are sufficient for the Company’s present requirements. If the Company proceeds with exploration and development plans that require significantly greater expenditures beyond its current commitments, additional sources of liquidity may be required. Such sources include the issuance of additional equity or the incurrence of debt.

Cash Flow

The following table represents cash flow data for the Company for the periods indicated.


	Years Ended December 31,
	2003			2004			2005
	(in thousands)

Net cash provided by (used in):
Operating activities	$	18,589		$	22,032		$	34,915
Investing activities		(13,574	)		(26,046	)		(33,651	)
Financing activities		6,851			1,070			(644	)

Cash flow from operating activities in 2005 was higher than in 2004, closely reflecting the 0.8 Bcfe increase in production and the $1.27 increase in realized gas prices for the year.

The Company’s $33.7 million of net investment activities in 2005, including 31.7 million paid for oil and gas properties and property, plant and equipment, was funded entirely from cash flows from operating activities.

The Company also provided cash collateral of $2.0 million to hedging instruments counterparties and received net distributions from investments of $0.1 million.

Net cash used in financing activities for the year ended December 31, 2005 of $0.6 million comprised short-term loan repayments used for insurance premium funding of $1.1 million offset by proceeds of $0.5 million from the issue of shares upon exercise of employee options during the year.

Credit Facilities

Effective February 20, 2004, PEI entered into a $2.0 million credit facility 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 MMS. This credit facility was subsequently increased to $3.0 million in July 2004, $6.0 million in December 2004 and $10.0 million in October 2005. During 2005, the final maturity date of the credit facility was extended from 31 March 2006 to 31 March 2007. In connection with the facility, letters of credit totalling $6.2 million are outstanding as of May 1, 2006. Letters of credit totalling $2.9 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 totalling $3.3 million secure the Company’s obligations to a hedging counterparty.

PEI incurs fees of 1³/4% to 2% per annum on the value 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 facility. 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 plus¹/2% pa, but no less than 4¹/2% pa or (ii) at LIBOR plus 3¹/2% pa. Upon final maturity of the credit facility, all loans and interest outstanding become due. The final maturity date of the credit facility, which was recently extended by one year, is March 31, 2007. To date, there have been no loans under the credit facility.

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

In March 2006, the Company was high bidder on four Gulf of Mexico leases and expects the leases to be awarded at a total cost of $2.3 million. In total, the Company expects to expend at least $50 million for acquisitions, exploration and development in 2006 including at least $1.4 million in China.

The Company anticipates that it will fund these projects through a combination of available cash, cash flow from operations and issuance of equity securities.

C. Research and Development

Not applicable.

D. Trend Information

The Company anticipates production for 2006 will be higher than 2005 as it should benefit from the commencement of production in early January 2006 from three wells successfully drilled at Main Pass 19 during the second quarter of 2005. The Company also expects to bring into production, during the second quarter of 2006, a further three wells that were successfully drilled and completed at Main Pass 19 over the period from December 2005 through to February 2006. The Company owns a 55% working interest in Main Pass 19. The Company plans to undertake further drilling in 2006, which could result in further increases in production for 2006. In conjunction with increased production, lease operating expenses and DD&A will also be higher in 2006. The anticipated increase in production for 2006 will be partially offset by the natural decline of production from West Cameron 343/352.

Hurricanes Katrina and Rita have resulted in escalated insurance costs and less favorable terms. As a result, the Company will expend more for it insurance coverage in 2006 compared to 2005.

Higher oil and gas prices have led to increased employment of oilfield service equipment and personnel. The increased employment has resulted in higher costs for oilfield services. These higher costs will contribute to higher operating costs and finding and development costs in 2006.

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, 2005


US$’000	Payments due by periods as of December 31, 2005
Contractual obligations	Total		Less than 1 year		1 — 3 years		3 — 5 years		After 5 years


Operating leases	$	815	$	267	$	548	$	—	$	—
Exploration lease rental		1,463		357		944		162		—


Total contractual cash obligations	$	2,278	$	624	$	1,492	$	162	$	—

In addition to the contractual cash obligations listed above, the Company has committed to expending approximately $8.9 million in total during 2006 for exploration and development within the U.S. and China in respect of its joint operating arrangement commitments and also has a commitment of up to $734,000 to an investment fund.

G. Critical Accounting Policies

The Company’s critical accounting policies under U.S. 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 U.S. GAAP with no need for the application of the Company’s judgment. In certain circumstances, however, the preparation of consolidated financial statements in conformity with U.S. GAAP 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 $5.3 million and $4.1 million were written-off and charged to the line item “Dry hole and abandonment costs” in the Company’s consolidated statements of operations for the years ended December 31, 2005 and 2004, 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.

No impairment charge was recognised during the year ended December 31, 2005. In 2004 and 2003, the Company recognized an impairment charge of $201,000 and $38,000, respectively.

(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 proved reserves. 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 revisions to the estimated reserves.

(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, 2005 the Company has net operating losses (“NOLs”) of approximately $38.8 million which are available to offset future U.S. federal taxable income. The NOLs from previous tax periods will expire from 2016 through 2021.

During 2005, the Company further revised its estimate of the amount of deferred tax assets it believes it will ultimately be able to realize based on current forecasts of future taxable income for the next three years. This reduced the deferred tax asset valuation allowance in our consolidated balance sheet by $2.7 million with a corresponding increase in income tax benefit in our consolidated statement of income in 2005.

In 2004, the Company revised its estimate of the amount of deferred tax assets it believed it would ultimately be able to realize as a result of changes in its forecast of future taxable income over the next three years in the U.S. (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 income in 2004. The Company was also able to realize the benefits of approximately $2.6 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 income in 2004.

In 2003, the Company was also able to realize the benefits of approximately $5.3 million of deferred tax assets that were not previously recognized following the generation of taxable income for that year. 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 income in 2003.

(5)Asset retirement obligations

The Company recognizes a liability for the legal obligation associated with the retirement of 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 (rehabilitation) on a units-of-production basis.

There have been no significant changes to the assumptions used in determining the asset retirement obligations since the inception of the legal obligations. The asset retirement obligation as of December 31, 2005 is $1.3 million.

(6)Derivative financial instruments

The Company used derivative financial instruments to hedge cash flows associated with its natural gas sales. In accordance with SFAS 133, the Company records its derivative financial instruments at fair value. At the time of entering into a hedge agreement the Company must assess whether the derivative instrument will be effective in hedging against the variability in cash flows associated with forecasted sales of natural gas. If a derivative instrument is expected to be an effective cash flow hedge, then all changes in the fair value of the derivative instrument are recorded as a deferred gain or loss in other comprehensive income until the underlying natural gas is produced and sold. On a quarterly basis thereafter, the Company must assess whether the derivative instrument has been and is expected to continue to be effective in hedging such cash flows. If the Company determines that a derivative instrument will no longer be an effective cash flow hedge, then all changes in fair value from the time the

derivative instrument ceases to be effective are recorded as gains or losses in the statement of income. If an underlying forecasted natural gas sale is no longer expected to occur, then the derivative instrument ceases to qualify for hedge accounting treatment, and the entire fair value gain or loss associated with the derivative instrument is recorded in the statement of income immediately.

In the third quarter of 2005, a major hurricane caused disruptions in the third-party systems on which the Company relies to process and deliver a substantial portion of its production. As a result of the disruption, derivative instruments associated with underlying production of 840,000 MMBtu no longer qualified for hedge accounting treatment due to the ineffective hedge relationship resulting in 2005 derivative losses from discontinued hedges of $4.6 million, which are recognised in the consolidated statement of income.

H. Safe Harbor

See Item 5A. Operating Results — Forward Looking Statements

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)	58	Chairman, Managing Director and Chief Executive Officer
David A. Mortimer	61	Director, Chairman of Audit and Remuneration and Nomination Committees
Peter E. Power	72	Director

Executive officers:
Ross A. Keogh	47	President of Petsec Energy Inc.
Fiona A. Robertson (1)	50	Chief Financial Officer
Craig H. Jones (1)	47	General Manager — Corporate and Company Secretary


(1)		Mr. Fern, Mrs. Robertson and Mr. Jones provide services to the Company through contractual arrangements between the Company and corporate affiliates.

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, Macquarie Infrastructure Investment Management Ltd, Sigma Pharmaceuticals Ltd, and is Deputy Chairman of Australia Post and Chairman of Crescent Capital Partners Limited and the Defence Procurement Advisory Board. Mr. Mortimer holds a Bachelor of Economics degree from The University of Sydney.

PETER E. POWER has over 50 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. He is a director of Metgasco Limited.

ROSS A. KEOGH joined the Company in 1989 and has over 25 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.

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 Ltd as General Manager, Finance/Chief Financial Officer. Mrs. Robertson holds a Master of Arts degree 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 2005 was $456,654. The total compensation received by the executive officers of the Company and its controlled and related companies for 2005 was $1,192,763.



Fiscal year ended					Other		Retirement
December 31, 2005	Base emoluments		Bonuses		benefits (6)		benefit plans		Other compensation		Total

Directors
T.N. Fern (1)	$	—	$	—	$	23,412	$	—	$	350,250	$	373,662
D.A. Mortimer		38,070		—		—		3,426				41,496
P.E. Power		38,070		—		—		3,426				41,496

Executive Officers
R.A. Keogh (2)		175,663		89,000		23,813		8,734		—		297,210
P. Kallenberger (2) (8)		162,900		78,000		23,032		8,385		—		272,317
N. Fakier (2) (7)		145,649		67,000		18,888		7,224		—		238,761
F.A. Robertson (3)		—		—		4,603		—		108,206		112,809
C. H. Jones (4)		—		—		1,808		—		144,971		146,779
G. H. Fulcher (5)		43,847		—		1,096		79,944		—		124,887


(1)		Included in other compensation above is an amount of $350,250 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 6¹/2 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 2005, the Company recorded $0.4 million of compensation expense under the plan.

(3)		Included in other compensation above is an amount of $108,206 which was paid or is payable to Geofin, a company through which Mrs. Robertson provided services.

(4)		Included in other compensation above is an amount of $144,971 which was paid or is payable to Geofin, a company through which Mr. Jones provided services.

(5)		Mr. Fulcher resigned from his position of Company Secretary on February 28, 2005. The retirement benefit plans amount of $79,944 includes an amount paid to him as a discretionary termination benefit.

(6)		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.

(7)		Mr. Fakier retired from his position of Vice President, Operations of Petsec Energy Inc. on March 20, 2006.

(8)		Mr. Kallenberger resigned from his position of Vice President, Exploration of Petsec Energy Inc. on April 21, 2006.

In addition, the Company has accrued $228,000 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. At December 31, 2005, the number of further shares or options, which could be issued within the limit, was 5,236,067.

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, 2005, 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 exercise 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, 2005, directors of the Company held no options to purchase Ordinary Shares pursuant to the Option Plan. During the year, Mr. R.A. Keogh, Mr. P. Kallenberger and Mr. N. Fakier exercised 925,000, 825,000 and 300,000 options on Ordinary Shares, respectively at an exercise price of A$0.30 per share. At December 31, 2005, Mr. Keogh, Mr. Kallenberger and Mr. Fakier held 325,000, 300,000 and 300,000 remaining options to purchase Ordinary Shares at an exercise price of A$0.30 per share. All three executive officers received their options during 2002 and their options will expire on June 1, 2007. On March 1, 2006, Mr. C. Jones and Mrs. F. Robertson were each granted 225,000 options on Ordinary Shares at an exercise price of A$2.13 per share. On March 30, 2006, Mr. N. Fakier exercised his remaining 300,000 options at an exercise price of A$0.30 per share. On April 3, 2006, Mr. P. Kallenberger also exercised his remaining 300,000 options at an exercise price of A$0.30 per share. 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:


	Regular		Additional		Audit		Nomination and		Date
	Board		Board		Committee		Remuneration		Director First
	Meetings		Meetings		Meetings		Committee Meetings		Appointed
Total number held during the year		11		—		3		3

T.N. Fern		10		—		1		3	May 21, 1987
D.A. Mortimer		11		—		3		3	July 1, 1985
P.E. Power		10		—		3		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.

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, 2005, the Company had 20 full-time employees 17 of whom were in Lafayette, Louisiana, and three 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 1, 2006 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 137,026,341 Ordinary Shares outstanding on May 1, 2006.


	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)		30,791,389		22.5	%		—
Terrence N. Fern (2) (3)		26,882,498		19.6	%		—
D.A Mortimer		610,068		*			—
P.E. Power		225,323		*			—
R. A. Keogh (4)		925,000		*			325,000
P. Kallenberger (4)		925,000		*			—
N. Fakier (4)		998,500		*			—
F.A. Robertson (5)		75,000		*			225,000
C. H. Jones (5)		150,000		*			225,000
Den Duyts Corporation Pty Limited (3)		18,344,639		13.4	%		—


*		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.

(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 1, 2006, were 26,882,498 Ordinary Shares and the “relevant” interests of Mr. Fern were 26,882,498 Ordinary Shares.

(4)		Options expire on June 1, 2007 and are exercisable at a price of A$0.30.

(5)		Options granted on February 24, 2006, expiring on February 24, 2011 and exercisable at a price of A$2.13.

Please see “Share and Option Plans” in Section B “Compensation” of this Item 6 for a description of the Company’s arrangement for involving the employees in the capital of the Company

ITEM 7 — MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. Major shareholders

At May 1, 2006, 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		19.62
Den Duyts Corporation Pty Limited		18,344,639		13.39
National Nominees Ltd		12,025,858		8.78
ANZ Nominees Limited		9,536,796		6.96
Citicorp Nominees Pty Limited		7,261,013		5.30


(1)		Includes shares held by Den Duyts Corporation Pty Limited.

Approximately 97% of the Company’s voting securities are held by 4,612 shareholders in the host country.

Major shareholders who had significant changes in the percentage ownership held during the past three years were:


Shareholder	May 3, 2004				May 31, 2005				May 1, 2006
	No. of		%		No. of		%		No. of		%
	Shares		o’ship		Shares		o’ship		Shares		o’ship
Citicorp Nominees Pty Limited		10,534,574		8.84		11,628,544		9.73		7,261,013		5.30
ANZ Nominees Limited		11,745,244		9.85		9,869,265		8.26		9,536,796		6.96
National Nominees Ltd		13,046,782		10.95		12,703,062		10.63		12,025,858		8.78

The Company’s shares are all of one class and carry equal voting rights. At May 1, 2006, there were 137,026,341 ordinary shares held by 5,059 shareholders.

B. Related party transactions

(a) Directors

The names of persons who were directors of the Company during the year ended December 31, 2005 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, 2005 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 2005 by the company associated with Mr. Fern was $603,000 (also refer to Item 6(b) for further details).

The Company holds unlisted shares in an investment fund of which Mr. Mortimer is Chairman. At December 2005, the Company had invested $417,000 in the fund and has a total commitment to the fund of up to $734,000.

At December 31, 2005, 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.

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, 2003		December 31, 2004		December 31, 2005
	$’000		$’000		$’000

Receivables — non-current		14,902		21,734		21,196
Payables — non-current		5,661		11,644		11,156

At December 31, 2005, 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 U.S. Dollar Financial Statements of the Company and the Report of Independent Registered Public Accounting Firm are included on pages F-1 through F-29 of the Form 20-F. See Item 18 below.

B. Significant Changes

On March 3, 2006, Petsec issued 15,000,000 shares at A$2.00 per share to raise a net A$29.3 million (net of A$0.75 million equity raising costs) or approximately US$21.5 million to partially fund an accelerated exploration and development programme in 2006. The shares were issued in a private placement under Part 6D.2 of the Australian Corporations Act 2001 (“Act”).

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 U.S. 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

Year ended December 31, 2003:		1.13		0.25		0.84		0.19

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

Year ended December 31, 2005:
First Quarter 2005		1.29		1.07		1.00		0.83
Second Quarter 2005		1.20		0.88		0.92		0.68
Third Quarter 2005		1.71		0.98		1.30		0.74
Fourth Quarter 2005		1.97		1.34		1.47		1.00

November 2005		1.68		1.44		1.24		1.06
December 2005		1.97		1.69		1.46		1.25
January 2006		1.95		1.83		1.48		1.39
February 2006		2.25		2.09		1.66		1.54
March 2006		2.41		2.10		1.72		1.50
April 2006		2.61		2.28		1.97		1.72

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 U.S. dollars:


	US$
	High		Low

Year ended December 31, 2001		0.47		0.20

Year ended December 31, 2002		0.81		0.32

Year ended December 31, 2003		4.15		0.70

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
Year ended December 31, 2005
First Quarter 2005		5.00		4.05
Second Quarter		4.60		3.40
Third Quarter		6.30		3.60
Fourth Quarter		6.35		5.14

November 2005		6.10		5.20
December 2005		6.10		6.10
January 2006		7.21		6.65
February 2006		8.25		7.60
March 2006		8.75		7.55
April 2006		9.90		8.32

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 1, 2006, 1,610,965 ADRs were on issue. These were equivalent to 8,054,825 Ordinary Shares or approximately 6% of the Company’s issued capital.

D. Selling Shareholders

Not applicable.

E. Dilution

Not applicable.

F. Expenses of the Issue

Not applicable.

ITEM 10 — ADDITIONAL INFORMATION

A. Share Capital

Not applicable

B. Constitution

The Company is a public company registered or taken to be registered under theCorporations Act2001 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.

Power to vote in 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 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 three, 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 two 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 three 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 one 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.

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.

Redemption and Alteration of Share Capital

The Company may reduce or alter its share capital in any manner permitted by theCorporations Act2001 and the Listing Rules of the Australian Stock Exchange.

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 five 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 three 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 AustralianForeign Acquisition and Takeovers Act1975 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.

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.

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.

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.

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 holding period requirements and other 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” in taxable years beginning on or before December 31, 2008. 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 that the U.S. Treasury Department determines to be satisfactory and that includes an exchange of information provision. The U.S. Treasury Department has determined that the Treaty meets these requirements; thus, subject to the limitations discussed in the following sentence, it appears the Company should be treated as a qualified foreign corporation. However, if in the year in which the dividend was paid or in the immediately preceding taxable year the Company constitutes (a) a “Passive Foreign Investment Company” (as defined below), 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.

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 constituted a FPHC in the applicable tax years covered by this report. The FPHC rules have been repealed with respect to taxable years of the Company beginning after December 31, 2004.

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 constituted a FIC in the applicable tax years covered by this report. The FIC rules have been repealed with respect to taxable years of the Company beginning after December 31, 2004.

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”).

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.

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 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 2005, the Company used natural gas swap agreements and costless collars as economic hedges 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 accounts for the natural gas swap agreements and costless collars in accordance with FASB Statement No. 133 (“FAS 133”) and other related FASB statements. See “Item 5 — Operating and Financial Review and Prospects — A. Operating Results — Hedging Transactions.”

The following table shows information on the Company’s fixed price natural gas swaps in place for 2006 as of December 31, 2005:


						Approximate Fair
		Notional Quantity		Average Price		Value at December
Type of Agreement	Remaining Term	(MMBtu per day)		Received per MMBtu		31, 2005

Swaps	Jan-Mar 2006		2,000	$	7.58		($673,000	)
Swaps	Jan-Mar 2006		2,000	$	7.92		($613,000	)
Swaps	Jan-Dec 2006		2,000	$	7.65		($2,226,000	)
Swaps	Jan-Dec 2006		2,000	$	8.20		($1,835,000	)
Swaps	Jan-Dec 2006		2,000	$	8.89		($1,334,000	)

The Company’s current commodity hedging policy allows for hedging up to 60% of expected production from proved developed properties up to 12 months and no greater than 25% of expected production from proved developed reserves over a period of 12 months to 24 months only. At December 31, 2005, approximately 35% to 40% of expected production from developed properties was hedged.

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/U.S. 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/U.S. dollar exchange rate risk except through natural hedging techniques such as maintaining cash balances in U.S. dollar accounts to support operations conducted in U.S. dollars.

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, 2005.

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.

There have been no changes in the Company’s internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 2004 and 2005, and fees billed for other services rendered by KPMG.


	2004		2005
Audit fees	$	128,940	$	226,308
All other fees		—		—
Total fees (1)	$	128,940	$	226,308


(1)		Total fees include amounts billed in foreign currencies, and are translated to U.S. Dollars as of the date of approval of the fees.

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 U.S. Dollar Financial Statements of the Company and the Report of Independent Registered Public Accounting Firm are included on pages F-1 through F-29 of this Form 20-F.

ITEM 19 — EXHIBITS

Exhibits


1.1		Constitution of the Company, incorporated herein by reference to Exhibit 1.1 to Form 20-F for the Company for the year ended December 31, 2004.

4.1		Form of employment contract agreement for Australian-based executives, incorporated herein by reference to Exhibit 4.1 to Form 20-F for the Company for the year ended December 31, 2004

4.2		Form of employment contract agreement for U.S.-based executives, incorporated herein by reference to Exhibit 4.2 to Form 20-F for the Company for the year ended December 31, 2004

8.1		Subsidiaries of the Company.

11.1		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.

12.1		Certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

12.2		Certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

13.1		Certification of CEO pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

13.2		Certification of CFO pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

15.1		Consent of Registered Independent Public Accounting Firm.

15.2		Consent of Independent Petroleum Engineers

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

Petsec Energy Ltd

ACN 000 602 700

U.S. Dollar Consolidated Financial Statements
Under U.S. Generally Accepted
Accounting Principles
December 31, 2005


Consolidated Balance Sheets			F2
Consolidated Statements of Income			F3
Consolidated Statements of Comprehensive Income			F4
Consolidated Statements of Cash Flows			F5
Notes to the Consolidated Financial Statements			F6
Report of Independent Registered Public Accounting Firm			F29

CONSOLIDATED BALANCE SHEETS
Petsec Energy Ltd and subsidiaries


	December 31			December 31
	2004			2005
(U.S. dollars, in thousands except share data)


Assets
Current assets
Cash	$	9,518		$	10,138
Margin deposits (note 13)		—			2,059
Trade receivables		6,930			11,250
Other receivables		64			57
Fair value of derivative financial instruments (note 10(c))		1,406			—
Deferred tax assets (note 2)		7,975			10,220
Prepayments		2,016			1,460

Total current assets		27,909			35,184


Non-current assets
Proved and unproved oil and gas properties		33,542			48,814
Investment securities (note 6)		543			417
Property, plant and equipment (note 7)		245			176
Deferred tax assets (note 2)		1,288			2,703

Total non-current assets		35,618			52,110

Total assets	$	63,527		$	87,294


Liabilities and shareholders’ equity
Current liabilities
Accounts payable and accrued liabilities (note 8)	$	10,337		$	24,784
Fair value of derivative financial instruments (note 10(c))		—			6,681
Short-term loans (note 10(a))		1,175			—

Total current liabilities		11,512			31,465


Long-term liabilities
Other accrued liabilities — non-current (note 9)		1,116			1,566

Total long-term liabilities		1,116			1,566


Shareholders’ equity
Share capital — 250,000,000 authorized; ordinary shares of issued and outstanding 121,389,341 (2004: 119,222,841). (notes 11 and 12)		130,106			130,725
Accumulated other comprehensive loss (note 12)		(1,964	)		(7,206	)
Accumulated deficit		(77,243	)		(69,256	)

Total shareholders’ equity		50,899			54,263

Total liabilities and shareholders’ equity	$	63,527		$	87,294

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME
Petsec Energy Ltd and subsidiaries


	Year ended
	December 31			December 31			December 31
(U.S. dollars, in thousands except earnings per share)	2003			2004			2005

Revenues
Oil and gas sales (net of royalties incurred)	$	23,270		$	32,575		$	45,130
Oil and gas royalties earned		1,949			223			332

Total revenues	$	25,219		$	32,798		$	45,462


Operating expenses
Lease operating expenses		1,557			1,776			2,465
Depletion, depreciation, amortization, and rehabilitation		6,574			12,361			15,597
Exploration expenditure		1,329			1,452			5,844
Dry hole and abandonment costs		—			4,119			5,290
Major maintenance expense		—			592			—
Impairment expense		38			201			—
General, administrative and other expenses		3,519			4,657			5,814
Hurricane-related business interruption insurance proceeds		—			—			(867	)
Stock compensation expense		90			83			88

Total operating expenses		13,107			25,241			34,231

Income from operations	$	12,112		$	7,557		$	11,231

Other income and expense
Interest expense		(10	)		(32	)		(23	)
Interest income		142			311			393
Other income, net		364			91			403
Derivative losses from discontinued hedges (note 1(h) and 10(c))		—			—			(4,615	)

Total other income and expense	$	496		$	370		$	(3,842	)

Income before income tax		12,608			7,927			7,389
Income tax benefit (note 2)		492			9,807			598

Net income	$	13,100		$	17,734		$	7,987


Earnings per share (note 3)
- basic	$	0.12		$	0.15		$	0.07
- diluted	$	0.12		$	0.15		$	0.07

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Petsec Energy Ltd and subsidiaries


	Year ended
	December 31			December 31			December 31
(U.S. dollars, in thousands)	2003			2004			2005


Net income	$	13,100		$	17,734		$	7,987


Other comprehensive income (loss)
Loss on available-for-sale securities reclassified to earnings		—			—			16
Foreign currency translation adjustments		(26	)		(413	)		(123	)
Unrealized gain (loss) on cash flow hedges		(346	)		1,752			(8,087	)
Aggregate income tax benefit (expense) related to other comprehensive income (loss)		137			(692	)		2,952

Comprehensive income	$	12,865		$	18,381		$	2,745

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
Petsec Energy Ltd and subsidiaries


	Year ended
	December 31			December 31			December 31
(U.S. dollars, in thousands)	2003			2004			2005


Cash flows from operating activities
Net income	$	13,100		$	17,734		$	7,987
Adjustment to reconcile net income to net cash from operating activities:
- depletion, depreciation, amortization, and rehabilitation		6,574			12,361			15,597
- dry holes and abandonments		—			4,119			5,290
- impairment expense		38			201			—
- employee stock compensation expense		90			83			88
- deferred income tax benefits		(492	)		(9,807	)		(708	)
Changes in operating assets and liabilities:
- accounts receivable and prepayments		(3,445	)		(6,284	)		(3,757	)
- accounts payable and accrued liabilities		2,724			3,625			10,418

Net cash from operating activities		18,589			22,032			34,915


Cash flows from investing activities
Additions to oil and gas properties and property, plant and equipment		(13,372	)		(27,957	)		(31,736	)
Purchases of investment securities and margin deposits		(1,453	)		(209	)		(2,059	)
Proceeds from sale of fixed assets		—			5			—
Distribution proceeds from bankruptcy trustee		82			—			—
Proceeds from sale of investment securities		1,169			2,115			144

Net cash from investing activities		(13,574	)		(26,046	)		(33,651	)


Cash flows from financing activities
Repayment of short-term loans		(402	)		(908	)		(1,175	)
Proceeds from issuance of shares		7,253			1,978			531

Net cash from financing activities		6,851			1,070			(644	)


Net increase (decrease) in cash		11,866			(2,944	)		620
Cash at beginning of the period		596			12,462			9,518

Cash at the end of the period	$	12,462		$	9,518		$	10,138

See accompanying notes to consolidated financial statements.

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 and subsidiaries (the Company) 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 U.S. generally accepted accounting principles (“GAAP”), with the U.S. 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

Impairment of oil and natural gas properties

Management’s assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of properties are subject to change in the future. Any change could cause impairment expense to be recorded, reducing net income and the carrying value of the related asset. Future prices received for the 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 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

Depreciation, depletion, and amortization

The Company records depreciation, depletion, and amortization (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 proved reserves. 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 revisions to the estimated reserves.

Asset retirement obligations

(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 8
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 interests in unincorporated joint operating arrangements are 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, 2005 and 2004 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 any tax effect, on available-for-sale securities are excluded from earnings and are reported as a separate component of other comprehensive income (loss) 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

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 incurred 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, collection of relevant receivable is probable, persuasive evidence of an arrangement exists and the sales price is fixed and determinable.

Revenue from oil and natural gas royalties earned 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.

For all hedging relationships the Company formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the hedged item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

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 (loss), net of related taxes, to the extent the hedge remains effective. Gains or losses on qualifying hedges are recognized in oil and gas sales in the period when the hedged production is delivered. 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 other income and expense. The fair value of these derivative financial instruments are recognized on the balance sheet as “Fair value of derivative financial instruments”.

The Company discontinues hedge accounting when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. In any of these circumstances, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur. In all situations in which hedge accounting is discontinued and the derivative is retained, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in other income and expense. When it is probable that a forecasted transaction will not occur, the Company discontinues hedge accounting, if not already done, and recognizes immediately in other income and expenses any gains and losses that were accumulated in other comprehensive income.

(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 sheet date. The provision has been calculated based on estimated wages to be paid out and salary rates and includes related on-costs. A liability is recognized for employee incentive plans based on a percentage of operating profits. Employer contributions to superannuation funds are charged against earnings. Further information is set out in note 13(d) — Superannuation commitments, incentive compensation, and directors’ retirement obligation.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

(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.

(k) Foreign currency

Functional and presentation currency

Items included in the financial statements of each of the Company’s subsidiaries are measured using the currency of the primary economic environment in which the subsidiary operates (“the functional currency”). The functional currency of the Australian subsidiaries is Australian dollars (A$) and the functional currency of the Company’s overseas subsidiaries is United States dollars (US$).

The financial statements are presented in United States dollars. The consolidated entity believes the U.S. dollar is the best measure of performance for Petsec Energy Ltd because oil and gas, the consolidated entity’s dominant sources of revenue, are priced in U.S. dollars and the consolidated entity’s main operations are based in the USA and China with most of the costs incurred in U.S. dollars.

Prior to consolidation, the results and financial position of each entity within the group are translated from the functional currency into the group’s presentation currency as follows:

	•		assets and liabilities for each balance sheet are translated at the closing rate at the date of that balance sheet;

	•		income and expenses for each income statement are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions);

	•		components of equity are translated at the historical rates; and

	•		all resulting exchange differences are recognised directly to the foreign currency translation adjustment and forms part of the accumulated other comprehensive income (loss).

Foreign currency transactions and balances

Foreign currency transactions are translated at the exchange rates prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies at the balance sheet date are translated to the respective functional currency at the foreign exchange rate ruling at that date. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement. The Company had no significant foreign exchange gains or losses during each of the last three years.

The exchange rates (U.S. dollars for one Australian dollar) used in the preparation of these financial statements are:


	Twelve months ended
	December 31,
	2003		2004		2005


Average exchange rate		0.6515		0.7341		0.7614
Exchange rate at period end		0.7431		0.7784		0.7336

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

(l) 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 2005 were 4.3 to 4.5 years (weighted average 4.5 years); 51%; 0% and 5.10% per annum, respectively; 4.4 to 4.5 years (weighted average 4.4 years); 49.90%; 0% and 5.05% per annum, respectively, in 2004 and 4.4 to 4.5 years (weighted average 4.4 years); 86.90%; 0% and 5.53% per annum, respectively, in 2003. The average fair value per option granted in 2005 using the Black-Scholes valuation method was A$0.19 per option (2004: A$0.16; 2003: A$0.07).

(m) Trade receivables

Trade receivables are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts, where necessary is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable.

(n) Use of estimates

The preparation of the consolidated 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 capitalized costs, asset retirement obligations and income taxes. Actual results could differ from those estimates.

(o) Reclassifications

Certain prior period amounts have been reclassified to achieve consistency in disclosure with the current financial year presentation.

(p) Recently Issued Accounting Standards Not Yet Adopted

In December 2004, the Financial Accounting Standards Board (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. The Company is currently assessing the impact of the adoption of this revised Statement though it does not expect that the initial adoption of this revised Statement will have a significant impact on the Company’s consolidated financial statements.

F10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

(p) Recently Issued Accounting Standards Not Yet Adopted (continued)

In April 2005, the FASB issued FASB Staff Position FAS 19-1,Accounting for Suspended Well Costs (FSP 19-1), 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. FSP 19-1 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. FSP 19-1 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 viability of the project. FSP 19-1 will be effective for the Company as of 1 January 2006. The Company is currently assessing the impact of the adoption of this FSP though it does not expect that the initial adoption of this FSP will have a significant impact on the Company’s consolidated financial statements.

2.Income taxes

Income (loss) before income taxes for the years ended December 31, 2003, 2004 and 2005 were taxed under the following jurisdictions:


				Year ended
	December 31			December 31			December 31
(U.S. Dollars, in thousands)	2003			2004			2005


Australia	$	(1,091	)	$	(1,241	)	$	(1,672	)
U.S.		13,699			9,168			9,061

	$	12,608		$	7,927		$	7,389


Income tax expense (benefit) is presented below:

Current:
Australia	$	—		$	—		$	—
U.S.		250			—			200

	$	250		$	—		$	200

Deferred:
Australia	$	(742	)	$	—		$	—
U.S.		—			(9,807	)		(798	)

	$	(742	)	$	(9,807	)	$	(798	)

Income tax benefit	$	(492	)	$	(9,807	)	$	(598	)

Income tax benefit differed from the amounts computed by applying an income tax rate of 30% (the statutory rate in effect in Australia) (2004: 30%, 2003: 30%) to income before income taxes as a result of the following:


				Year ended
	December 31			December 31			December 31
(U.S. Dollars, in thousands)	2003			2004			2005


Computed “expected” tax expense	$	3,782		$	2,378		$	2,217

Increase (reduction) in income taxes resulting from:
Adjustment of prior year net operating loss		1,099			(242	)		(58	)
U.S. income taxes at different rates		822			485			438
Reversal of contingencies		(840	)		—			—
Change in valuation allowance		(5,329	)		(12,422	)		(3,195	)
Other		(26	)		(6	)		—

Actual tax benefit	$	(492	)	$	(9,807	)	$	(598	)

F11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

2.Income taxes (continued)

The significant components of deferred income tax benefit attributable to income from continuing operations for the years ending December 31, 2003, 2004 and 2005 are as follows:


				Year ended
	December 31			December 31			December 31
(U.S. Dollars, in thousands)	2003			2004			2005

Deferred tax expense (benefit), exclusive of the effects of other components below	$	(742	)	$	(35	)	$	2,693
Decrease in beginning-of-the-year balance of valuation allowance for deferred tax assets		—			(9,772	)		(3,491	)

		(742	)		(9,807	)		(798	)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2004 and 2005 are presented below.


	December 31			December 31
	2004			2005
	(U.S. Dollars, in thousands)

Deferred tax assets:
Employee entitlement provisions	$	91		$	—
Alternative minimum tax credit carryforward		250			450
Unrealized loss on derivative financial instruments		—			2,338
U.S. sourced net operating loss carryforwards		16,559			13,590
Australian sourced net operating loss carryforwards		1,506			1,802

Total deferred tax assets	$	18,406		$	18,180
Less valuation allowance		(4,997	)		(1,802	)

Deferred tax assets, net of valuation allowance		13,409			16,378


Deferred tax liabilities:
Proved and unproved oil and gas properties		(3,591	)		(3,455	)
Unrealized gain on derivative financial instruments		(555	)		—

Total deferred tax liabilities		(4,146	)		(3,455	)

Net deferred tax assets	$	9,263		$	12,923

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, 2003, the deferred tax asset valuation allowance was $22,748,000. The valuation allowance was required because of a series of previous operating losses, which meant that management was unable to conclude that it was more likely than not that the benefit of its existing net deferred tax assets would be realized in the future. During 2003, the deferred tax asset valuation allowance was reduced by $5,329,000 primarily as a result of the utilization of some of the Company’s net operating loss carryforwards in the U.S. following the Company’s generation of taxable income for that year. In 2004, the valuation allowance was reduced by $12,422,000 as a further result of the utilization of net operating loss carryforwards in the U.S. and the revision of the Company’s assessment of future taxable income. During 2005, the Company continued to generate taxable income resulting in utilization of more of its net operating loss carryforwards in the U.S. and also revised its assessment of future taxable income. Consequently, the deferred tax asset valuation allowance decreased, by a further $3,195,000.

At December 31, 2005 the Company has gross operating loss carryforwards of $38,827,000 for United States Federal income tax purposes. The carryforwards from previous tax periods will expire from 2016 through 2021. In addition, the Company has alternative minimum tax credit carryforwards of $450,000, which are available to reduce future U.S. Federal regular income taxes, if any, over an indefinite period.

At December 31, 2005, the Company has gross operating loss carryforwards for Australian income tax purposes of approximately U.S.$6,006,000 (based on year end spot rate) which are available to offset future taxable income in Australia. These losses have no expiry.

F12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

3. Earnings per share

Basic earnings per ordinary share is computed by dividing net income 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
	2003		2004		2005
	(in thousands)


Weighted average number of ordinary shares used in the calculation of the basic earnings per share		105,736		118,830		120,112
Incremental shares		2,047		2,673		2,315

Weighted average number of ordinary shares used in the calculation of the diluted earnings per share		107,783		121,503		122,427

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 ordinary share equivalents were calculated using the treasury stock method.

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 FASB Interpretation No. (FIN) 46 (revised December 2003)Consolidation of Variable Interest Entitiesdid not have an impact on the accounting for these joint operating arrangements and the Company continues 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
	2004			2005
	(U.S. Dollars, in thousands)


Lease permits and capital expenditure:
Now in production — at cost
- West Cameron 343	$	10,259		$	11,114
- West Cameron 352		8,124			8,073
Less: Accumulated amortisation		(14,802	)		(17,281	)

	$	3,581		$	1,906

Not in production — at cost
- Main Pass 89		121			121
- Main Pass 19 (1)		1,537			21,200
- Block 22/12 Beibu Gulf		1,370			2,064
- Price Lake, Onshore Louisiana (2)		—			—
- St James Parish, Onshore Louisiana		2,519			2,518

		5,547			25,903

Total lease permit and capital expenditure	$	9,128		$	27,809

F13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

4. Interests in joint operating arrangements (continued)


	December 31		December 31
	2004		2005
	(U.S. Dollars, in thousands)


Asset retirement obligation liability:
- West Cameron 343	$	217	$	238
- West Cameron 352		89		86
- Main Pass 19		—		421

	$	306	$	745


	December 31			December 31			December 31
	2003			2004			2005
	(U.S. Dollars, in thousands)

The contribution of the Company’s joint operating arrangements to income from operations
- West Cameron 343	$	11,589		$	7,342		$	1,766
- West Cameron 352		3,630			1,117			1,786
- Block 22/12 Beibu Gulf (3)		(302	)		(1,373	)		(358	)
- Price Lake, Onshore Louisiana (2)		—			(3,188	)		(5,283	)
- St James Parish, Onshore Louisiana		—			—			(5,103	)

	$	14,917		$	3,898		$	(7,192	)


(1)		Three wells were successfully drilling during the year and were brought into production in January 2006. A further three wells were successfully drilled in December 2005 through January 2006 and are expected to be brought into production during second quarter 2006.

(2)		The Company determined subsequent to the year ending December 31, 2004 that the Price Lake drilling targets were dry holes and, in accordance with FASB 19,Financial Accounting and Reporting by Oil and Gas Producing Companiesand FIN 36,Accounting for Exploratory Wells in progress at End of a Period,recorded $2,987,000 to dry hole and abandonment costs and $201,000 to impairment expense in the year ended December 31, 2004. Additionally, capital expenditure incurred subsequent to December 31, 2004 totalling $5,283,000 was expensed to dry hole and abandonment costs by the Company in respect of this joint operating arrangement and the Company subsequently relinquished its entire 25.0% working interest.

(3)		In 2004, the Company recorded $1,132,000 to dry hole and abandonment costs in relation to the dry hole costs of two wells drilled in the Beibu Gulf, China.

The principal activity of all the joint operating arrangements is oil and 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
	2004			2005


Main Pass 89		30.0	%		30.0	%
Main Pass 19		55.0	%		55.0	%
West Cameron 343		75.0% to 100	%		75.0% to 100	%
West Cameron 352		56.3	%		56.3	%
Block 22/12 Beibu Gulf		25.0	%		25.0	%
Price Lake, Onshore Louisiana		25.0	%		—
St James Parish, Onshore Louisiana		50.0	%		50.0	%

F14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

5. Wholly owned areas of interests


	December 31			December 31
	2004			2005
	(U.S. Dollars, in thousands)


Lease permits and capital expenditure:
Now in production at cost
- Vermilion 258 (1)	$	27,602		$	34,000
Less: Accumulated amortisation		(3,895	)		(16,798	)

	$	23,707		$	17,202

Not in production — at cost
- Vermilion 246		243			243
- Vermilion 257		303			359
- Main Pass 18		—			2,421
- Main Pass 103		—			530
- Spare equipment		161			250

	$	707		$	3,803

Total lease permit and capital expenditure	$	24,414		$	21,005


Asset retirement obligation liability:
- Vermilion 258(1)	$	505		$	560


Contribution of area of interest to income from operations:
- Vermilion 258(1)	$	10,608		$	25,137


(1)		Commenced initial production in July 2004.

6. Investments


	December 31		December 31
	2004		2005
	(U.S. Dollars, in thousands)

Non-current
Listed shares at fair value	$	16	$	—
Unlisted shares at cost		527		417

	$	543	$	417

7. Property, plant and equipment


	December 31			December 31
	2004			2005
	(U.S. Dollars, in thousands)

- at cost	$	611		$	615
- accumulated depreciation		(366	)		(439	)

	$	245		$	176

8. Accounts payable and accrued liabilities


	December 31		December 31
	2004		2005
	(U.S. Dollars, in thousands)

Current
Trade creditors	$	1,984	$	7,063
Employee related liabilities		1,057		489
Exploration and development accruals		5,515		10,694
Operational and administration accruals		1,616		1,349
Joint operating arrangement accruals		146		5,163
Related party payables		19		26

	$	10,337	$	24,784

F15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

9. Other accrued liabilities — non-current


	December 31		December 31
	2004		2005
	(U.S. Dollars, in thousands)


Employee entitlements provision	$	305	$	261
Asset retirement obligations		811		1,305

	$	1,116	$	1,566

The Company adopted Statement No. 143,Accounting for Asset Retirement Obligationseffective January 1, 2003. Since no asset retirement obligation existed upon adoption, no cumulative change in accounting principle was reflected in the 2003 financial statements. 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 are discounted and accretion expense is 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 following table shows the changes to asset retirement obligations during 2004 and 2005:


	December 31		December 31
	2004		2005
	(U.S. Dollars, in thousands)


Asset retirement obligations at beginning of year	$	281	$	811
Liabilities incurred during the period		480		452
Liabilities settled during the year		—		(12	)
Liabilities reversed during the year				(32	)
Accretion expense		50		86

Asset retirement obligation at the end of the period	$	811	$	1,305

10. Financing arrangements, liquidity, financial instruments disclosures and significant concentrations

(a) Financing arrangements

At December 31, 2005, the Company had fully repaid its short-term loan relating to its U.S. oil and natural gas operations (2004: $1,175,000), held in the accounts of Petsec Energy Inc. a wholly owned subsidiary. The interest charge on this liability was 5.15% per annum. (2004: 5.15%). The loan expired in August 2005 and was repaid through monthly installments of $150,000.

Effective February 20, 2004, PEI entered into a $2,000,000 credit facility with a U.S. bank for the purpose of securing letters of credit issued by the bank and also to allow the refund of $1,725,000 of cash collateral previously posted to secure surety bonds issued to the Minerals Management Service. This facility was subsequently increased to $3,000,000 on July 2, 2004, $6,000,000 on December 21, 2004 and $10,000,000 on October 12, 2005. During 2005, the final maturity date of the credit facility was extended from March 31, 2006 to March 31, 2007.

Total outstanding letters of credit as at December 31, 2005 were $6,000,000. Letters of credit totaling $2,625,000 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 $3,375,000 secure the Company’s obligations to the hedging counterparties.

F16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

10. Financing arrangements, liquidity, financial instruments disclosures and significant concentrations (continued)

(a) Financing arrangements (continued)

PEI incurs fees of 1³/4% to 2% on the amount of letters of credit issued by the bank. Any funding of a letter of credit issued by the bank will constitute a loan under the credit facility. Principal payments on any loans outstanding are 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 plus¹/2% pa, but no less than 4¹/2% per annum or (ii) at Libor rate plus 3¹/2% per annum. Upon final maturity of the credit facility, all loans and interest outstanding become due. To date, there have been no loans under the credit facility.

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) Foreign exchange exposures

During 2003, 2004 and 2005, operating costs were incurred in both Australian and U.S. dollars.

Throughout 2003, 2004, and 2005, the Company predominantly held the majority of its liquid funds in U.S. dollars.

Fluctuations in the Australian dollar/U.S. 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/U.S. dollar exchange rate risk except through natural hedging techniques such as maintaining cash balances in U.S. dollar accounts to support operations conducted in U.S. dollars.

(c) 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. 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 at any time.

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 relevant NYMEX contract penultimate closing price if the latter is lower than the agreed floor price. If the NYMEX contract penultimate closing price is higher than the agreed ceiling price, the Company will pay the difference to the counterparty.

F17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

10. Financing arrangements, liquidity, financial instruments disclosures and significant concentrations (continued)

At December 31, 2005, the Company had the following outstanding natural gas hedges in place:

Weighted average

Production period

Hedge type

Daily volume

USD Price/MMBtu

First quarter 2006

Swap

10,000 MMBtu

8.58

Second quarter 2006

Swap

6,000 MMBtu

7.82

Third quarter 2006

Swap

6,000 MMBtu

7.85

Fourth quarter 2006

Swap

6,000 MMBtu

8.21

At 31 December 2004, the Company had the following outstanding natural gas hedges in place:

Weighted average

Production period

Hedge type

Daily volume

USD Price/MMBtu

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

Generally, the Company has determined that its hedge agreements are highly effective and qualify for hedge accounting treatment as cash flow hedges. Accordingly, gains or losses on qualifying hedges are recognized into earnings in the period when the hedged production is delivered. Derivative gains or losses are recorded upon settlement of qualifying hedges to the extent that an exact offset is not achieved between the change in the hedging instrument value and the change in natural gas prices. The remaining gains or losses on qualifying hedges are included in oil and gas sales. During 2005, the Company recognized hedging losses to oil and gas sales on qualifying cash flow hedges totaling $1,554,000 (2004: $1,058,000 loss; 2003: $37,000 gain). Substantially all of the hedge losses were netted against oil and natural gas revenues.

During 2005, the Company determined that a portion of its natural gas swaps no longer qualified for hedge accounting treatment because forecasted production underlying the swaps did not occur or was not expected to occur due to production shut-ins caused by hurricanes in the Gulf of Mexico. As a result, the cash flow hedge designation was removed from those swaps resulting in the recording of $4,615,000 loss (2004: Nil; 2003: Nil) to other income and expense in the statement of income.

At December 31, 2005, the Company had recognized a $6,681,000 liability (2004: asset of $1,406,000) representing the fair value of the swaps at that date of which $6,590,000 of the associated loss has been deferred in equity, net of taxes of $2,603,000 (2004: Nil) and $91,000 of the associated loss has been recorded in operating results (2004: nil). 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 creditworthiness 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.

(d) 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, 2005.

F18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

10. Financing arrangements, liquidity, financial instruments disclosures and significant concentrations (continued)

(d) Concentrations and other credit risk exposures (continued)

The Company’s revenues are related to the production and sales of oil and natural gas in the Gulf of Mexico. During 2005, approximately 59% of the Company’s oil and natural gas sales were made to Bridgeline Gas Marketing, approximately 17% were made to Chevron USA Inc., and approximately 13% were made to Louis Dreyfus Inc. The Company typically sells all of its monthly natural gas production to only one or two purchasers. At December 31, 2005, 36% of the Company’s outstanding accounts receivable were due from Louis Dreyfus Inc.

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. 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.

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 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.

Trade receivables also include amounts due from third-party participants in joint operating arrangements. At December 31, 2005, approximately 50% of the company’s outstanding accounts receivable were due from a third-party participant in joint operating arrangements (2004: 8%).

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 regarding what is reasonable and appropriate, premium cost, 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.

(e) 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
	2004		2005
	(U.S. Dollars, in thousands)

Issued capital
121,389,341 shares issued and outstanding (2004: 119,222,841 shares)
Ordinary shares fully paid	$	130,106	$	130,725

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.

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.

F19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

11. Share capital (continued)

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 and not exercised over a five-year period are not to exceed 6,987,567. As of December 31, 2005, the number of further shares or options which could be issued within the limit was 5,236,067 (2004: 3,349,567).

At December 31, 2005, 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		970,000		1.4		33,000	June 1, 2007
A$0.40		209,000		2.1		133,000	December 1, 2007 — April 1, 2008
A$0.82		100,000		2.0		—	December 31, 2007
A$0.83		15,000		2.9		8,000	November 30, 2008
A$1.00		112,500		3.5		—	June 30, 2009
A$1.25		65,000		3.4		16,500	March 1, 2009 — July 30, 2009
A$1.15		15,000		4.0		3,000	December 31, 2009
A$1.10		15,000		4.4		—	June 1, 2010
A$1.40		250,000		4.8		—	October 20, 2010

A$0.30 — A$1.40		1,751,500		2.3		193,500

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, 2005, 280,000 additional options were granted to employees; 2,166,500 options were exercised and converted to ordinary shares. During 2005, the Company recorded $88,000 of compensation expense related to the option plan (2004: $83,000; 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 2.3 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, 2005, the balance of unearned stock compensation expense to be recorded in future periods was $76,000.


Outstanding options:
	Number of			Weighted
	outstanding			average
	options			exercise price

As at December 31, 2002		3,628,000			A$0.30
Granted		450,000			A$0.58
Forfeited		(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
Forfeited		(15,000	)		A$0.40

As at December 31, 2004		3,638,000			A$0.38
Granted		280,000			A$1.37
Exercised		(2,166,500	)		A$0.33

As at December 31, 2005		1,751,500			A$0.60


Exercisable at December 31, 2005		193,500			A$0.48
Exercisable at December 31, 2004		1,333,000			A$0.34

F20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

12. Shareholders’ equity (deficiency)


	Year ended
	December 31			December 31			December 31
	2003			2004			2005
(Unless stated otherwise, U.S. dollars, in thousands)


Issued capital	$	120,701		$	130,106		$	130,725
Accumulated other comprehensive income (loss)		(2,611	)		(1,964	)		(7,206	)
Accumulated deficit		(94,977	)		(77,243	)		(69,256	)

Total shareholders’ equity	$	23,203		$	50,899		$	54,263


Movements during the financial period

Issued capital (number of shares)
Balance at the beginning of the financial period		105,736,041			105,736,041			119,222,841
Shares issued for cash pursuant to placement		—			12,846,800			—
Shares issued from exercise of options under Employee Option Plan		—			640,000			2,166,500

Balance at the end of the financial period		105,736,041			119,222,841			121,389,341


Issued capital
Balance at the beginning of the financial period	$	120,701		$	120,791		$	130,106
Shares issued for cash pursuant to placement		—			9,064			—
Shares issued from exercise of options under Employee Option Plan		—			168			531
Employee stock compensation expense		90			83			88

Balance at the end of the financial period	$	120,791		$	130,106		$	130,725


Accumulated deficit
Balance at the beginning of the financial period	$	(108,077	)	$	(94,977	)	$	(77,243	)
Net income		13,100			17,734			7,987

Balance at the end of the financial period	$	(94,977	)	$	(77,243	)	$	(69,256	)


Accumulated other comprehensive income (loss)
Unrealized loss on available-for-sale securities
Balance at the beginning of the financial period	$	(16	)	$	(16	)	$	(16	)
Loss on available-for-sale securities reclassified to earnings		—			—			16

Balance at the end of the financial period	$	(16	)	$	(16	)	$	—


Foreign currency translation adjustment
Balance at the beginning of the financial period	$	(2,360	)	$	(2,386	)	$	(2,799	)
Current period change		(26	)		(413	)		(123	)

Balance at the end of the financial period	$	(2,386	)	$	(2,799	)	$	(2,922	)


Unrealized gain (loss) on cash flow hedges
Balance at the beginning of the financial period	$	—			(209	)		851
Net change in fair value of cash flow hedges (net of tax)		(209	)		1,060			(5,135	)

Balance at the end of the financial period	$	(209	)	$	851		$	(4,284	)



Balance at the end of the financial period	$	(2,611	)	$	(1,964	)	$	(7,206	)

F21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

13. Commitments and contingent liabilities

(a) Contingent liabilities

As at December 31, 2005, the estimated maximum contingent liability of the Company 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 $99,000 (2004: $105,000).

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.

In December 2005, the Company commenced a new four-well drilling programme at Main Pass 19/18 from the Main Pass 19 platform. All four wells were successful and have met pre-drill expectations. Three of the four wells have been completed and brought into production. Completion of the Main Pass 18 G-6 well has been halted subject to the resolution of a dispute with a joint operating arrangement participant over the use of Main Pass 19 facilities. Legal action has been initiated against the Company which has resulted in the granting of a preliminary injunction to prevent production of the G-6 well from the Main Pass 19 platform. The Company believes that the suit is without merit and will vigorously defend its position. The Company believes that the ultimate outcome of this matter may increase the cost of the programme but will not have a material adverse effect on our future results of operations or business.

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 Company.

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, 2005 the Company was contingently liable for $5,575,000 of surety bonds (2004: $3,875,000) issued through a surety company to secure those obligations to the authorities. $2,625,000 of these bonds (2004: $2,625,000) were collateralized by letters of credit.

From time to time, PEI must secure obligations to counterparties used for hedging activities. At December 31, 2005 letters of credit totaling $3,375,000 and cash margin deposit of $2,059,000 secure PEI’s obligations to the hedging counterparties (2004: Nil).

(b) Lease commitments

Until it begins exploration or production on a lease, 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-cancellable 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, 2003, 2004 and 2005 was $490,000, $554,000 and $679,000 respectively.

F22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

13. Commitments and contingent liabilities (continued)

The following table presents the remaining aggregate lease commitments as of December 31, 2005 under operating leases, including Gulf of Mexico properties, having initial non-cancellable terms in excess of one year:


	Year ended
(U.S. dollars, in thousands)	December 31

2006	$	624
2007		588
2008		464
2009		440
2010		162

	$	2,278

(c) Exploration commitments

In addition to the contractual cash obligations listed above, the Company has committed to expending approximately $8,901,000 in total during 2006 for exploration within the U.S. and China in respect of its joint operating arrangement commitments.

(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. The Company is under no legal obligation to make contributions in excess of those specified in Superannuation Industry (Supervision) legislation. During the years ended December 31, 2003, 2004 and 2005, superannuation contributions by the Company were $29,000, $28,000 and $20,000 respectively.

U.S. based employees are eligible to participate in a voluntary savings plan under Section 401(k) of the U.S. tax code (“401(k) plan”). As of January 1, 2005 the Company provides matching contributions to those employees that participate. The matching contributions recognised as an expense was $54,000 for the year ended December 31, 2005 (2004: Nil; 2003: Nil).

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 6¹/2 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 the years ended December 31, 2003, 2004 and 2005 the Company recorded compensation expense of $862,000, $973,000 and $421,000 respectively.

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 and 2005, the Company recorded no expense for the directors’ retirement benefit (2003: $98,000). The total amount accrued for director retirement is $228,000.

F23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

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 U.S. GAAP.

Other than as set out below, there are no significant tangible assets for the China and USA segments.


U.S. dollars, thousands	China									USA									Reconciling items									Consolidated

	2003			2004			2005			2003			2004			2005			2003			2004			2005			2003			2004			2005


Oil & gas sales (net of royalties incurred)		—			—			—			23,270			32,575			45,130			—			—			—			23,270			32,575			45,130
Oil & gas royalties earned		—			—			—			1,949			223			332			—			—			—			1,949			223			332

Revenue from customers		—			—			—			25,219			32,798			45,462			—			—			—			25,219			32,798			45,462

Depreciation, depletion, amortization and rehabilitation		—			—			—			6,553			12,335			15,571			21			26			26			6,574			12,361			15,597

Dry hole and abandonment costs		—			1,132			—			—			2,987			5,290			—			—			—			—			4,119			5,290

Impairment expense		—			—			—			38			201			—			—			—			—			38			201			—

Interest income		—			—			—			43			37			295			99			274			98			142			311			393

Interest expense		—			—			—			(10	)		(32	)		(23	)		—			—			—			(10	)		(32	)		(23	)

Income before income tax		(302	)		(1,373	)		(358	)		14,001			10,541			9,419			(1,091	)		(1,241	)		(1,672	)		12,608			7,927			7,389


Cash		—			—			—			3,983			6,916			8,372			8,479			2,602			1,766			12,462			9,518			10,138

Proved and unproved oil and gas properties		981			1,370			2,064			18,176			32,172			46,750			—			—			—			19,157			33,542			48,814

Expenditure for additions to long lived assets		856			1,715			1,052			12,515			26,217			30,681			1			25			3			13,372			27,957			31,736

F24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

15. Related party disclosures

Directors

The names of persons who were directors of the Company during the year ended December 31, 2005 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.

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 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 the year by this company was $603,000 (2004: $440,000; 2003: $530,000).

16. Supplemental disclosures of cash flow information


			Year ended
	December 31		December 31		December 31
(U.S. dollars, in thousands)	2003		2004		2005


Cash paid during the period for:
Interest	$	10	$	32	$	23
Income taxes paid		250		—		200

Non-cash items:
Insurance premiums financed with short-term debt	$	730	$	1,754	$	—

17. Events subsequent to balance sheet date

On March 3, 2006, Petsec Energy Ltd issued 15,000,000 shares at A$2.00 per share to raise a net A$29,250,000 (issue costs were A$750,000), or approximately US$20,928,000, to assist in the funding of an accelerated exploration and development program in 2006. The shares were issued in a private placement under Part 6D.2 of the Australian Corporations Act 2001 (“Act”).

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 2005 and 2004 were based on studies performed by Ryder Scott Company L.P.

F25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

18. Supplementary oil and gas disclosures — unaudited (continued)

No major discovery or other favourable or adverse event subsequent to December 31, 2005 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

Estimated net quantities of oil and 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, 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
Revisions of previous estimates		(25	)		4,769
Extensions, discoveries and other additions		130			7,216
Production		(20	)		(6,335	)


December 31, 2005		148			17,919

Proved developed reserves :
December 31, 2003		32			3,725
December 31, 2004		63			12,269
December 31, 2005		108			15,901

The following represents additional information on individually significant properties (volumes in MMcfe):


	Net Proved					Extensions,					Net Proved
	Reserves At		Revisions of			Discoveries, and					Reserves At
Field Name	December 31, 2002		Previous Estimates			Other Additions		Production			December 31, 2003

West Cameron 352/343 (1)		7,312		(1,315	)		1,693		(4,160	)		3,530
Vermilion 258/244/259 (2)		—		—			7,057		—			7,057


	Net Proved				Extensions,					Net Proved
	Reserves At		Revisions of		Discoveries, and					Reserves At
Field Name	December 31, 2003		Previous Estimates		Other Additions		Production			December 31, 2004

West Cameron 352/343		3,530		1,852		—		(3,279	)		2,103
Vermilion 258/244/259 (3)		7,057		3,784		1,683		(2,370	)		10,154


	Net Proved					Extensions,					Net Proved
	Reserves At		Revisions of			Discoveries, and					Reserves At
Field Name	December 31, 2004		Previous Estimates			Other Additions		Production			December 31, 2005

West Cameron 352/343		2,103		(232	)		—		(993	)		878
Vermilion 258/244/259		10,154		4,984			—		(5,421	)		9,718
Main Pass 19 (4)		—		—			7,994		—			7,994


(1)		During the third quarter of 2003, the Company drilled two additional successful wells at West Cameron 352/343 in the Gulf of Mexico.

(2)		During fourth quarter of 2003, the Company drilled a successful well at Vermilion 258 in the Gulf of Mexico. The Company installed a platform and pipeline and completed the well in 2004.

(3)		During the first quarter of 2004, the Company drilled an additional successful well at Vermilion 258. During the fourth quarter of 2004, the Company drilled two additional wells at Vermilion 258/244/259.

(4)		During the second quarter of 2005, the Company drilled three successful wells on the Main Pass 19 lease in the Gulf of Mexico. In fourth quarter of 2005, a fourth well made a discovery on the Main Pass 19 lease. Petsec owns a 55% working interest in the four Main Pass 19 wells.

F26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

18. Supplementary oil and gas disclosures — unaudited (continued)

Capitalized costs of natural gas and oil properties


	December 31,			December 31,			December 31,
	2003			2004			2005
	(U.S. dollars, in thousands)


Capitalised costs for oil and gas producing activities
consist of the following:
Proved properties	$	24,036		$	45,827		$	74,373
Unproved properties		1,602			6,412			8,508

Total capitalised costs		25,638			52,239			82,881
Accumulated depletion, depreciation and amortization		(6,481	)		(18,697	)		(34,067	)


Net capitalised costs	$	19,157		$	33,542		$	48,814

Costs incurred for oil and natural gas property acquisition, exploration and development activities


			Year ended
	December 31,		December 31,		December 31,
	2003		2004		2005
	(U.S. dollars, in thousands)

Costs incurred for oil and gas property acquisition, exploration and development activities were as follows:
Lease acquisition	$	519	$	3,973	$	2,191
Exploration		6,586		11,943		19,710
Development		8,987		15,898		20,117

Total costs incurred	$	16,092	$	31,814	$	42,018

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 Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% annual discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and 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.

F27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Petsec Energy Ltd and subsidiaries

18. Supplementary oil and gas disclosures — unaudited (continued)

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was as follows:


				Year ended
	December 31			December 31			December 31
	2003			2004			2005
	(U.S. Dollars, in thousands)


Future cash inflows	$	65,612		$	78,599		$	183,194
Less: Future production costs		(7,802	)		(6,605	)		(19,588	)
Future development costs		(13,283	)		(7,862	)		(17,961	)
Future income tax expense		—			—			(29,884	)

Future net cash flows after income taxes		44,527			64,132			115,761
Less: 10% annual discount for estimated timing of cash flows		(9,032	)		(6,240	)		(16,284	)

Standardized measure of discounted future net cash flows	$	35,495		$	57,892		$	99,477


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		$	57,892
Sales and transfers of oil and gas produced, net of production costs		(23,662	)		(32,080	)		(44,559	)
Changes in prices and production costs		7,982			1,353			13,488
Extensions, discoveries and improved recoveries net of future productions and development costs		25,978			19,625			50,873
Development costs incurred during the period		3,293			12,258			7,202
Changes in estimated development costs		(1,906	)		(3,561	)		(5,967	)
Revisions of previous quantity estimates		(5,207	)		14,982			33,480
Net change in income taxes		—			—			(22,623	)
Accretion of discount		1,780			2,953			3,730
Changes in timing and other		1,081			6,867			5,961

Net increase		9,339			22,397			41,585

End of the period	$	35,495		$	57,892		$	99,477

The computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31, 2005 was based on average natural gas prices of approximately $9.72 per Mcf and on average liquids of approximately $61.47 per barrel, before hedging effects.

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 (the Company) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. 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 the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

KPMG

May 16, 2006
Sydney, Australia

F29

EXHIBIT INDEX


1.1		Constitution of the Company, incorporated herein by reference to Exhibit 1.1 to Form 20-F for the Company for the year ended December 31, 2004

4.1		Form of employment contract agreement for Australian-based executives, incorporated herein by reference to Exhibit 4.1 to Form 20-F for the Company for the year ended December 31, 2004.

4.2		Form of employment contract agreement for U.S.-based executives, incorporated herein by reference to Exhibit 4.2 to Form 20-F for the Company for the year ended December 31, 2004.

8.1		Subsidiaries of the Company

11.1		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.

12.1		Certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

12.2		Certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

13.1		Certification of CEO pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

13.2		Certification of CFO pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

15.1		Consent of Independent Registered Public Accounting Firm.

15.2		Consent of Independent Petroleum Engineers.

Petsec Energy Inactive 20-F/A2005 FY Annual report (foreign) (amended)