Esso Australia Resources Pty Ltd v The Commissioner of Taxation
[2011] FCA 360
•13 April 2011
FEDERAL COURT OF AUSTRALIA
Esso Australia Resources Pty Ltd v The Commissioner of Taxation
[2011] FCA 360
Citation: Esso Australia Resources Pty Ltd v The Commissioner of Taxation [2011] FCA 360 Parties: ESSO AUSTRALIA RESOURCES PTY LTD v THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA File number(s): VID 1024 of 2004, VID 1025 of 2004
VID 1026 of 2004, VID 1027 of 2004
VID 1028 of 2004, VID 1029 of 2004
VID 1030 of 2004, VID 1031 of 2004
VID 1032 of 2004, VID 1033 of 2004
VID 1034 of 2004, VID 1035 of 2004
VID 1312 of 2004, VID 1313 of 2004Parties: BHP BILLITON PETROLEUM (BASS STRAIT) PTY LTD v THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA File number(s): VID 1036 of 2004, VID 1037 of 2004
VID 1038 of 2004, VID 1039 of 2004
VID 1040 of 2004, VID 1041 of 2004
VID 1042 of 2004, VID 1043 of 2004
VID 1044 of 2004, VID 1045 of 2004
VID 1047 of 2004, VID 1120 of 2007
VID 1121 of 2007, VID 1122 of 2007
VID 1123 of 2007, VID 1124 of 2007
VID 1125 of 2007, VID 1126 of 2007
VID 1127 of 2007, VID 1128 of 2007
VID 1129 of 2007, VID 1130 of 2007
VID 1131 of 2007Judge: MIDDLETON J Date of judgment: 13 April 2011 Catchwords: TAXATION – petroleum resource rent tax – taxable profit - assessable petroleum receipts –taxing points – text of provision – content and scheme of Act – legislative history – extrinsic materials
EVIDENCE – use of extrinsic material – requirement to prove under Evidence Act – expert evidence
STATUTORY INTERPRETATION – use of extrinsic material – importance of definitions in context
Legislation: Acts Interpretation Act 1901 (Cth)
Evidence Act 1995 (Cth)
Petroleum (Submerged Lands) Act 1967 (Cth)
Petroleum Resource Rent Tax Act 1987 (Cth)
Petroleum Resource Rent Tax Assessment Act 1987 (Cth)
Petroleum Resource Rent Legislation Amendment Act 1991 (Cth)
Petroleum Revenue Act 1985 (Cth)
Taxation Administration Act 1953 (Cth)
Taxation Laws Amendment Act (No 6) 2001 (Cth)Cases cited: Alcan (NT) Alumina Pty Ltd v Commissioner of Territory Revenue (Northern Territory) (2009) 239 CLR 27
Alliance Petroleum Australia NL v The Australian Gas Light Company
Archibald Howie Pty Ltd v Commissioner of Stamp Duties (NSW) (1948) 77 CLR 143
BHP Billiton Petroleum (Bass Strait) Pty Ltd v FCT (2002) 126 FCR 119
Black-Clawson International Ltd v Papierwerke Waldhof-Aschaffenburg AG [1975] AC 591
C of T v Australian Guarantee Corporation Limited (1984) 2 FCR 483
Chief Commissioner of State Revenue (NSW) v Dick Smith Electronics Holdings Pty Ltd (2005) 221 CLR 496
Coles Myer Finance Ltd v FCT (1993) 176 CLR 640
Commercial Union Assurance Co of Australia Ltd v FCT (1977) 77 ATC 4
Cooper Brookes (Wollongong) Pty Ltd v FCT (1981) 147 CLR 297
Diamond Shamrock Exploration Co v Hodel (1988) 853 F.2d 1159 (5th Cir. 1988)
Esso Australia Resources Ltd v FCT (1998) 83 FCR 511
Esso Australia Resources Pty Ltd v Commissioner of Taxation [2009] FCA 272
Gibb v FCT (1966) 118 CLR 628
Kelly v R (2004) 205 ALR 274
Network Ten Pty Ltd v TCN Channel Nine Pty Ltd (2004) 218 CLR 273
RACV Insurance Pty Ltd v FCT [1975] VR 1
Singhv Commonwealth of Australia (2004) 209 ALR 355
St George Bank Limited v Commissioner of Taxation [2009] FCAFC 62
The Owners of the Ship “Shin Kobe Maru” v Empire Shipping Co Inc (1994) 181 CLR 404Trade Practices Commission v Australia Meat Holdings Pty Ltd (1988) 83 ALR 299
Wacal Developments Pty Ltd v Realty Developments Pty Ltd (1978) 140 CLR 503
Woodside Energy Ltd v FCT (2009) 174 FCR 91Date of hearing: 16, 17, 18, 23, 24, 23, 25, 26, 29, 30 March 2010, 14 and 15 April 2010 Place: Melbourne Division: GENERAL DIVISION Category: Catchwords Number of paragraphs: 516 Counsel for Esso Australia Resources Pty Ltd: Mr JW De Wijn QC with Mr SH Steward SC, Mr MT Flynn and Mr AT Broadfoot Solicitor for Esso Australia Resources Pty Ltd: Allens Arthur Robinson Counsel for BHP Billiton Petroleum (Bass Strait) Pty Ltd: Mr DJ O’Callaghan SC with Mr GP Harris Solicitor for BHP Billiton Petroleum (Bass Strait) Pty Ltd: Allens Arthur Robinson Counsel for The Commissioner of Taxation: Mr GJ Davies QC with Mr H Foxcroft SC, Mr SJ Sharpley and Mr AD Pound Solicitor for The Commissioner of Taxation: Australian Government Solicitor
IN THE FEDERAL COURT OF AUSTRALIA
VICTORIA DISTRICT REGISTRY
GENERAL DIVISION
VID 1024 of 2004
VID 1025 of 2004
VID 1026 of 2004
VID 1027 of 2004
VID 1028 of 2004
VID 1029 of 2004
VID 1030 of 2004
VID 1031 of 2004
VID 1032 of 2004
VID 1033 of 2004
VID 1034 of 2004
VID 1035 of 2004
VID 1312 of 2004
VID 1313 of 2004
BETWEEN: ESSO AUSTRALIA RESOURCES PTY LTD
ApplicantAND: THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA
Respondent
JUDGE:
MIDDLETON J
DATE OF ORDER:
13 APRIL 2011
WHERE MADE:
MELBOURNE
THE COURT ORDERS THAT:
1.The parties confer and thereafter by 4.00 pm on 29 April 2011 file minutes of orders (including as to costs), and in the event of disagreement, file and serve written submissions as to the contentions of the parties.
2.Any further directions necessary for the final determination of the proceedings be adjourned to a date to be fixed.
Note:Settlement and entry of orders is dealt with in Order 36 of the Federal Court Rules.
The text of entered orders can be located using Federal Law Search on the Court’s website.
IN THE FEDERAL COURT OF AUSTRALIA
VICTORIA DISTRICT REGISTRY
GENERAL DIVISION
VID 1036 of 2004
VID 1037 of 2004
VID 1038 of 2004
VID 1039 of 2004
VID 1040 of 2004
VID 1041 of 2004
VID 1042 of 2004
VID 1043 of 2004
VID 1044 of 2004
VID 1045 of 2004
VID 1047 of 2004
VID 1120 of 2007
VID 1121 of 2007
VID 1122 of 2007
VID 1123 of 2007
VID 1124 of 2007
VID 1125 of 2007
VID 1126 of 2007
VID 1127 of 2007
VID 1128 of 2007
VID 1129 of 2007
VID 1130 of 2007
VID 1131 of 2007
BETWEEN: BHP BILLITON PETROLEUM (BASS STRAIT) PTY LTD
ApplicantAND: THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA
Respondent
JUDGE:
MIDDLETON J
DATE OF ORDER:
13 APRIL 2011
WHERE MADE:
MELBOURNE
THE COURT ORDERS THAT:
1.The parties confer and thereafter by 4.00 pm on 29 April 2011 file minutes of orders (including as to costs), and in the event of disagreement, file and serve written submissions as to the contentions of the parties.
2.Any further directions necessary for the final determination of the proceedings be adjourned to a date to be fixed.
Note:Settlement and entry of orders is dealt with in Order 36 of the Federal Court Rules.
The text of entered orders can be located using Federal Law Search on the Court’s website.
IN THE FEDERAL COURT OF AUSTRALIA
VICTORIA DISTRICT REGISTRY
GENERAL DIVISION
VID 1024 of 2004
VID 1025 of 2004
VID 1026 of 2004
VID 1027 of 2004
VID 1028 of 2004
VID 1029 of 2004
VID 1030 of 2004
VID 1031 of 2004
VID 1032 of 2004
VID 1033 of 2004
VID 1034 of 2004
VID 1035 of 2004
VID 1312 of 2004
VID 1313 of 2004
BETWEEN: ESSO AUSTRALIA RESOURCES PTY LTD
ApplicantAND: THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA
Respondent
GENERAL DIVISION
VID 1036 of 2004
VID 1037 of 2004
VID 1038 of 2004
VID 1039 of 2004
VID 1040 of 2004
VID 1041 of 2004
VID 1042 of 2004
VID 1043 of 2004
VID 1044 of 2004
VID 1045 of 2004
VID 1047 of 2004
VID 1120 of 2007
VID 1121 of 2007
VID 1122 of 2007
VID 1123 of 2007
VID 1124 of 2007
VID 1125 of 2007
VID 1126 of 2007
VID 1127 of 2007
VID 1128 of 2007
VID 1129 of 2007
VID 1130 of 2007
VID 1131 of 2007
BETWEEN: BHP BILLITON PETROLEUM (BASS STRAIT) PTY LTD
ApplicantAND: THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA
Respondent
JUDGE:
MIDDLETON J
DATE:
13 APRIL 2011
PLACE:
MELBOURNE
REASONS FOR JUDGMENT
INTRODUCTION
Esso Australia Resources Pty Ltd (‘Esso’) is a co-venturer with BHP Billiton Petroleum (Bass Strait) Pty Ltd (‘BHPBP’) (together, ‘the joint venturers’) in a series of offshore petroleum facilities located in Bass Strait and onshore processing and storage facilities at Longford in Gippsland and Long Island Point (‘the Gippsland facilities’). Esso is the operator of the joint venture.
Both Esso and BHPBP are applicants in various proceedings before the Court. Evidence in the proceedings in which Esso is the applicant has been ordered to be evidence in the proceedings in which BHPBP is an applicant. Evidence in the proceedings in which BHPBP is the applicant has not been ordered to be evidence in the proceedings in which Esso is an applicant. Generally, as was envisaged by procedural orders made by the Court, BHPBP has adopted and relied upon the submissions and evidence made and led by Esso for the purposes of all the proceedings, except to the extent that adaptations became necessary. It is convenient in reference to the applicants to refer to Esso alone and to the submissions and evidence relied upon by Esso, unless the context otherwise requires a reference to BHPBP. Needless to say, my reasoning and conclusions apply to both applicants. No dispute for my current consideration arose concerning the exact amounts of tax liability involved, and I have not burdened these reasons with unnecessary detail as to specific amounts of tax liability which would obviously differ between Esso and BHPBP.
Since 1 July 1990, the Gippsland facilities have been subject to the taxation regime set out in the Petroleum Resource Rent Tax Assessment Act 1987 (Cth) (‘PRRTA Act’). Esso and BHPBP had lodged objections to the Commissioner’s amended assessments of their liability to petroleum resource rent tax (‘PRRT’) in relation to the Gippsland facilities for each of the years ended 30 June 1991 to 30 June 2002. The Commissioner disallowed the objections. Appeals have been instituted under Pt IVC of the Taxation Administration Act 1953 (Cth) (‘TAA’) from the Commissioner’s objection decisions in respect of the each of the tax years for the whole period. Additional grounds of objection have been added in the course of the proceedings.
I am currently concerned with 13 questions set down by order of the Court made on 17 December 2009 for separate hearing and determination pursuant to O 29 r 2 of the Federal Court Rules. Each of the separate questions mainly concern whether certain amounts returned by Esso and BHPBP and assessed by the Commissioner as “assessable petroleum receipts” for the purposes of s 24 of the PRRTA Act should be excised from the “assessable petroleum receipts” returned by Esso and BHPBP in the relevant years.
THE QUESTIONS
It is convenient to refer to the questions set down by reference to the Esso proceedings where Esso is described as the applicant, as the substance of each question is the same in the BHPBP proceedings.
The questions for determination, quoting directly from the Court order of 17 December 2009, are as follows:
A.DEFINITION OF TERMS
(a)applicant’s FASFIC means the Further Amendment Statement of Facts Issues and Contentions filed and served by the applicant on 7 May 2009;
(b)exit of the Longford Plant means the place alleged by the applicant in paragraph 25 of the applicant’s FASFIC;
(c)first period means 1 July 1990 to 31 March 2002;
(d)first period Taxing Points alleged by the applicant means the taxing points referred to in the particulars under paragraphs 22(b) and (c) of the applicant’s FASFIC;
(e)PRRTA Act means the Petroleum Resource Rent Tax Assessment Act 1987 (Cth);
(f)second period means 1 April 2002 to 30 June 2002;
(g)second period Taxing Points alleged by the applicant means the taxing points referred to paragraphs 22G and 22I of the applicant’s FASFIC;
(h)whole period means 1 July 1990 to 30 June 2002.
B.SALES GAS – the first period
1.For what period or periods within each of the tax years during the first period and in what quantities in respect of each tax year did any marketable petroleum commodity, in the form of sales gas within the meaning of the PRRTA Act and produced from petroleum recovered from the area or areas to which paragraph (a) of s 24 of the PRRTA Act applies, become an excluded commodity (otherwise than by virtue of being sold or treated or processed or moved for re-injection or destruction or for use in carrying on or providing operations facilities or other things of a kind referred to in s 37, s 38 or s 39 in relation to the petroleum project) for the purposes of s 24(c) of the PRRTA Act at each of the first period Taxing Points alleged by the applicant?
2.If any quantity of sales gas referred to in question 1 became an excluded commodity, as referred to in question 1, what amounts in respect of the sale of sales gas included by the applicant as assessable petroleum receipts under the PRRTA Act during the first period as referred to in paragraph 21 of the applicant’s FASFIC were not assessable petroleum receipts under s 24 of the PRRTA Act?
C.SALES GAS – the second period
3.For what period or periods during the second period and in what quantity for the whole of the second period did any marketable petroleum commodity, in the form of sales gas within the meaning of the PRRTA Act and produced from petroleum recovered from the area or areas to which paragraph (a) of s 24(1) of the PRRTA Act applies, become an excluded commodity (otherwise than by virtue of being sold or treated or processed or moved for re-injection or destruction or for use in carrying on or providing operations facilities or other things of a kind referred to in ss 37, 38 or 39 in relation to the petroleum project) for the purposes of s 24(1)(c) or s 24(1)(e) of the PRRTA Act at each of the second period Taxing Points alleged by the applicant?
4.If any quantity of sales gas referred to in question 3 became an excluded commodity, as referred to in question 3, what amounts in respect of the sale of sales gas included by the applicant as assessable petroleum receipts under the PRRTA Act during the second period as referred to in paragraph 21 of the applicant’s FASFIC were not assessable petroleum receipts under s 24(1) of the PRRTA Act?
5.If any quantity of sales gas referred to in question 3 became an excluded commodity as referred to in question 3, does the fact that no regulations under s 24(1)(e) of the PRRTA Act were made during the second period have the consequence that no amount in respect of that quantity of sales gas is to be included in the applicant's assessable petroleum receipts under the PRRTA Act in respect of the second period?
D.LIQUEFIED PETROLEUM GAS
6.For what period or periods within each of the tax years during the whole period and in what quantities in respect of each tax year did any marketable petroleum commodity, in the form of liquefied petroleum gas within the meaning of the PRRTA Act and produced from petroleum recovered from the area or areas to which paragraph (a) of s 24 or s 24(1) of the PRRTA Act applies, become an excluded commodity (otherwise than by virtue of being sold or treated or processed or moved for re-injection or destruction or for use in carrying on or providing operations facilities or other things of a kind referred to in ss 37, 38 or 39 in relation to the petroleum project) –
(a) for the purposes of s 24(c) of the PRRTA Act during the first period; and
(b)for the purposes of s 24(1)(c) during the second period, at the exit of the Longford Plant?
7.If any quantity of sales gas referred to in questions 1 and/or 3 became an excluded commodity as referred to in questions 1 and/or 3, and/or if any quantity of liquefied petroleum gas referred to in question 6 became an excluded commodity, as referred to in question 6, what amounts in respect of the sale of liquefied petroleum gas included by the applicant as assessable petroleum receipts under the PRRTA Act during the whole period as referred to in paragraph 24 and paragraph 26(a) of the applicant’s FASFIC were not assessable petroleum receipts –
(a) under s 24(b) of the PRRTA Act for the first period;
(b) under s 24(1)(b) of the PRRTA Act for the second period?
E.ETHANE and STABILISED CRUDE OIL
8.If any quantity of sales gas referred to in questions 1 and/or 3 became an excluded commodity as referred to in questions 1 and/or 3, and/or if any quantity of liquefied petroleum gas referred to in question 6 became an excluded commodity as referred to in question 6, what amounts in respect of ethane included by the applicant its assessable petroleum receipts during the whole period as referred to in paragraph 24 and paragraph 26(a) of the applicant’s FASFIC were not assessable petroleum receipts under s 24 of the PRRTA Act?
9.If any quantity of sales gas referred to in questions 1 and/or 3 became an excluded commodity as referred to in questions 1 and/or 3, what amounts in respect of stabilised crude oil included by the applicant its assessable petroleum receipts during the whole period as referred to in paragraph 24 of the applicant’s FASFIC were not assessable petroleum receipts under s 24 of the PRRTA Act?
F.GAS USED FOR ELECTRICITY GENERATION
10.What, if any, amounts included by the applicant in its assessable petroleum receipts in respect of the gas used to generate electricity during the whole period, as referred to in paragraph 27(b) of the applicant’s FASFIC, were not assessable petroleum receipts under s 24 of the PRRTA Act?
G.TAKE OR PAY ISSUE
11.Was all or part, and if so how much, of the amount of $11,753,357.87 referred to in paragraph 9 of the applicant’s FASFIC paid to the applicant by the State Electricity Commission of Victoria (‘SECV’) pursuant to clause 7.3 of the SECV Agreement an assessable petroleum receipt of the applicant for the purposes of the PRRTA Act in the year ended 30 June 1997?
12.Should all or part, and if so how much, of the amounts paid by the SECV to the applicant pursuant to clause 7.3 of the SECV Agreement (as set out in the table contained in paragraph 10B of the applicant’s FASFIC on the dates set out in the table) be excised from the assessable petroleum receipts of the applicant for the purposes of the PRRTA Act in each of the years ended 30 June 1991, 30 June 1993, 30 June 1995 and 30 June 1996?
H.MDQ PAYMENTS ISSUE
13.Were all or part, and if so how much, of the amounts received by the applicant from the Gas and Fuel Corporation of Victoria (‘GFC’) pursuant to the Further GFC Agreement (as set out in the table contained in paragraph 15 of the FASFIC) assessable receipts for the purposes of the PRRTA Act in the tax years in which those payments were received?
ANSWERS FOR WHICH THE PARTIES CONTEND
The Commissioner submitted that questions 1, 3 and 6 should be answered ‘none’, making questions 2, 4, 5, 7, 8 and 9 not applicable.
As to the other questions, the Commissioner submitted that the questions should be answered as follows:
Question 10 - The amounts included by Esso in its assessable petroleum receipts in respect of the gas used to generate electricity for sale during the whole period, as referred to in paragraph 27(b) of Esso’s FASFIC, were not assessable petroleum receipts under s 24 of the PRRTA Act to the extent to which the gas so used was obtained during the course of the process of production of sales gas at Longford and was not a marketable petroleum commodity.
Question 11 - The whole of the amount of $11,753,357.87 referred to in paragraph 9 of Esso’s FASFIC paid by the State Electricity Commission of Victoria (‘the SECV’) pursuant to clause 7.3 of the SECV Agreement was an assessable petroleum receipt of Esso for the purposes of the PRRTA Act in the year ended 30 June 1997.
Question 12 - The amounts the subject of Question 12 should be treated as follows:(a)The amounts of $3,550,209.98 and $4,828,584.63 included in Esso’s assessable receipts in the tax years ended 30 June 1991 and 30 June 1993 respectively (as set out in the right hand column of the table in paragraph 46A of the Commissioner’s FASFIC) were assessable petroleum receipts for the purposes of the PRRTA Act in those years.
(b)The amounts of $8,436.00, $1,910,943.62 and $5,673,026.81 included in Esso’s assessable receipts in the tax years ended 30 June 1993, 30 June 1995 and 30 June 1996 respectively (as set out in the right hand column of the table in paragraph 46B of the Commissioner’s FASFIC) were not assessable petroleum receipts for the purposes of the PRRTA Act in those years and should be excised.
(c)The amounts of $4,010,448.18 and $3,581,958.25 received by Esso in the tax years ended 30 June 1992 and 30 June 1994 respectively (as set out in the middle column of the table in paragraph 46B of the Commissioner’s FASFIC and in the consequential adjustments table on page 34 of Esso’s FASIC) should be added back into Esso’s assessable petroleum receipts for the purposes of the PRRTA Act in those years.
Question 13 - The amounts were assessable receipts by reason of s 24(b) of the PRRTA Act in the tax years in which those payments were received.
For Esso (and BHPBP) the position is dependent upon a number of factual and legal conclusions which the Court must reach, particularly as to the various ‘taxing points’ contended for by Esso and BHPBP.
Further, the parties were not able to agree as to the amounts that should be excised from the assessable petroleum receipts should any of Questions 1, 3, 6, 8 or 9 be answered in favour of Esso or BHPBP. In the event that the Court did decide against the answers for which the Commissioner contended, a further hearing in relation to Questions 2, 4, 7, 8 and 9 may then have been necessary to fix the amounts to be excised in light of the Court’s ruling on Questions 1, 3 or 6.
In light of these circumstances, the parties agreed that I should publish my reasons determining factual and legal issues raised by the parties relevant to each of the questions, and thereafter the parties could consider the appropriate minute of order reflecting the Court’s conclusions in each of the proceedings. Whilst I have found in favour of the Commissioner on the principal questions 1, 3 and 6, I still propose to adopt the approach agreed to by the parties to enable them to file with the Court appropriate minutes of orders reflecting the conclusions reached in these reasons and to deal with any other matter consequential upon such conclusions.
OVERVIEW OF THE QUESTIONS FOR DETERMINATION
The 13 preliminary questions involve four principal categories of issues.
The first principal category of issues has been referred to as the ‘taxing point’ issue and concerns whether the amount of Esso’s ‘assessable petroleum receipts’ in respect of:
(i) ‘sales gas’ produced from petroleum recovered from Bass Strait is to be ascertained under s 24(c) of the PRRTA Act by reference to the market value of the gas at identified points on the various Bass Strait offshore production platforms; and
(ii) ‘liquefied petroleum gas’ (‘LPG’) produced from petroleum recovered from Bass Strait, but excluding that produced from already taxed sales gas, is to be ascertained under s 24(c) of the PRRTA Act by reference to the market value of the mixture which satisfies the statutory definition of ‘LPG’ at the exit to Longford.
Esso contended that s 24(c) applies. The Commissioner contended Esso’s assessable petroleum receipts are to be ascertained under s 24(b) of the PRRTA Act by reference to the consideration receivable, less expenses payable, by Esso in relation to the sale of products derived from the gas and sold from the onshore processing facilities situated at Longford and at Long Island Point.
The second principal issue category has been referred to as the ‘MLMDQ issue’. The MLMDQ issue concerns the assessability of payments (‘the MLMDQ payments’) that Esso and BHPBP received from GFC and its successor organisation, Gascor, for agreeing to a variation in their contract with GFC. The variation related to terms of the agreement under which GFC was required to give Esso advance notice of the maximum amount of gas it might require each day.
The third principal category of issue has been referred to as the ‘take or pay issue’. The take or pay issue concerns whether a payment of $11,753,357.87 by Generation Victoria (‘Genvic’), the successor organisation to the SECV, to Esso in January 1997 (‘the 1997 payment’) was an assessable petroleum receipt. Genvic made the payment under a contract for the supply of gas by Esso and BHPBP that required the SECV to pay a minimum amount to the suppliers annually, regardless of the amount of gas it required. If SECV took less gas than a specified amount, it was entitled to apply the excess payment to gas taken in succeeding years under the contract (the contract described this gas as ‘Make Up Gas’). Genvic made the 1997 payment in the final year of the contract, so it was not able to apply the payment to take any Make Up Gas.
If, contrary to Esso’s contention, the 1997 payment was an assessable petroleum receipt, the Court needs to consider a second question, which is whether amounts that Esso returned as assessable petroleum receipts in the 1991, 1993, 1995 and 1996 years were properly returned. Esso returned payments it received from the SECV as assessable petroleum receipts in the year the SECV (or Genvic) took the Make Up Gas to which the receipts related. If the payments it received were properly returnable on a cash received basis, rather than when the SECV took the Make Up Gas, then its assessable petroleum receipts need to be adjusted in the 1991, 1993, 1995 and 1996 years. The effect of the adjustments would be to reduce the total amounts returned as assessable petroleum receipts, because some of the amounts that Esso has returned relate to payments received before the introduction of PRRT.
The fourth principal category of issue involves the sale by Esso of surplus electricity generated at Longford. This issue concerns whether the market value of such proportion of gas which is attributable to the production of surplus electricity is an assessable petroleum receipt under s 24(c) of the PRRTA Act.
There are various subsidiary issues within the four principal issue categories identified above which will need to be considered.
THE GIPPSLAND FACILITIES
Most of the facts as to the operations in the Gippsland facilities are not in contention. I will address any relevant criticisms of any witness later in these reasons when dealing with their evidence in relation to specific issues. No issue of credit arose in relation to any witness, although each party sought to characterise the evidence led by Esso in different ways or to place different emphasis on the evidence.
Mr Heath, a director of Esso and chemical engineer, who over many years has gained a detailed knowledge of and experience with the process and operations in the Gippsland facilities, gave extensive evidence as to various facilities the subject of these proceedings. I accept Mr Heath’s evidence as to the primary facts. Of course, to the extent Mr Heath uses or refers to terms that are to be interpreted as a matter of statutory construction, I treat his expressions as no more than those of a chemical engineer familiar with the processing and operations he described in his evidence. In describing the Gippsland facilities below, I make these findings of fact based upon Mr Heath’s evidence and the documentation introduced into evidence which describes the facilities and processes undertaken both offshore and onshore.
The Commissioner referred in its submissions to the ‘Esso Manual’, a document which included information on the formation, receiving and processing of Bass Strait petroleum. Mr Heath agreed with the contents of the Esso Manual. I do not consider there to be any inconsistency between the Esso Manual and Mr Heath’s other evidence and I propose to proceed on that basis.
Esso and BHPBP are joint venturers. Between them, the joint venturers hold a number of production licences for Bass Strait which, for the purposes of the PRRTA Act, are treated as giving rise to a single petroleum project. Esso holds a 50% share in the joint venture and operates the project on behalf of the joint venturers pursuant to an agreement between them.
Esso recovers petroleum from wells on a series of offshore platforms in Bass Strait. Esso conducts an integrated process involving the platforms, the Longford Gas Processing and Crude Stabilisation Plant (‘Longford’ or ‘the Longford Plant’) and Long Island Point Fractionation Plant (‘LIP’), separating the recovered petroleum into a number of hydrocarbon products for commercial exploitation. The process to which the petroleum recovered from Bass Strait is subjected to produce these products is one of separating the petroleum into its constituent hydrocarbons and removing impurities (such as water, hydrogen sulphide and other non-hydrocarbon substances).
Esso’s platforms, pipelines and processing facilities are designed to produce commercially saleable oil and gas products from the raw petroleum recovered from petroleum pools beneath the seabed in Bass Strait. The process is one of successive stages of separation and filtration commencing with the raw petroleum and finishing with the production of the commercially saleable products.
In summary, the process is integrated and continuous, involving the following steps:
(a)The use of wells on the Bass Strait platforms to recover liquid and gaseous raw petroleum from the petroleum pools.
(b)Some separation of the recovered petroleum on the platforms into substantially liquid and substantially gaseous streams, which is then piped to shore. In some cases, these streams are recombined prior to being piped to shore.
(c)Further separation and filtering of the substantially gaseous petroleum stream in the gas plants at Longford so as to produce the commercial product ‘sales gas’ and a raw LPG stream (condensate) of propane, butane and ethane. Some liquid petroleum extracted from this stream is added to the stabilised crude oil stream from the Longford. The sales gas is sold at the exit of the Longford Plant.
(d)Further separation and filtering of the substantially liquid petroleum stream in the Longford Plant so as to produce the commercial product stabilised crude oil and to remove the raw LPG and gas that is piped across to the gas plants.
(e)Transport of the raw LPG and stabilised crude oil by pipeline to the LIP. At that plant the stabilised crude oil is stored for sale while the raw LPG stream is further separated (fractionated) into the commercial products ethane, propane and butane for sale. Ethane is not sold at Long Island Point; it is transported by pipeline to Altona where it is sold.
Hydrocarbons are molecules consisting of combinations of carbon and hydrogen atoms. All hydrocarbon molecules take the chemical form CnH2n+2 where C refers to carbon and H refers to hydrogen. For present purposes the following hydrocarbon molecules are relevant, listed in order of increasing weight:
Name
Composition
Abbreviation
Boiling Point at 1 atm pressure (°C)
Phase at 15°C and 1 atm pressure
Methane
CH4
C1
-161
Gas
Ethane
C2H6
C2
-88
Gas
Propane
C3H8
C3
-42
Gas
Butane
C4H10
C4
-12 to -1
Gas
Pentane
C5H12
C5
27-36
Liquid
Hexane and heavier hydrocarbons
C6H14+
C6+
49+
Liquid
The row “hexane and heavier hydrocarbons” is a reference to the range of heavier liquid hydrocarbons up to approximately C20. A reference to “lighter hydrocarbons” is a reference to methane, ethane, propane and butane (that is, C1-C4). A reference to “heavier hydrocarbons” is a reference to pentane and heavier hydrocarbons (that is, C5+).
Boiling point is the temperature at which the hydrocarbon changes phase from liquid to gas. Phase is a reference to whether the substance is a solid, liquid or a gas. The heavier a hydrocarbon is the higher its boiling point. The reference in the table above to boiling point at “1 atm pressure” means the boiling point at one atmosphere of pressure, that is, the air pressure at sea level.
Boiling points are dependent on pressure: increasing pressure increases the boiling point and decreasing pressure decreases the boiling point. So a hydrocarbon that is a gas at a particular pressure can be converted to a liquid at the same temperature by increasing the pressure sufficiently. Conversely, a hydrocarbon that is a liquid at a particular pressure can be converted to a gas by reducing the pressure at the same temperature.
The fact that different hydrocarbons have different boiling points is important as it allows temperature and pressure variations to be used to separate different hydrocarbons from a stream of mixed hydrocarbons. Another technique used to separate gaseous and liquid hydrocarbons is the difference in weights.
Hydrocarbons are found in naturally occurring underground deposits. In Bass Strait these deposits are found deep beneath the sea floor in discrete reservoirs or pools of petroleum. The depth of the pools ranges from about 1,200 to 2,500 metres below sea level. These deposits occur in places where the configuration of the underground geology produces traps – formations of rock that confine the petroleum underground and prevent it seeping upwards to escape at the surface.
The hydrocarbons are formed over very long periods of time as a combination of geologic and chemical action on deposits of ancient decaying plant and animal material. Bass Strait contains a large number of these pools of raw petroleum. The pools are not actual spaces in the rock rather they are areas where porous rock contains petroleum.
Some pools contain mostly heavier hydrocarbons and the hydrocarbons will be in a liquid phase, others contain mostly lighter hydrocarbons and the hydrocarbons will be in a gaseous phase. The liquid hydrocarbon pools consist predominantly of the heavier hydrocarbon compounds in the range C5 to C15 (using the table above) while the gaseous hydrocarbon pools contain predominantly the lighter hydrocarbons C1 to C4. However, all pools will contain at least some amount of all hydrocarbons in the range C1 to approximately C20. Each hydrocarbon pool contains a unique mixture of hydrocarbons. Depending on the temperature and pressure in the pool, in the gaseous pools some of the heavier liquid hydrocarbons will have evaporated into the gaseous mix while in the liquid pools the lighter gaseous hydrocarbons will have dissolved into the liquid mix. The quantity of lighter gaseous hydrocarbons found in the liquid pools in the Bass Strait reservoirs is considerable.
Aside from hydrocarbons the pools also contain significant quantities of non-hydrocarbon substances. These can include water, carbon dioxide, nitrogen and hydrogen sulphide. The mixture of hydrocarbons and non-hydrocarbons found in these pools is known as petroleum. Liquid petroleum is also known as ‘oil’, ‘crude oil’ or ‘unstabilised oil’. Gaseous petroleum is also known as ‘gas’, ‘raw gas’ or ‘unprocessed gas’.
The pools of petroleum are usually found in groups of pools known as a ‘field’. These pools can be found either laterally distributed or in vertical layers or both. A field that contains mostly gaseous petroleum is known as a ‘gas field’. A field that contains mostly liquid petroleum is known as an ‘oil field’. A gas field may also contain pools of liquid petroleum and vice versa. Each pool has a unique composition.
Also, a particular pool may contain both gaseous and liquid petroleum. In such cases the gaseous petroleum will typically sit above the liquid petroleum in what is known as a ‘gas cap’. If petroleum is recovered from a point near the boundary between the gas and liquid layers ‘coning’ can occur. This refers to the phenomenon where in an oil well gas from the adjacent gas layer is drawn down to mix with the liquid petroleum being recovered, such that a mix of liquid and gaseous petroleum will be recovered. The same phenomenon can occur in gas wells with liquid petroleum being drawn up to mix with the gaseous petroleum being recovered.
The petroleum pools in Bass Strait are under great pressure due to the weight of the ocean and the rock layers above them bearing down. There is also an aquifer of high pressure subsurface water beneath each petroleum pool, also within the porous rock. As hydrocarbons are lighter than water they will float above the water layer. The presence of this water aids in the recovery of petroleum from oil fields.
I have already alluded to the fact that the purpose of Esso’s operations and facilities in Bass Strait and on land is to recover the petroleum from these pools and then separate the petroleum into its constituent hydrocarbons while filtering out unwanted substances such as non-hydrocarbon compounds and water so as to produce five commercial products for sale.
Mr Heath encapsulated this in his principal affidavit evidence of 22 December 2007 describing the Gippsland facilities:
[38] The objective of the Gippsland Facilities during the relevant period, and to date, was to recover petroleum from the Bass Strait reservoirs and to process it so as to yield the five hydrocarbon products in an efficient and safe manner. Also, the Longford facilities have been designed so that hydrocarbons predominantly in a liquid phase (predominantly heavier hydrocarbons) arrive at the CSP, and hydrocarbons predominantly in a gas phase (predominantly lighter hydrocarbons) arrive at the Gas Plants. While there are levels of tolerance in the design of each of the plants to allow for some level of liquids, including water, to be received at the Gas Plants in the gas pipelines, and some level of gases and free water to be received at the CSP in the liquids pipelines, the plants could not operate efficiently if these tolerances were exceeded.
[39] In broad terms, the process of obtaining Natural Gas, Commercial Ethane, Commercial Propane, Commercial Butane and Stabilised Crude Oil for sale from the petroleum recovered from the Bass Strait reservoirs involves separating the petroleum into products of consistent molecular weight and removing impurities such as water and sulphur. This process occurs in stages. At no single stage is one able to achieve perfect separation of molecules into groups having sufficiently consistent weight but gradually through a series of processes one is able to achieve the necessary specifications for the five products.
The five commercial products referred to by Mr Heath and which Esso produces from the petroleum, and their average compositions are:
Product
Composition
Sales Gas
About 85% methane with small amounts of ethane, nitrogen and carbon dioxide
Commercial Ethane
About 99% ethane
Commercial Propane
About 97% propane with small amounts of ethane and butane
Commercial Butane
About 97% butane with small amounts of propane
Stabilised Crude Oil
About 97% pentane and heavier hydrocarbons
In addition to hydrocarbon content the commercial products are produced to comply with buyers’ specifications.
Because their composition is biased towards the lighter hydrocarbons the gaseous hydrocarbon pools will yield a greater proportion of sales gas, ethane, propane and butane, while the liquid hydrocarbon pools will yield a greater proportion of stabilised crude oil. However, because the production facilities at Longford are interconnected, such that light hydrocarbons are sent from the Crude Stabilisation Plant to the gas plants and heavy hydrocarbons from the gas plants to the Crude Stabilisation Plant, each of the commercial products is able to be produced from the totality of the petroleum recovered on all of the platforms.
Esso produces the commercial products entirely by separating and filtering the hydrocarbons found in the petroleum. Esso’s production processes do not involve any chemical reactions; that is, none of the hydrocarbon molecules found in the petroleum are either broken down to form smaller molecules (as can happen in an oil refinery – a process known as ‘cracking’) or combined with other hydrocarbon molecules or chemical compounds to form larger compounds. All of the molecular constituents of the commercial products are present in the petroleum in the same chemical form. Esso processes this petroleum by removing unwanted substances (water and other non-hydrocarbon substances) and using a succession of separation and filtering processes to separate the petroleum into its constituent hydrocarbons which eventually culminates in the commercial products.
Esso’s facilities and operations for the production of the five commercial products from petroleum consist of five stages:
1.the platforms in Bass Strait;
2.the pipelines linking the Bass Strait platforms to the Longford Plant;
3.the Longford Plant;
4.the pipelines linking the Longford Plant to the LIP; and
5.the LIP.
In addition, there are associated facilities such as the offshore control room, the marine terminal, helicopter pads and training facilities.
It is useful to give a brief description of each stage, as this is relevant to the ‘taxing points’ contended for by Esso and to the approach adopted by the Commissioner. Again, I do not consider there is any dispute about the evidence giving rise to these findings.
The Bass Strait Platforms
The purpose of the Bass Strait platforms is to recover the petroleum from the undersea petroleum pools and partially separate it for metering and to facilitate transport by pipeline to the Longford Plant. The functions performed at the platforms are integral to and form part of the process that is continued at Longford and the LIP by which various products from the recovered petroleum are produced for sale. Whether or not at various points along the process some product could have been marketed and sold, this did not occur in the relevant period until the point where the product sought to be sold was in fact sold. To contend, as Esso does, that it has a “vendible product” as soon as the petroleum is recovered is not to the point. During the whole period, Esso did not sell nor seek to market or sell this so called “vendible product”. The evidence, both from Mr Heath and the Esso manual, indicates in any event, that the hydrocarbon streams were not in a marketable state prior to production of the sales gas at Longford, nor was there a market for such streams. Whatever may occur in other projects where gas is sold off the platform, this was not the position during the relevant period in Bass Strait.
Recovery of the petroleum is done using wells. A well is essentially a hole drilled from the platform down to the petroleum pool and lined with metal called a casing. The well penetrates the pool and is perforated at the desired depth to allow the petroleum to access it. Perforating the well at a particular depth is referred to as ‘completing’ it. Since the natural pressure in the pool is higher than at the surface the petroleum flows upwards through the well without the need for pumping to bring it to the surface. The pressure differential in the case of the gaseous pools is sufficient to cause the petroleum not only to flow up through the well but all the way through Esso’s processing facilities and to the end user. The rate at which the petroleum flowing under natural pressure arrives on the platform is controlled by the valves at the top of the well. Opening or closing the valves controls the rate at which petroleum is recovered.
A well may be ‘recompleted’, that is, closed off at its current depth and perforated at another depth, so as to access a different layer of a pool or a separate pool at a different depth. So, for example, an oil well may be recompleted as a gas well to access a pool at a different depth. Some wells are completed at more than one level.
On land wells can be drilled directly above the petroleum pool. At sea, however, due to the expense in installing and maintaining a platform, one platform will usually service numerous wells, for example, the Snapper platform (referred to later in these reasons) hosted 27 wells in its structure which were accessing the various petroleum pools in the Snapper field at up to 31 points. The wells can be drilled out at an angle from the platform so that the platform can be used to access petroleum pools that are some lateral distance from the platform. A platform may also be used to service subsidiary or satellite platforms and wells. The point at the top of a well where the petroleum exits onto the platform is called the ‘wellhead’.
A gas platform is one that services a gas field and an oil platform is one that services an oil field. However, a gas field may contain liquid pools and an oil field may contain gaseous pools or liquid pools with gas caps. An oil platform may thus also have gas wells and a gas platform may also have oil wells. Also, as noted above, a liquid petroleum pool will contain some dissolved lighter hydrocarbons and a gaseous hydrocarbon pool will contain some evaporated heavier hydrocarbons.
When the petroleum is brought to the surface the reduction in pressure and temperature often causes some of the liquid hydrocarbons in the gaseous petroleum to condense and the gaseous hydrocarbons in the liquid petroleum to evaporate out. This means that the petroleum stream at the wellhead will contain a mixture of petroleum in both liquid and gaseous phases. The stream of petroleum at the wellhead is known as the ‘well effluent’. A platform must therefore be capable of handling both liquid and gaseous petroleum.
Whenever petroleum is recovered some water, in either liquid or vapour form (or both), will also be recovered. In the case of an oil well the amounts of water can be very substantial. As the petroleum is extracted from a pool the level of the water beneath it will rise until it reaches the well, resulting in increasing amounts of water being recovered until recovery is no longer possible (called ‘watering out’).
On the platform after the well effluent exits the wellhead it is collected together in piping known as a ‘header’ and then undergoes some separation into liquid (heavier) and gaseous (lighter) hydrocarbon phases. This partial separation is done for three reasons:
·The petroleum needs to be separated into its liquid and gas phases for the purposes of metering because it is difficult to accurately meter a fluid that contains both a gas and a liquid phase.
·It is more difficult to pump or compress a mixture that is a combination of liquids and gas through a pipeline because different equipment (a pump for liquids and a compressor for gases) is needed for each phase. Accordingly, separation on the platform can make it easier and cheaper to move the petroleum to shore by allowing the streams to be directed to separate pipelines from the platform dedicated to either substantially gaseous or substantially liquid phase streams.
·The gas plants at Longford are designed to accept an inlet stream that is predominantly gaseous while the Crude Stabilisation Plant is designed to accept a stream that is predominantly liquid.
In the case of gas wells the separation that occurs on the platforms is sufficient to remove some of the hydrocarbon liquids from the gaseous petroleum recovered and some of the water.
Separation is accomplished on the platforms by a device known as a ‘separator’. A separator is a vessel designed to separate an incoming petroleum stream into gaseous (lighter) and liquid (heavier) streams. It does this by gravity – the heavier liquids and water tend to fall to the bottom of the separator where they are drawn off while the lighter gases are removed from the vessel through a pipe in the top. All of the well effluent from both gas and oil wells passes through at least one separator on the platforms. The composition of the gaseous and liquid phases leaving the separator will vary with separator temperature and pressure.
The substantially gaseous phase output stream from a separator will still contain evaporated heavier hydrocarbons and the substantially liquid phase output stream will still contain dissolved lighter hydrocarbons. The streams will also contain non-hydrocarbon compounds and some water in either vapour (gas streams) or liquid (liquid streams) form. Because of the cost of installing and maintaining equipment on the platforms as opposed to on land it is not cost-effective to carry out further separation and filtration of the petroleum streams on the platforms.
There are six platforms that are directly relevant to these proceedings:
·two large gas platforms servicing mainly gas fields: Barracouta and Marlin;
·a large oil and gas platform: Snapper; and
·three smaller oil platforms servicing oil fields: Tuna, West Tuna and Flounder.
The Barracouta platform also services two subsidiary, or satellite, oil wells: Tarwhine and Seahorse. Snapper also services the predominantly unmanned Whiting oil platform and the Moonfish oil wells, and West Tuna services the Batfish gas well. Each of the six platforms produces both liquid and gaseous raw petroleum.
On the platforms the partially separated gaseous and liquid streams can either be recombined after metering or sent from the platform in separate gas and liquid pipelines. The point at which a pipeline departs from a platform is called the Last Valve Off (‘LVO’).
Depending on the configuration of the platform and the number of separators the gaseous and liquid streams that exit the platform at each LVO can be the result of commingling of multiple individual streams on the platform.
Not all of the gaseous phase petroleum stream from the separator is sent from the platform. Gaseous petroleum is used, after further processing on the platform to remove liquids, as a fuel source for the platform. Gaseous petroleum can also be re-injected into oil wells so as to improve the efficiency of recovery from those wells (known as ‘gas-lift’). The re-injected gas lightens the column of fluids in the well and counteracts the effect of increasing water. The re-injected gas will then be re-recovered as part of a gas/oil mixture from the well. Surplus gaseous petroleum can be re-injected underground as a form of storage for later use. There is also provision on the platform for excess amounts of gaseous petroleum to be disposed of by burning (called ‘flaring’).
Depending on the daily production requirements the operators of the platforms are able to vary the rate at which gaseous petroleum is extracted from each well. This means that the volume and source of gaseous petroleum piped to the Longford Plant can vary on a continuous basis.
The Bass Strait Pipelines
A purpose of the pipelines linking the Bass Strait platforms to the Longford Plant is to bring the partially separated streams of liquid and gaseous petroleum ashore for further separation and filtering. There are pipelines that carry substantially gaseous phase hydrocarbon stream (that is, predominantly lighter hydrocarbons). There are pipelines that carry substantially liquid phase hydrocarbon stream (that is, predominantly heavier hydrocarbons). Pipelines, particularly pipelines from gas platforms, typically contain streams that are in both liquid and gaseous phases.
There are six main pipelines from the Bass Strait platforms to the Longford Plant:
·three gas pipelines linking the gas platforms Barracouta, Marlin and Snapper to Longford;
·An oil pipeline linking Barracouta to Longford; and
·two other oil pipelines which service Marlin and Snapper as well as the remaining oil platforms.
The contents of the gas pipelines are known as ‘wet gas’ or ‘raw gas’. It is called ‘wet gas’ because it contains heavier hydrocarbons and water. It is to be distinguished from ‘dry gas’ which has been dehydrated to remove water and which has had the heavier hydrocarbons removed. The contents of the oil pipelines are known as ‘crude’ or ‘crude oil’. Both pipelines also contain amounts of water and other non-hydrocarbon substances such as carbon dioxide, nitrogen and sulphur compounds, including hydrogen sulphide. The stream flowing through the gas pipelines will contain gaseous lighter hydrocarbons and some evaporated heavy hydrocarbons. The stream flowing through the oil pipelines will contain liquid heavy hydrocarbons and some dissolved lighter hydrocarbons. The streams will also contain some water.
The pipelines are laid on the bottom of the sea. Because the contents are cooled by the pipes being exposed to the ocean and because water is present inside the pipeline this can cause formation of water/hydrocarbon crystalline ices inside the gas pipelines, known as ‘hydrates’. This is undesirable and to help prevent it happening an antifreeze, monoethylene glycol (‘MEG’), is added to the gas streams on the platform before they are piped to shore.
In addition, because there is a drop in temperature and pressure over the length of the pipelines there will be some further separation of the contents of the pipelines into gaseous and liquid phases and some condensation of water by the time the pipelines reach Longford. Because the pipelines follow the contours of the ocean floor there are dips in the pipeline in which the separated liquid phase may accumulate during periods of lower flow. When flow rates are subsequently increased through the pipeline these accumulated liquids tend to surge into Longford at high speed, where they are known as ‘slugs’. The Longford Plant has special apparatus at the exit of the pipelines known as ‘slug catchers’ which are designed to slow down these slugs and store them for processing.
Longford Plant
The purpose of the Longford Plant is to further separate and filter the incoming raw gas and crude oil contents of the gas and oil pipelines respectively, with the following outputs:
·the commercial product sales gas;
·the commercial product stabilised crude oil; and
·a mixture of ethane, propane and butane known by Esso as ‘raw LPG’.
The Longford Plant has two main sections:
·the Crude Stabilisation Plant which further separates and filters the contents of the three incoming oil pipelines; and
·three gas plants, which further separate and filter the contents of the three incoming gas pipelines.
The two sections are interconnected so that lighter hydrocarbons extracted from the oil pipelines can be sent to the gas plants for processing and the heavier hydrocarbons extracted from the gas pipelines can be sent to the Crude Stabilisation Plant for processing.
Stabilised crude oil is crude oil that can be safely handled and stored in open containers without loss of the lighter gaseous phase hydrocarbons by evaporation. Crude oil is stabilised by removing these lighter hydrocarbons that are dissolved in the crude oil. The Crude Stabilisation Plant functions by separating the remaining lighter gaseous hydrocarbons (methane, ethane, propane and butane) from the crude oil stream that arrives via the oil pipeline. Impurities and water are also filtered out. The Crude Stabilisation Plant is linked to the gas plants so that these lighter hydrocarbons separated from the crude oil (the ‘KVR Vapours’) can be sent to the gas plants to be processed along with the wet gas from the gas pipelines. The output of the Crude Stabilisation Plant is stabilised crude oil which is then sent by pipeline to Long Island Point for sale.
There are three gas plants at Longford with Gas Plant No 1 using a different method of separation to Gas Plants Nos 2 and 3. Gas Plant No 1 uses a method known as lean oil absorption while Gas Plants Nos 2 and 3 use cryogenic separation. All, however, have the same purpose, namely, the further separation and filtering of the incoming raw gas from the gas pipelines.
The gas plants function by removing impurities such as hydrogen sulphide and water and then separating the raw gas stream exiting the gas pipelines into three constituent streams:
1.A stream consisting principally of methane (but with some ethane as well) which has been processed so that it meets the specifications for the commercial product sales gas. The sales gas is sold to buyers at the exit from Longford.
2.A stream consisting principally of ethane, propane and butane. This stream is called ‘raw LPG’ by Esso and is piped to Long Island Point in liquid form for further separation and processing.
3.Separated heavier liquid hydrocarbons (that is, C5+) which are sent across to the Crude Stabilisation Plant to be processed along with the crude oil from the oil pipelines.
Not all of the gas produced at Longford is sold to customers. After further processing, some is used as a fuel source for Esso’s own electricity generation equipment. The gas to be used for fuel gas is taken off at points after the heavier hydrocarbons have been removed. This electricity is used to power the Longford Plant, with any excess generation capacity being available to generate electricity to be sold into the Victorian power grid.
Longford to Long Island Point Pipelines
There are two pipelines which connect the Longford Plant to Long Island Point. The first carries stabilised crude oil. The second contains a ‘raw LPG’ mixture of liquefied ethane, propane and butane. Under standard temperature and pressure ethane, propane and butane are gaseous. As initially produced inside the Longford Plant the ‘raw LPG’ mixture is gaseous. However, the ‘raw LPG’ mixture is then passed through plant designed to cool and then compress it so that it forms a single liquid phase for pumping along the pipeline from the Longford Plant to Long Island Point.
Long Island Point
The functions of the LIP include providing storage for the stabilised crude oil and further separation of the ‘raw LPG’ stream so as to produce the commercial products ethane, propane and butane.
At LIP the stabilised crude oil is stored in tanks. In these tanks residual water in the stabilised crude oil can settle out and is periodically drained away. The stabilised crude oil is withdrawn from the tanks and sold to customers.
The ‘raw LPG’ mixture is further processed at LIP so as to separate out the ethane, propane and butane. This processing is known as fractionation. First the ethane is removed from the ‘raw LPG’ mixture and then the propane and butane are separated. Water and other impurities are also removed. The ethane is processed so as to meet buyers’ specifications and is then piped to Altona in gaseous form where it is sold to buyers for use in the petrochemical industry. The propane and butane are processed to meet buyers’ specifications and sold in liquid form at LIP. There are storage facilities at LIP for propane and butane.
There is provision at LIP for the ethane to be used as a fuel gas in the LIP’s power generation system. There is also provision for flaring.
THE SALE OF PRODUCTS PRODUCED
All of the products referred to by Mr Heath were sold either at Longford (in the case of sales gas), LIP (in the case of commercial propane, commercial butane and stabilised crude oil) or at the end of a pipeline owned and operated by the joint venturers (in the case of ethane).
Sales gas
Over the period with which these proceedings are concerned, there were three main sales agreements pursuant to which the joint venturers, as the ‘sellers’, sold sales gas produced at Longford to its principal ‘buyers’. They were:
1.an agreement made in 1975 between the joint venturers and the GFC, which terminated on 30 November 1996 (‘the Sales Agreement’);
2.an agreement made in 1996 between the joint venturers and Gascor, the successor entity to the GFC, which replaced the earlier agreement and was in force throughout the remainder of the relevant period (the 1996 Gascor Agreement); and
3.an agreement made in 1981 between the joint venturers and the SECV.
From September 2000, Esso also sold gas to customers other than the GFC, Gascor or the SECV.
Propane and butane
Commercial propane and commercial butane were sold as separate products to many different customers. They were sold from LIP at different points: they were sold onto ocean going ships at the LIP jetty; they were delivered into a pipeline owned and operated by the GFC (and later Gascor and others) and delivered to a facility at Dandenong; and they were sold onto trucks at the LIP truck terminal just outside the boundary to LIP. In each case, the sale took place at LIP.
Ethane
Commercial ethane was produced at LIP and piped from there to Altona via a dedicated pipeline owned and operated by the joint venturers. At Altona, it was sold to no more than two customers at any one time. Title to the ethane transferred close to the customers’ premises at the end of the pipeline.
Stabilised crude oil
Stabilised crude oil was produced at Longford and piped to a storage facility (the ‘tank farm’) at LIP, from where it is sold. During the relevant period, Esso sold stabilised crude oil onto ocean going ships at the LIP jetty, for transport to Australian and international refineries, and via a pipeline (known as the WAG pipeline) to refineries in Altona and Geelong. The pipeline was not owned or operated by the joint venturers. Title to the stabilised crude oil passed at the point it was loaded onto the ships or at the exit of LIP into the WAG pipeline.
THE PRRT ACT AND PRRTA ACT
I now turn to the statutory framework in which the questions for determination fall for decision by the Court.
The Petroleum Resource Rent Tax Act 1987 (Cth) (‘PRRT Act’) and the PRRTA Act came into operation on 15 January 1988. The PRRT Act imposes tax “… in respect of the taxable profit of a person of a year of tax in relation to a petroleum project”. The rate of tax imposed is 40%.
The PRRTA Act is described in its long title as:
An Act relating to the assessment and collection of the tax imposed by the Petroleum Resource Rent Tax Act 1987, and for related purposes
Part V of the PRRTA Act deals with “Liability to Taxation”. The following relevant divisions appear in Pt V:
·Division 1, Liability to tax on taxable profit, creates the liability to pay PRRT (ss 21-22);
·Division 2, Assessable receipts, sets out the criteria for determining what is an assessable receipt (ss 23-31A); and
·Division 3, Deductible expenditure, sets out the criteria for determining what is deductible expenditure (ss 31B-45).
Part IV of the PRRTA Act defines the concept of a petroleum project.
The term ‘petroleum project’ is defined in s 2 to mean a petroleum project within the meaning of s 19(1) or (2).
Section 19(1), (1A) and (2), which form part of Pt IV of the Act, provide, so far as is relevant:
(1)Subject to subsection (1A), for the purposes of this Act, where an eligible production licence is in force and is not specified in a project combination certificate that is in force, there shall be taken to be a petroleum project in relation to the eligible production licence.
(1A)For the purposes of this Act, there is taken to be a single petroleum project in relation to all production licences that are related to the Bass Strait exploration permit and that are in force from time to time, unless those licences are specified in a project combination certificate that is in force.
(2)For the purposes of this Act, where 2 or more eligible production licences are specified in a project combination certificate that is in force, there shall be taken to be a petroleum project in relation to such of the eligible production licences as are in force.
There are production licences held by the joint venturers in relation to Bass Strait. A project combination certificate has been issued by the Minister for Resources & Energy. For the purposes of the PRRTA Act, there is a single petroleum project in relation to the Bass Strait production licences.
It is important to note that the production licence area does not constitute the entirety of the petroleum project. Rather, s 19(1), (1A) and (2) provide only that there shall be a petroleum project in relation to an eligible production licence or licences.
Section 19(4) provides:
For the purposes of this Act, a reference to the operations, facilities and other things comprising a petroleum project is a reference to:
(a)operations and facilities for the recovery of petroleum from the production licence area or production licence areas in relation to the project; and
(b)such of the following as are carried on or provided:
(i)operations and facilities involved in moving petroleum so recovered between any storage or processing facilities prior to the production of any marketable petroleum commodity from the petroleum;
(ii)operations and facilities involved in the storage, processing or treatment of petroleum so recovered to produce any marketable petroleum commodity from the petroleum;
(iii)operations and facilities involved in the moving or storage of any such marketable petroleum commodity before it becomes an excluded commodity;
(iv)services, or facilities for the provision of services, in connection with the operations, facilities, amenities and services referred to in this section;
(v)employee amenities in connection with the operations, facilities and services referred to in this section.
The liability to pay tax is imposed by s 21 which provides:
Subject to this Act, tax imposed in respect of the taxable profit of a person of a year of tax in relation to a petroleum project is payable by the person.
The taxable profit is defined in s 22:
Where, in relation to a petroleum project and a year of tax, the assessable receipts derived by a person exceed the sum of:
(a)the deductible expenditure incurred by the person; and
(b)the total of the amounts (if any) transferred by the person to the project in relation to the year of tax under section 45A; and
(c)the total of the amounts (if any) transferred by another person to the person in relation to the project and the year of tax under section 45B;
the person is taken for the purposes of this Act to have a taxable profit in relation to the project and the year of tax of an amount equal to the excess.
‘Assessable receipts’ is then defined in s 23. It refers to total receipts of specified kinds whether of a capital or revenue nature. The kinds of receipts which make up assessable receipts are:
(a) assessable petroleum receipts;
(b) assessable exploration recovery receipts;
(c) assessable property receipts;
(d) assessable miscellaneous compensation receipts;
(e) assessable employee amenities receipts.Each of those components is separately explained in the succeeding provisions. The term relevant for present purposes is ‘assessable petroleum receipts’. Relevantly for the first period, it was defined in s 24 thus:
For the purposes of this Act, a reference to assessable petroleum receipts derived by a person in relation to a petroleum project is a reference to:
(a)where any petroleum, or a constituent of petroleum, recovered from the production licence area or areas in relation to the project is or was sold, whether processed or unprocessed, before any marketable petroleum commodity is or was produced from it – the consideration receivable, less any expenses payable, by the person in relation to the sale;
(b)where any marketable petroleum commodity produced from petroleum recovered from the area or areas to which paragraph (a) applies becomes or became an excluded commodity by virtue of being sold – the consideration receivable, less any expenses payable, by the person in relation to the sale; and
(c)where any marketable petroleum commodity produced from petroleum recovered from the area or areas to which paragraph (a) applies becomes or became an excluded commodity otherwise than by virtue of being:
(i)sold; or
(ii)treated or processed, or moved, for re-injection or destruction or for use in carrying on or providing operations, facilities or other things of a kind referred to in section 37, 38 or 39 in relation to the petroleum project;
so much of the market value of the commodity immediately before it becomes or became an excluded commodity, or, where there is insufficient evidence of that market value, of such amount as, in the opinion of the Commissioner, is fair and reasonable, as is taken by section 26 to be derived by the person.
‘Deductible expenditure’, which appears in s 22, is defined in s 32 thus:
For the purposes of this Act, a reference to the deductible expenditure incurred by a person in a financial year in relation to a petroleum project (not being an ineligible project in relation to the financial year) is a reference to the total expenditure of the following kinds incurred by the person in the financial year in relation to the project:
(a) class 1 augmented bond rate general expenditure;
(b) class 1 augmented bond rate exploration expenditure;
(c) class 2 augmented bond rate general expenditure;
(d) class 1 GDP factor expenditure;
(e) class 2 augmented bond rate exploration expenditure;
(f) class 2 GDP factor expenditure;
(g) closing-down expenditure.The terms referred to in s 32 are separately defined in succeeding provisions of the Act. The only provision to which reference need be made relates to general project expenditure which for the first period was defined in s 38, thus:
For the purposes of this Act, a reference to general project expenditure incurred by a person in relation to a petroleum project is a reference to payments (not being excluded expenditure, exploration expenditure or closing-down expenditure), whether of a capital or revenue nature, liable to be made by the person:
(a)in carrying on or providing operations and facilities preparatory to the activities referred to in paragraph (b), including in carrying out any feasibility or environmental study; and
(b)in carrying on or providing the operations, facilities and other things comprising the project;
and includes any production licence or other fee (not being an excluded fee) liable to be paid by the person in relation to the carrying on or providing of any operations, facilities or other things referred to in this section.
It will be apparent that s 24(a) and (b) of the PRRTA Act draws a distinction between petroleum (or a constituent of petroleum) on the one hand and a marketable petroleum commodity on the other, the latter being something that is produced from petroleum, and that petroleum may be processed and yet remain petroleum for the purposes of the PRRTA Act.
Petroleum is defined in s 2 of the PRRTA Act to have the same meaning as in the Petroleum (Submerged Lands) Act 1967 (Cth). Throughout the whole period, s 2 of that Act defined petroleum to mean:
(a)any naturally occurring hydrocarbon, whether in a gaseous, liquid or solid state;
(b)any naturally occurring mixture of hydrocarbons, whether in a gaseous, liquid or solid state;
(c)any naturally occurring mixture of one or more hydrocarbons, whether in a gaseous, liquid or solid state, and one or more of the following, that is to say, hydrogen sulphide, nitrogen, helium and carbon dioxide;
and includes any petroleum as defined by paragraph (a), (b) or (c) that has been returned to a natural reservoir in an adjacent area.
Then there are two important defined terms relevant to the proper interpretation of s 24. As Esso pointed out on a number of occasions during the course of submissions, each definition is an exhaustive definition, encapsulated by the use of the word “means”.
The term ‘marketable petroleum commodity’ is defined in s 2 of the PRRTA Act as follows:
marketable petroleum commodity means any of the following products produced from petroleum:
(a) stabilised crude oil;
(b) sales gas;
(c) condensate;
(d) liquefied petroleum gas;
(e) ethane;(f)any other product declared by the regulations to be a marketable petroleum commodity;
not being a product produced from another product of a kind referred to in paragraphs (a) to (f) (inclusive).
Then the term ‘excluded commodity’ is defined in s 2 of the PRRTA Act to mean:
… a marketable petroleum commodity that:
(a)has been sold;
(b)after being produced, has been further processed or treated; or
(c)has been moved away from the place of its production other than to a storage site adjacent to that place; or
(d)has been moved away from a storage site adjacent to the place of its production.
During the first period, sales gas was defined in s 2 to mean a mixture that includes methane, where the methane comprises more than 50% by weight of the mixture.
For the whole period, LPG was defined in s 2 to mean a mixture that includes propane and butane, where the propane and butane comprise more than 50% by weight of the mixture.
There was no definition of ethane or stabilised crude oil in s 2 during the whole period.
No regulation was made declaring any product to be a marketable petroleum commodity for the purposes of the definition of ‘marketable petroleum commodity’.
Section 24 and the definition of ‘sales gas’ in s 2 of the PRRTA Act were amended with effect from 1 April 2002 by the Taxation Laws Amendment Act (No 6) 2001 (Cth) (‘the 2001 Amendment Act’).
Esso’s case seems to be that the amendment to the definition of sales gas had the effect of shifting the place at which sales gas was produced and became an excluded commodity downstream from various points on the offshore platforms (if Esso is successful in relation to the first period) or upstream of the point of sale (if Esso is unsuccessful in relation to the second period) to various points within the Longford Plant. The extrinsic materials relating to the 2001 Amendment Act demonstrate that the amendments were concerned to clarify the point at which sales gas was produced and became an excluded commodity in the context of integrated gas-to-liquid (or ‘GTL’) projects, such as liquefied natural gas (or ‘LNG’) projects, and the price to be attributed to sales gas at that point in such projects. These proceedings do not concern such a project. Nothing in the extrinsic materials evinces any intention to alter the manner in which the PRRTA Act had previously applied to sales gas produced from Bass Strait in respect of either the place of production of the sales gas product or the manner in which it became an excluded commodity.
The Explanatory Memorandum to the Bill for the 2001 Amendment Act stated that:
Part 1 of Schedule 1 to this bill amends the PRRTA Act to reduce the uncertainty surrounding the determination of a price for gas produced in integrated GTL [Gas to Liquid] projects.
Broadly, the amendments will provide for a new methodology to determine the price where there is no comparable uncontrolled price and:
• there is not a sale at the PRRT taxing point; or
• there is a sale at the PRRT taxing point but the sale is non-arm’s length.The new methodology will be incorporated in regulations to the PRRTA Act.
The Explanatory Memorandum stated also that the Bill included “a revised definition of ‘sales gas’ … in order to determine the PRRT taxing point of sales gas (ie when the gas becomes an excluded commodity) in the extraction phase of an integrated GTL project.”
Other than an amendment to the definition of sales gas in s 2 and to s 24, the relevant provisions and definitions remained unchanged.
As a result of the amendments, throughout the second period from 1 April 2002 to 30 June 2002, sales gas was defined in s 2 of the PRRTA Act as follows:
sales gas means a substance:
(a)which is in a gaseous state when at the temperature of 15°C and a pressure of one atmosphere; and
(b)which consists of naturally occurring hydrocarbons, or a naturally occurring mixture of hydrocarbons and non-hydrocarbons; and
(c)the principal constituent of which is methane; and
(d)which:
(i)if it is to be used as a feedstock for conversion to another product – has been processed so that it is suitable for that use; or
(ii)in any other case – has been processed so that it is suitable for direct consumption as energy.
During the second period, s 24 provided as follows:
(1)For the purposes of this Act, a reference to assessable petroleum receipts derived by a person in relation to a petroleum project is a reference to:
(a)where any petroleum, or a constituent of petroleum, recovered from the production licence area or areas in relation to the project, is or was sold, whether processed or unprocessed, before any marketable petroleum commodity is or was produced from it – the consideration receivable, less any expenses payable, by the person in relation to the sale;
(b)where any marketable petroleum commodity (other than sales gas) produced from petroleum recovered from the area or areas to which paragraph (a) applies becomes or became an excluded commodity by virtue of being sold – the consideration receivable, less any expenses payable, by the person in relation to the sale; and
(c)where any marketable petroleum commodity (other than sales gas) produced from petroleum recovered from the area or areas to which paragraph (a) applies becomes or became an excluded commodity otherwise than by virtue of being:
(i)sold; or
(ii)treated or processed, or moved, for re-injection or destruction or for use in carrying on or providing operations, facilities or other things of a kind referred to in section 37, 38 or 39 in relation to the petroleum project;
so much of the market value of the commodity immediately before it becomes or became an excluded commodity, or, where there is insufficient evidence of that market value, of such amount as, in the opinion of the Commissions, is fair and reasonable, as is taken by section 26 to be derived by the person;
(d)where any sales gas produced from petroleum recovered from the area or areas to which paragraph (a) applies becomes or became an excluded commodity by virtue of being sold:
(i)if the sale is a non-arm’s length transaction – the amount worked out in accordance with the regulations; and
(ii)in any other case – the consideration receivable, less any expenses payable, by the person in relation to the sale; and
(e)where any sales gas produced from petroleum recovered from the area or areas to which paragraph (a) applies becomes or became an excluded commodity otherwise than by virtue of being:
(i)sold; or
(ii)treated or processed, or moved, for re-injection or destruction or for use in carrying on or providing operations, facilities or other things of a kind referred to in section 37, 38 or 39 in relation to the petroleum project;
the amount worked out in accordance with the regulations.
(2) In this section:
non-arm’s length transaction means a transaction where the Commissioner, having regard to any connection between the parties to the transaction or to any other relevant circumstances, is satisfied that the parties to the transaction are not dealing with each other at arm’s length in relation to the transaction.
I observe that regulations were not made under s 24(1) of the PRRTA Act until 2005: the Petroleum Resource Rent Tax Assessment Regulations 2005 (Cth), registered on 15 December 2005.
STATUTORY INTERPRETATION AND EXTRINSIC MATERIAL
Overview
I now turn to consider the extrinsic material brought before the Court by the parties. Before doing so, I make some general observations.
It is apparent that the legislation before me reflects input from a variety of groups within the petroleum and mining industry. Correspondence over time, both prior to and after the passing of the legislation, indicates lobbying and the expression of various positions by interested parties.
Context is important in interpreting legislation. However, where legislation comes into existence after extensive ‘positioning’ by various parties, extrinsic material in the form of ‘position papers’, press releases and private correspondence, even between Ministers and members of the public, does not assist in discerning the purpose of a legislative enactment. In fact, it may lead to error.
As McHugh J said in Stevens v Kabushiki Kaisha Sony Computer Entertainment (2005) 224 CLR 193 at 231 [para 126]:
Much modern legislation regulating an industry reflects a compromise reached between, or forced upon, powerful and competing groups in the industry whose interests are likely to be enhanced or impaired by the legislation. In such cases, what emerges from the legislative process is frequently not a law motivated solely by the public interest. It reflects wholly or partly a compromise that is the product of intensive lobbying, directly or indirectly, of Ministers and parliamentarians by groups in the industry seeking to achieve the maximum protection or advancement of their respective interests. The only purpose of the legislation or its particular provisions is to give effect to the compromise. To attempt to construe the meaning of particular provisions of such legislation not solely by reference to its text but by reference to some supposed purpose of the legislation invites error.
The sellers made the following MLMDQ nominations for the contract years from 1990-2000:
Contract Year MLMDQ Nomination 1990 8.3 million therms 1991 8.3 million therms 1992 8.3 million therms 1993 8.3 million therms 1994 8.3 million therms 1995 8.3 million therms 1996 8.3 million therms 1997 8.0 million therms 1998 7.7 million therms 1999 7.5 million therms 2000 7.4 million therms
By letter dated 7 September 1990 GFC advised the sellers that its forecast requirements were as follows:
Contract Year MDR Forecast Forecast of Expected MDQ Nomination 1991 9.4 million therms 1992 9.8 million therms 1993 10.2 million therms 1994 10.5 million therms 1995 10.9 million therms 8.7 million therms 1996 11.2 million therms 9.4 million therms 1997 11.5 million therms 9.7 million therms 1998 11.7 million therms 10.0 million therms 1999 12.0 million therms 10.3 million therms 2000
12.3 million therms
10.5 million therms
In August 1990 the buyer approached the sellers about increasing the MLMDQ levels set under the Sales Agreement so that it could access a higher level of MDQ in 1995-2000 if it was required.
(c) The agreement to increase the MLMDQ levels
The parties reached an agreement in mid-1991, which is set out in the letter dated 6 June 1991 (referred to as the ‘Heads of Agreement’), and the subsequent letter dated 17 December 1991 as modified by the further letter dated 29 June 1992 (collectively, ‘the MLMDQ Agreement’).
Although the letter dated 17 December 1991 states that the sellers agreed to revise the MLMDQ advised to the buyer over the period from 1991-2000, the MLMDQ was only actually increased in the years from 1995 to 2000:
Contract Year Revised MLMDQ 1990 8.3 million therms 1991 8.3 million therms 1992 8.3 million therms 1993 8.3 million therms 1994 8.3 million therms 1995 8.7 million therms 1996 9.4 million therms 1997 9.7 million therms 1998 10.0 million therms 1999 10.3 million therms 2000 10.5 million therms
The increased level of MLMDQ did not increase the amount of gas to be sold. It increased the range in which GFC could nominate the maximum quantity of gas to be delivered on a given day.
In addition to dealing with the agreement reached on MLMDQ, the agreement recorded in the letters of 6 June 1991 and 17 December 1991 (as modified by the further letter dated 29 June 1992) also dealt with a number of matters which had been negotiated contemporaneously. These other matters were referred to as the ‘C Market price renegotiation’ and the ‘1991 End Market Price Challenge’.
The terms of the MLMDQ Agreement were incorporated into a new Gas Sales Agreement between Esso, BHP and Gascor dated 20 November 1996 (‘the 1996 Agreement’), which superseded the Sales Agreement.
(d) The increased MLMDQ levels
GFC agreed to make monthly payments for the period from July 1991 through to December 2000, which consisted of a fixed and a variable component (described in cl 1.3 and cl 1.4 of the document enclosed with the letter of 17 December 1991). The MLMDQ payments invoiced and returned as assessable receipts by Esso were:
Year ended 30 June MLMDQ (Assessed) MLMDQ (Invoiced) Proceeding No VID 1992
$11,345,004
$11,345,004
1025
1993
$12,350,731
$12,350,694
1312
1994
$12,691,198
$12,691,723
1313
1995
$11,992,286
$11,991,975
1027
1996
$11,493,177
$11,492,391
1028
1997
$11,733,234
$11,730,702
1029
1998
$11,784,112
$11,787,372
1030
1999
$11,831,501
$11,831,669
1031
2000
$12,018,399
$12,014,288
1032
2001
$6,155,896
$6,159,725
1034
Total
$113,395,538
$113,395,543
The difference between the invoiced amount and the amounts that Esso returned as assessable petroleum receipts was due to the accounting treatment of these amounts.
Consideration
As I have indicated, the principal issues in dispute are whether the MLMDQ payments and the 1997 payment are assessable petroleum receipts under paragraph 24(b) of the PRRTA Act. Esso contended that neither the MLMDQ payments nor the 1997 payment satisfy s 24(b), because they are not “consideration receivable, less any expenses payable, by the person … in relation to the sale” of gas.
Esso referred to Woodside Energy Ltd v FCT (2009) 174 FCR 91, where the Full Court considered the meaning of s 24(b) and, in particular, the nexus required between “consideration receivable” and a sale of oil, in the context of claims to deduct hedging losses as expenses payable in relation to sales of oil.
The Full Court said that the use of the word “consideration” in s 24 controls the sales to which paragraphs (a) and (b) of s 24 refer. The Court referred to comments by Dixon J in Archibald Howie Pty Ltd v Commissioner of Stamp Duties (NSW) (1948) 77 CLR 143 at 152, where his Honour said:
In the context I think that the word ‘consideration’ should receive the wider meaning or operation that belongs to it in conveyancing rather than the more precise meaning of the law of simple contracts. The difference is perhaps not very material because the consideration must be in money or money's worth. But in the law of simple contracts it is involved with offer and acceptance: indeed properly understood it is perhaps merely a consequence or aspect of offer and acceptance. Under s 66 the consideration is rather the money or value passing which moves the conveyance or transfer.
Adopting the same reasoning, the Full Court concluded that “consideration”:
… would not encompass a passing of money or value which does not move the relevant sale. The only money or value which moves the relevant sale, the sale of Laminaria oil, is the contract price, whether the nexus is provided by the phrase ‘in relation to’ the sale, or by the word ‘for’ the sale.
By parity of reasoning, Esso contended that the MLMDQ payments did not relate to any sales of gas. This was said to be most apparent in relation to the MLMDQ payments Esso received in the 1992, 1993 and 1994 years. During those years Esso received MLMDQ payments but the sellers were not obliged to, nor did they, deliver any additional gas over and above what they were otherwise required to deliver under the Sales Agreement before it was varied in 1991 (because the MLMDQ was only increased in the years from 1995 to 2000).
Esso also contended that French J (as he then was), whose decision at first instance was upheld in the Full Court, also indicated that the receipts to which s 24(b) applies must be payments for a particular sale:
The receipts from marketable petroleum commodities which have been sold comprise ‘the consideration receivable, less any expenses payable, by the person in relation to the sale’. Consideration in this context may be taken to refer to payment received in return for the delivery of the commodity pursuant to the sale in question. It is not a net concept. It cannot sensibly be construed as a sum calculated by reference to hedging losses. It is the payment received for sale of the relevant commodity. The assessable petroleum receipts, for the purposes of s 24(b) comprised payment for a particular sale less expenses payable in relation to that sale. The language of the section suggests a close connection between the expense and the sale transaction. Such a connection may have functional and temporal aspects. While the word ‘direct’ does not appear in the section to qualify the relationship between expenses and sale, the language of the section, in my opinion, suggests such a limitation.
It was contended by Esso that the MLMDQ payments were not made pursuant to the Sales Agreement but rather under the MLMDQ Agreement which was a variation to the Sales Agreement agreed in a series of side letters. No additional gas was recovered, produced or sold in return for the MLMDQ payments as the variations made by the MLMDQ Agreement did not in any way change the total volume of gas to be sold. Therefore, the MLMDQ Agreement did not alter the level of dedicated gas reserved under Article XV of the Sales Agreement, and did not change the total volume of gas required to be supplied by the sellers over the term of the Sales Agreement (see clause 2.2 of Article II). The purpose and effect of the MLMDQ Payments was to give GFC the opportunity to revise the parameters within which a demand for gas could be made.
The Commissioner contended that the MLMDQ Agreement was a variation to the 1975 Agreement between Esso and BHPBP and the GFC, and the payments thereunder should be considered in that light.
From this perspective, it was contended by the Commissioner that the consideration paid to Esso under the Sales Agreement should be treated as relating to the sale of gas, notwithstanding that it was consideration for a range of matters including not only the quantity of the gas delivered but also the security of supply, delivery point, pressure and the quality of the gas delivered. Therefore, the MLMDQ payments should be considered an increase in the total price paid by the GFC for the performance of the combination of promises made by the sellers under the Sales Agreement.
The Commissioner relied upon the Chief Commissioner of State Revenue (NSW) v Dick Smith Electronics Holdings Pty Ltd (2005) 221 CLR 496. I do not consider any assistance can be gained from that decision, dealing as we are in these proceedings with the operation of the PRRTA Act and the terms of the agreements set out above.
In my view, in the absence of any additional sale of gas, the MLMDQ payments did not have the relevant and direct nexus with the sales of gas originally agreed in 1975 under the Sales Agreement.
The PRRT is relevantly imposed on the sale of gas. The focus is upon that sale and the consideration for the sale. The Commissioner submits that the payments made pursuant to the variations to the Sales Agreement do not stand alone, and make no sense without the Sales Agreement. So much is true. However, the question is to determine, within that context, what the consideration was for the sale of the gas.
In my view, it is important to characterise the transactions, and focus upon the operation of the MLMDQ payments as set out in the contractual documents.
I accept the characterisation submitted by Esso. The important point is that the sellers were willing to transfer to the buyer the gas for the consideration agreed to in the Sales Agreement excluding the MLMDQ payments. The MLMDQ payments did not move the transfer of the gas, rather they related to a specific variation that did not affect the quantity or quality of the gas sold.
On this basis I do not accept the position taken by the Commissioner in relation to the MLMDQ payments.
Esso contended that like the MLMDQ payments, the 1997 payment does not relate to any specific quantity of gas taken by Genvic or by SECV. It was contended that Esso received the payment, without being obliged to deliver any gas, because Genvic failed to take the minimum amount of gas it was required to buy under the contract. Esso contended that the 1997 payment was not receivable “in relation to” the sale of gas because it was not directly connected to any particular sales of gas that Esso produced. It was also not “consideration receivable” for or in relation to the sale of gas because it did not “move the transfer” of any particular amount of gas.
In addition to the authorities referred to by it in relation to the MLMDQ, Esso relied upon Diamond Shamrock Exploration Co v Hodel (1988) 853 F.2d 1159 (5th Cir. 1988).
In Diamond Shamrock the United States Court of Appeals for the Fifth Circuit was required to determine whether royalties were due for payments made under take or pay payments not as value of gas actually taken but as a result of the take or pay obligation under the contract. The producer was required to pay a royalty of 16⅔% in amount or value of “production saved, removed or sold from the leased area”. The gas producer paid the royalties only to the extent that make up gas was taken. After an audit, the relevant government agency demanded that the oil company pay royalties on the take or pay payments.
Justice Brown held, at 1165, that:
… royalties are not due on “value” or even “market value” in the abstract, but only on the value of production saved, removed or sold from the leased property. Likewise, the agency’s regulations do not refer to “gross proceeds” in the abstract, but only to gross proceeds that accrue to the lessee from the disposition or sale of produced substances, that is, gas actually removed and delivered to the pipeline. Consequently, royalties are not owed unless and until actual production, the severance of minerals from the formation, occurs.
Later in his judgment, at 1167, he observed that:
A take-or-pay payment which comes before gas is actually produced and taken simply cannot be a payment for a sale of gas.
The purpose of take-or-pay clauses is to apportion the risks of natural gas production and sales between the buyer and seller. The seller bears the risk of production. To compensate seller for that risk, buyer agrees to take, or pay for if not taken, a minimum quantity of gas. The buyer bears the risk of market demand. The take-or-pay clause insures that if the demand for gas goes down, seller will still receive the price for the contract quantity delivered each year.
Take-or-pay payments are not, therefore, payments for the sale of gas. Far from being payments for the purchase of gas, take-or-pay payments are payment for the pipeline - purchaser’s failure to purchase (take) gas.
Justices Johnson and Higginbotham concurred in the judgment.
Diamond Shamrock was referred to with approval by Lander J in Alliance Petroleum Australia NL v The Australian Gas Light Company, unreported, Supreme Court of South Australia, 23 December 1994, who said (at p 12), in relation to a take or pay clause that as “explained in the Shamrock Case the payment was not for the gas taken but for the failing to take the gas.”
The Commissioner contended that the 1997 payment (referred to in the Commissioner’s written submissions as the “1996 Shortfall Payment”) was part of the consideration that the SECV provided to Esso in the 1996 contract year for the acquisition of the gas supplied during that year. The Commissioner contended that there was a material and relevant relationship between the 1997 payment and the gas supplied during the 1996 contract year, and contended that it is not important if the payment also secured an entitlement to Make Up Gas. The Commissioner contended that in any event the 1997 payment was consideration only for gas supplied and delivered in the year ended 30 June 1997 because there was no right to Make Up Gas.
Again the question is to determine the degree of connection required between the consideration receivable and the sale of gas. The content of contractual arrangements between the parties will determine this connection.
I do not consider that the obligation to pay arises from the failure to take gas as submitted by Esso. There was an obligation to pay at the outset, and it was the consideration that moved the supply of gas actually supplied. This is the effect of clauses 19.1 and 7.3 of the SECV Agreement.
The construction of cl 19.1 allows for no other conclusion. This applies whether the gas is still in the ground or not. The consideration for the gas taken in a particular year is a certain sum, no matter how much gas is in fact taken. In fact, if no gas is actually taken, the minimum amount would still need to be paid. This conclusion, whilst Esso contends otherwise, arises from the construction and operation of cl 19.1.
It is to be recalled that clause 8.1 of the SECV Agreement indicates that the entitlement to Make Up Gas arose not as a result of making a Shortfall Payment pursuant to clause 7.3, but as a result of the SECV failing to take the Minimum Annual Quantity. In a year in which the SECV took its Minimum Annual Quantity but nevertheless was required to make a Shortfall Payment, it did not receive any entitlement to Make Up Gas. This occurred in the 1994 and 1995 calendar years. In such circumstances, the 1994 and 1995 Shortfall Payments can only have been consideration for the gas sold and delivered in the calendar years ended 31 December 1994 and 1995. The 1994 and 1995 Shortfall Payments were therefore treated by Esso, correctly, as assessable petroleum receipts for the tax years ended 30 June 1995 and 30 June 1996 and Esso does not seek to excise those amounts from its assessable petroleum receipts for those years.
By reason of the operation of clause 8.3 of the SECV Agreement and the expiry of Part A on 31 December 1996, the 1997 payment did not secure for Genvic any entitlement to Make Up Gas. The 1997 payment was consideration for and only for the gas sold and delivered in the year ended 30 June 1997.
As I have indicated, Esso submitted that the 1997 payment was a payment made pursuant to an obligation which arose from the SECV’s failure to take gas during the 1996 contract year and that it was, accordingly, directly related to gas not taken during that year. I accept the Commissioner’s contention that this is an incorrect characterisation of the contractual provisions set out above. The SECV’s obligation to make a Shortfall Payment arose by operation of clauses 7.3 and 19.1 of the SECV Agreement. It arose as a result of the fact that the amounts “otherwise paid” for gas supplied during a contract year were less than the MAP prescribed by clause 7.1. The obligation to make a Shortfall Payment arose not from the failure to take gas, as Esso would have it, but from the failure to make the MAP for the gas taken in a particular contract year.
I turn to the 1991 and 1993 Shortfall Payments.
In respect of the 1991 and 1993 Shortfall Payments, the Commissioner agrees, for the reasons given above in relation to the 1997 payment, that those amounts constituted assessable petroleum receipts in the tax years in which they were receivable, namely the tax years ended 30 June 1992 and 1994.
Accordingly, the amounts incorrectly included by Esso in its assessable petroleum receipts in respect of Make Up Gas taken in the tax years ended 30 June 1993, 1995 and 1996 should be excised from its returns for those years and added back into its assessable petroleum receipts in the tax years ended 30 June 1992 and 1994. Esso consents to these adjustments.
However, in respect of the 1987 and 1988 shortfall amounts, the effect of a transitional provision in the 1991 Amendment Act, which amended the PRRTA Act so as to apply it to the Bass Strait project, in my view requires that the 1987 and 1988 Shortfall Payments be differently treated. It will be recalled that s 33(4) of the 1991 Amendment Act provided:
For the purposes of the application of the [PRRTA Act] as amended by this Act to the Bass Strait project, any consideration received by a person before 1 July 1990 in respect of petroleum recovered on or after that day is taken to be received in the financial year in which the petroleum is recovered.
The purpose of s 33(4) was to ensure that petroleum which had not been subject to the excise and royalty regime prior to 1 July 1990 because it had not then been recovered would be subject to the PRRT regime. Section 33(4) achieved that legislative purpose by deeming consideration paid prior to 1 July 1990 in respect of petroleum recovered after that date as having been received during the year in which the petroleum is recovered.
I again rehearse the Explanatory Memorandum to the Bill which introduced the 1991 Amendment Act and explained the purpose and effect of s 33(4) as follows:
PRRT is to apply to the Bass Strait Project from 1 July 1990. Specifically PRRT will apply to petroleum recovered in respect of the Bass Strait project on or after 1 July 1990. [subclause 33(3)].
In addition only assessable receipts derived on or after 1 July 1990 will be included in the taxable profit calculation. [Clause 9 new paragraphs 31(f) and (g)].
Therefore if a person received consideration on or after 1 July 1990 from the sale of petroleum recovered prior to that date the amount received would not be an assessable receipt.
However, where consideration was received before 1 July 1990 for petroleum recovered on or after that date, the consideration is taken to be received during the year petroleum is recovered and therefore would be an assessable receipt. [Subclause 33(4)].
This provision ensures that petroleum not subject to the excise and royalty regime will be subject to PRRT.
The making of the 1987 and 1988 Shortfall Payments entitled the SECV to take Make Up Gas in the succeeding four years subject to the conditions of clause 8.1 of the SECV Agreement. The SECV exercised that entitlement in the tax years ended 30 June 1991 and 1993 by taking sales gas produced from petroleum which, it is to be inferred, was recovered after 1 July 1990 within the meaning of s 33(4) of the 1991 Amendment Act. The 1987 and 1988 Shortfall Payments therefore constituted consideration received by Esso before 1 July 1990 “in respect of petroleum recovered” on or after 1 July 1990 to the extent that Make Up Gas was taken on or after that day. Accordingly, s 33(4) of the 1991 Amendment Act requires that those payments be taken to have been received in the financial year in which the petroleum (from which the sales gas supplied to the buyer was produced) was recovered, namely 1991 and 1993.
The requirement in s 33(4) of the 1991 Amendment Act was that the Shortfall Payments be consideration received by Esso before 1 July 1990 “in respect of petroleum recovered” on or after 1 July 1990. That requirement may be satisfied provided that there is a material and relevant relationship between the petroleum recovered and the consideration.
Esso says that the Commissioner’s submissions in relation to the 1987 and 1988 Shortfall Payments is directly at odds with his submissions in relation to the 1991 and 1993 Shortfall Payments. I do not agree. The Commissioner’s submission is that the Shortfall Payments are consideration for or in relation to the gas supplied during the year in respect of which the payment was made. The transitional provision was required to deal with this situation. If s 33(4) of the 1991 Amendment Act did not exist, the 1987 and 1988 Shortfall Payments would have been consideration for or, in relation to, the gas supplied in those years. The payments would not have been subject to either the royalty regime or the PRRT regime.
GENERAL OBSERVATIONS ON EVIDENCE
A number of evidentiary issues arose in relation to documents and expert testimony. Some rulings were made during the course of the trial in respect of certain documentation.
The admissibility of other documentation was left for the Court’s final determination, as this could be dealt with conveniently as part of the determination of the questions before the Court. None of the contentious documentation has had any bearing on my consideration as is apparent from my reasons, and I need not consider individually the remaining objections to evidence not otherwise ruled upon.
However, I mention one document. A letter from R R Alderson, Assistant Secretary, Petroleum Policy Branch, to Alan Powell, Financial Controller – Australia BHP Petroleum Ltd, dated 17 May 1991 was sought to be tendered by the Commissioner. The letter completes a series of documentation otherwise admitted. I rule such letter to be relevant and admissible. Again, I do not consider the letter to have any impact on the result that I have finally reached.
Then objection was taken to the evidence of Mr Aron. I consider that none of the objections should be upheld. I make these observations. To the extent that Mr Aron gave a general description of the Gippsland facilities, these were made by reference to the practices and processes in the petroleum industry generally. Such a description is not in dispute and is otherwise proved in other evidence. It is unobjectionable. Contrary to the submission put by Esso, Mr Aron in describing the Gippsland facilities and making comments was not engaging in the exercise criticised by Wilcox J in Trade Practices Commission v Australia Meat Holdings Pty Ltd (1988) 83 ALR 299 at 316.
Where Mr Aron opined on the question whether hydrocarbon streams at various points complied with contractual specifications, this could have been relevant to the characterisation of ‘marketable petroleum commodities’ or ‘products’ as contended for by the Commissioner.
As to Mr Aron’s reliance on his own ‘experience’, Mr Aron as an expert is entitled to so rely, and indicate such reliance to the Court. His opinion as to the phrases “feedstock for conversion” was put forward as one for the Court’s determination upon its ordinary meaning but by reference to its use within the relevant industry. The evidence adduced by Mr Aron was relevant, and being based on ‘experience’, was in proper form. Section 79 of the Evidence Act1995 (Cth) does not incorporate a ‘basis’ rule, nor does it preclude a person from giving expert evidence based on experience. It is then a question of weight to be given to such evidence.
CONCLUSION
I propose to make the following orders in each proceeding:
1.The parties confer and thereafter by 4.00 pm on 29 April 2011 file minutes of orders (including as to costs), and in the event of disagreement, file and serve written submissions as to the contentions of the parties.
2.Any further directions necessary for the final determination of the proceedings be adjourned to a date to be fixed.
I certify that the preceding five hundred and sixteen (516) numbered paragraphs are a true copy of the Reasons for Judgment herein of the Honourable Justice Middleton. Associate:
Dated: 13 April 2011
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