FEDERAL COURT OF AUSTRALIA
Esso Australia Resources Pty Ltd v The Commissioner of Taxation
[2011] FCA 360
IN THE FEDERAL COURT OF AUSTRALIA | |
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 |
ESSO AUSTRALIA RESOURCES PTY LTD Applicant | |
AND: | THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA Respondent |
DATE OF ORDER: | |
WHERE MADE: |
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 Applicant |
AND: | 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.
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 Applicant
|
AND: | 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 Applicant
|
AND: | THE COMMISSIONER OF TAXATION OF THE COMMONWEALTH OF AUSTRALIA Respondent
|
JUDGE: | MIDDLETON J |
DATE: | 13 APRIL 2011 |
PLACE: | MELBOURNE |
REASONS FOR JUDGMENT
INTRODUCTION
1 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.
2 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.
3 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.
4 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
5 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.
6 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
7 The Commissioner submitted that questions 1, 3 and 6 should be answered ‘none’, making questions 2, 4, 5, 7, 8 and 9 not applicable.
8 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.
9 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.
10 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.
11 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
12 The 13 preliminary questions involve four principal categories of issues.
13 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.
14 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.
15 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.
16 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.
17 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.
18 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.
19 There are various subsidiary issues within the four principal issue categories identified above which will need to be considered.
THE GIPPSLAND FACILITIES
20 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.
21 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.
22 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.
23 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.
24 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).
25 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.
26 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.
27 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 15C 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 |
28 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+).
29 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.
30 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.
31 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.
32 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.
33 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.
34 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.
35 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’.
36 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.
37 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.
38 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.
39 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.
40 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.
41 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 |
42 In addition to hydrocarbon content the commercial products are produced to comply with buyers’ specifications.
43 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.
44 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.
45 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.
46 In addition, there are associated facilities such as the offshore control room, the marine terminal, helicopter pads and training facilities.
47 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
48 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.
49 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.
50 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.
51 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’.
52 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.
53 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.
54 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’).
55 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.
56 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.
57 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.
58 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.
59 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.
60 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.
61 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’).
62 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.
63 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’).
64 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
65 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.
66 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.
67 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.
68 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.
69 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
70 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’.
71 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.
72 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.
73 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.
74 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.
75 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.
76 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
77 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
78 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.
79 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.
80 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.
81 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
82 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
83 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.
84 From September 2000, Esso also sold gas to customers other than the GFC, Gascor or the SECV.
Propane and butane
85 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
86 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
87 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
88 I now turn to the statutory framework in which the questions for determination fall for decision by the Court.
89 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%.
90 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
91 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).
92 Part IV of the PRRTA Act defines the concept of a petroleum project.
93 The term ‘petroleum project’ is defined in s 2 to mean a petroleum project within the meaning of s 19(1) or (2).
94 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.
95 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.
96 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.
97 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.
98 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.
99 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.
100 ‘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.
101 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.
102 ‘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.
103 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.
104 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.
105 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.
106 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”.
107 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).
108 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.
109 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.
110 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.
111 There was no definition of ethane or stabilised crude oil in s 2 during the whole period.
112 No regulation was made declaring any product to be a marketable petroleum commodity for the purposes of the definition of ‘marketable petroleum commodity’.
113 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’).
114 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.
115 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.
116 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.”
117 Other than an amendment to the definition of sales gas in s 2 and to s 24, the relevant provisions and definitions remained unchanged.
118 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.
119 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.
120 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
121 I now turn to consider the extrinsic material brought before the Court by the parties. Before doing so, I make some general observations.
122 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.
123 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.
124 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.
125 Further, where legislation, as in this case, is based upon concepts related to economic theory and a change in approach to taxation, care needs to be taken in the application of that theory and comments made by various interested parties. As French J (as he then was) stated in Woodside Energy Ltd v Commissioner of Taxation (No 2) (2007) 69 ATR 465 at [203]:
An assumption that legislation which uses economic terms or concepts related to a particular economic theory or model, thereby applies the theory or model, whether it be for the purpose of regulation or tax collection, is an assumption which requires close scrutiny. Particular statutes may be based upon or inspired by economic theories or models. Their precise terms, however, may reflect policy choices or political compromises inconsistent with a complete acceptance or application of the theory or model concerned.
126 It is the terms of the legislation considered in the proper context that the Court must look to for assistance. In Carr v Western Australia (2007) 232 CLR 138 at [5]-[7], Gleeson J said:
[5] Another general consideration relevant to statutory construction is one to which I referred in Nicholls v The Queen (2005) 219 CLR 196 at 207[8]. It was also discussed, in relation to a similar legislative scheme, in Kelly v The Queen (2004) 218 CLR 216 at 225-232 [22]-[40]. It concerns the matter of purposive construction. In the interpretation of a provision of an Act, a construction that would promote the purpose or object underlying the Act is to be preferred to a construction that would not promote that purpose or object. As to federal legislation, that approach is required by s 15AA of the Acts Interpretation Act 1901 (Cth). It is also required by corresponding state legislation, including, so far as presently relevant, s 18 of the Interpretation Act 1984 (WA). That general rule of interpretation, however, may be of little assistance where a statutory provision strikes a balance between competing interests, and the problem of interpretation is that there is uncertainty as to how far the provision goes in seeking to achieve the underlying purpose or object of the Act. Legislation rarely pursues a single purpose at all costs. Where the problem is one of doubt about the extent to which the legislation pursues a purpose, stating the purpose is unlikely to solve the problem. For a court to construe the legislation as though it pursued the purpose to the fullest possible extent may be contrary to the manifest intention of the legislation and a purported exercise of judicial power for a legislative purpose.
[6] To take an example removed from the present case, it may be said that the underlying purpose of an Income Tax Assessment Act is to raise revenue for government. No one would seriously suggest that s 15AA of the Acts Interpretation Act has the result that all federal income tax legislation is to be construed so as to advance that purpose. Interpretation of income tax legislation commonly raises questions as to how far the legislation goes in pursuit of the purpose of raising revenue. In some cases, there may be found in the text, or in relevant extrinsic materials, an indication of a more specific purpose which helps to answer the question. In other cases, there may be no available indication of a more specific purpose. Ultimately, it is the text, construed according to such principles of interpretation as provide rational assistance in the circumstances of the particular case, that is controlling.
[7] As explained in Kelly and Nicholls, the general purpose of legislation of the kind here in issue is reasonably clear; but it reflects a political compromise. The competing interests and forces at work in achieving that compromise are well known. The question then is not: what was the purpose or object underlying the legislation? The question is: how far does the legislation go in pursuit of that purpose or object?
127 The observations of Gleeson CJ in Carr were referred to with approval in Alcan (NT) Alumina Pty Ltd v Commissioner of Territory Revenue (Northern Territory) (2009) 239 CLR 27 at [51].
128 This is not to say that one ignores context (see eg Network Ten Pty Ltd v TCN Channel Nine Pty Ltd (2004) 218 CLR 273). Just that the Court needs to be careful in what it concludes to be the proper context for the purposes of determining the intent of the Parliament.
129 When talking in terms of the intent of the Parliament, I am mindful of the comments of Gleeson CJ in Singh v Commonwealth of Australia (2004) 209 ALR 355 at [19]:
Acknowledging that “[i]ntention of the Legislature” is a “very slippery phrase”, courts, and parliament itself, refer to “intention” or “intent” in stating rules and principles of statutory interpretation … In Sovar v Henry Lane Pty Ltd (1967) 116 CLR 397 at 405, Kitto J warned that the intention that such a private right shall exist is not conjured up by judges to give effect to their own ideas of policy, and then imputed to parliament. “The legitimate endeavour of the courts is to determine what inference really arises, on a balance of considerations, from the nature, scope and terms of the statute, including the nature of the evil against which it is directed, the nature of the conduct prescribed, the pre-existing state of the law, and, generally, the whole range of circumstances relevant upon a question of statutory interpretation … It is not a question of the actual intention of the legislators, but of the proper inference to be perceived upon a consideration of the document in the light of all its surrounding circumstances.” In Wilson v Anderson (2002) 213 CLR 401 at 417-19 [7]-[10]. I sought to explain the objectivity of the concept of intention, comparing the position with respect to construction of a contract, and stressing that the exercise is not formal or literalistic but demands consideration of background, purpose and object, surrounding circumstances, and other matters which throw light on the meaning of unclear language. The danger to be avoided in references to legislative intention is that they might suggest an exercise in psychoanalysis of individuals involved in the legislative process; the value of references to legislative intention is that they express the constitutional relationship between courts and the legislature. As Kitto J said, references to intention must not divert attention from the text, for it is through the meaning of the text, understood in the light of background, purpose and object, and surrounding circumstances, that the legislature expresses its intention, and it is from the text, read in that light, that intention is inferred. The words “intention”, “contemplation”, “purpose”, and “design” are used routinely by courts in relation to the meaning of legislation. They are orthodox and legitimate terms of legal analysis, provided their objectivity is not overlooked.
130 In the task of ascertaining the “intention of the legislature” I consider that it would be inappropriate to take the opinion of any Minister, government official or committee as to the particular meaning or application of any legislative provision as being capable of assisting in the constitutional task that is imposed on the Court of construing and applying any particular legislative provision – see the comments of Lord Wilberforce in Black-Clawson International Ltd v Papierwerke Waldhof-Aschaffenburg AG [1975] AC 591, at 629-30.
131 In any event, as in this case, material of that kind sometimes sought to be relied upon as assisting in the interpretative process, is often vague and uncertain and at such a level of generality to be unhelpful.
132 Much debate took place over the admissibility of some of the extrinsic material, the weight to be given to it, and the extent to which it was capable of assisting in the ascertainment of the meaning of the legislative provisions in dispute.
133 Extrinsic material needs to be tendered into evidence. In most instances, this is done by consent or without objection and without any formal proof of the document itself. However, to be tendered into evidence, the extrinsic material must be relevant: see s 55 and s 56 of the Evidence Act 1995 (Cth).
134 Section 15AB of the Acts Interpretation Act 1901 (Cth) then deals with the use of the extrinsic material in the interpretation of an Act. It is to be recalled that the purposive interpretation has already been mandated by s 15AA.
135 Section 15AB deals with the use of extrinsic material in the interpretation of an Act. It provides, inter alia:
(1) Subject to subsection (3), in the interpretation of a provision of an Act, if any material not forming part of the Act is capable of assisting in the ascertainment of the meaning of the provision, consideration may be given to that material:
(a) to confirm that the meaning of the provision is the ordinary meaning conveyed by the text of the provision taking into account its context in the Act and the purpose or object underlying the Act; or
(b) to determine the meaning of the provisions when:
(i) the provision is ambiguous or obscure; or
(ii) the ordinary meaning conveyed by the text of the provision taking into account its context in the Act and the purpose or object underlying the Act leads to a result that is manifestly absurd or is unreasonable.
(2) Without limiting the generality of subsection (1), the material that may be considered in accordance with that subsection in the interpretation of a provision of an Act includes:
(a) all matters not forming part of the Act that are set out in the document containing the text of the Act as printed by the Government Printer;
(b) any relevant report of a Royal Commission, Law Reform Commission, committee of inquiry or other similar body that was laid before either House of the Parliament before the time when the provision was enacted;
(c) any relevant report of a committee of the Parliament or of either House of the Parliament that was made to the Parliament or that House of the Parliament before the time when the provision was enacted;
(d) any treaty or other international agreement that is referred to in the Act;
(e) any explanatory memorandum relating to the Bill containing the provision, or any other relevant document, that was laid before, or furnished to the members of, either House of the Parliament by a Minister before the time when the provision was enacted;
(f) the speech made to a House of the Parliament by a Minister on the occasion of the moving by that Minister of a motion that the Bill containing the provision be read a second time in that House;
(g) any document (whether or not a document to which a preceding paragraph applies) that is declared by the Act to be a relevant document for the purposes of this section; and
(h) any relevant material in the Journals of the Senate, in the Votes and Proceedings of the House of Representatives or in any official record of debates in the Parliament or either House of the Parliament.
(3) In determining whether consideration should be given to any material in accordance with subsection (1), or in considering the weight to be given to any such material, regard shall be had, in addition to any other relevant matters, to:
(a) the desirability of persons being able to rely on the ordinary meaning conveyed by the text of the provision taking into account its context in the Act and the purpose or object underlying the Act; and
(b) the need to avoid prolonging legal or other proceedings without compensating advantage.
136 The classes of extrinsic material enumerated under s l5AB(2), to which regard may be had, do not include all the classes of material sought to be made available in these proceedings. However, what is enumerated in subs (2) does not limit the classes of material to which regard may be had under subs (l). The limiting factor in determining the material to which regard may be had under subs (l) is that it be “capable of assisting in the ascertainment of the meaning of the provision”.
137 I observe that the common law will also apply: see Pearce and Geddes, Statutory Interpretation in Australia (6th ed, Butterworths, 2006) at para [3.7]. However, I do not consider the common law has any impact on the position as far as these proceedings are concerned.
138 Much of the extrinsic material brought before the Court included background material to the PRRTA Act and amending legislation. Some of the material was relied upon by French J (as he then was) in Woodside Energy, and on the basis of that decision I allowed similar material to be admitted into evidence. Of course, that does not necessarily mean that now that I come to determine the proper interpretation and application of the PRRTA Act that such material will ultimately be of assistance in the ascertainment of the legislative meaning, or that any weight should necessarily be given to such material. The approach I adopt in these reasons is to consider the material addressed in the submissions on the basis that it is admissible, but then to consider whether it is of assistance in fact to the task the Court has in interpreting the PRRTA Act and considering its operation to the facts that I have found in these proceedings.
Background and Extrinsic Material Relied upon by the parties
139 I now go to the background to the legislative provisions and the extrinsic material relied upon by the parties.
140 Prior to the introduction of the PRRTA Act and related legislation, onshore and offshore petroleum in Australia was subject to State and Commonwealth royalty and excise regimes.
141 Crude oil and LPG were subject to an ad valorem excise levied by the Commonwealth. In the case of crude oil, for example, the excise was levied as a percentage of the volume weighted average of realised Free On Board prices (or ‘VOLWARE price’) of all sales made from crude oil produced from certain areas after the first 30 million barrels, which were exempt from excise. Different rates of excise were levied depending on the date on which the petroleum pools from which the oil was produced had been discovered and developed with lower rates on “new oil” in order to encourage new production.
142 Petroleum production was subject to royalties levied by the States and the Northern Territory in respect of onshore production and offshore production in the territorial sea and by the Commonwealth in respect of offshore production beyond the territorial sea. Revenues derived by the Commonwealth in respect of offshore petroleum production were shared with the relevant State governments. The royalty was a fixed percentage of the “wellhead value” of the petroleum which was calculated, in general terms, as the sales receipts less certain deductions for costs incurred in bringing the petroleum from the wellhead to the point of sale (including excise).
143 A Discussion Paper released by the Commonwealth Government in December 1983 (‘the December 1983 Discussion Paper’) in relation to the proposed introduction of the PRRT system, described the perceived deficiencies of the royalty and excise regime in the following terms:
[10] … The existing excise arrangements remain deficient in a number of respects. In particular, the excise is based on production rather than profits or capacity to pay and while larger fields tend to be more profitable than small fields this is not always the case. Projects earning comparable profits can pay widely divergent levels of production or mixes of ‘old’ and ‘new’ oil. Marginal projects which might otherwise have been undertaken can be discouraged and some petroleum that would otherwise be extracted economically is left in the ground.
…
[12] State Government imposts in the petroleum sector are mostly in the form of ad valorem royalties calculated as a percentage of wellhead value. As such they fail to allow adequately for the different characteristics of projects which result in some projects being much more profitable than others.
144 It must be noted that the December 1983 Discussion Paper did not purport to be the Government’s final position. It was to be the basis for consultation.
145 In the December 1983 Discussion Paper, the Government proposed the introduction of a resource rent tax in relation to offshore petroleum projects which would be imposed on the achieved profits of a project where those profits exceeded some minimum or threshold level. The proposed resource rent tax was intended to be a more economically efficient and equitable means of achieving an appropriate balance between the need to provide sufficient economic incentive for the exploration and development of petroleum resources, including the development of marginal fields, and the community’s entitlement to receive an adequate share of the profits derived from the exploitation of the country’s mineral resources.
146 The December 1983 Discussion Paper gave the following description of the scope of the proposed tax:
[31] It is envisaged that the tax would apply to profits derived from activities within the boundaries of petroleum development projects. The objective would be that only those expenditures necessary to produce a marketable commodity, and so realise the resource rent, would be allowable as deductions against revenue from the sale of that commodity; the RRT is not meant to go beyond this production stage. In applying those boundaries, it would be necessary to accord parallel treatment to income and expenditure items.
147 In addition the December 1983 Discussion Paper stated:
[32] The definition of what constitutes a “project” under a project basis of assessment will be an important matter for discussion. The following broad principles appear relevant to the determination of an acceptable definition:
• the project should represent an integrated investment (and could include a number of proximate fields if their development is mutually inter-dependent);
• the output of a project should be a marketable petroleum commodity; and
• the project’s scope could include certain related infrastructure where this was integral to the production of a marketable commodity.
148 In April 1984, the Treasurer and the Minister for Resources and Energy announced the Government’s intention to introduce a resource rent tax applicable to “greenfields” offshore petroleum projects. Attached to the press release was a paper outlining the operation of the proposed tax (‘the April 1984 Discussion Paper’). In describing the tax unit of the proposed RRT, the paper stated:
The RRT will be assessed on a project basis... [T]he basic principles are that:
• the project would represent an integrated investment (and could include a number of proximate fields if their development is mutually inter-dependent). Broadly, an integrated investment would be determined by production licence areas and would also include treatment and other facilities and operations outside licence areas that are integral to the production of a ‘marketable’ petroleum commodity;
• project boundaries would not extend beyond the petroleum production stage to downstream activities such as refineries and facilities for transporting ‘marketable’ products;
• the output of a project would be a ‘marketable’ petroleum product. A product would be treated as ‘marketable’ at the first point in the production process at which it is saleable commercially, even though an actual sale may not have taken place.
149 A further Joint Press Release by the Treasurer and the Minister for Resources, in June 1984, outlined the principal policy elements of the proposed RRT arrangements (‘the June 1984 Joint Statement’). It described the tax base in terms similar to the April 1984 Discussion Paper set out above. It stated:
The RRT will be assessed on a project basis... [t]he basic principles are that:
• the project will represent an integrated investment and could include a number of proximate fields. Broadly, the boundaries of an integrated investment will comprise a production licence area and treatment and other facilities and operations outside that area which are integral to the production of a ‘marketable’ petroleum product;
• the taxable output of a project (that is, the ‘marketable’ petroleum product) will be treated as ‘marketable’ for assessment purposes at the first point in the production process at which it is saleable commercially, even though an actual sale may not have taken place at that point;
• if no sale takes place at that point, or where a non-arm’s length sale occurs, an income value will be attributed to the product at the RRT assessment point;
• project boundaries for RRT assessment will not extend beyond the petroleum production stage to downstream activities such as refineries and facilities for transporting ‘marketable’ products. This means that neither expenditure on downstream activities, nor value added to products through those activities, will be taken into account in calculating liability for RRT;
• the scope of the project expenditure and income to be taken into account will encompass certain infrastructure where this is integral to the production of a ‘marketable’ product…
150 Attachment 1 to the June 1984 Joint Statement provided a further description of the assessable receipts and deductible expenditures for the proposed resource rent tax. It stated, in part:
Assessable receipts for RRT purposes will include the following:
• receipts from the sale of a marketable petroleum product (including crude oil, condensate, natural gas, LPG and ethane) derived from the project, where sale occurs at the point at which the product is first marketable commercially and the sale is on an arm’s length basis. If no sale takes place at that point, or where a non-arm’s length sale takes place, a taxable value will be attributed to the product on the basis of its market value having regard to recognized markets;
...
Other deductible project expenditures will generally comprise those in respect of a production licence area and expenditures outside that area necessary to obtain a marketable petroleum product.
Some indicative examples of the kinds of expenditures which will be allowed as deductions are:
• expenditure on production platforms, drilling plant and equipment and overheads at the wellhead;
• expenditure on pipelines and other facilities (including tankers dedicated to the project) for transporting petroleum from the wellhead to a mainland reception point or to a point of further treatment as described hereunder;
• expenditure on plant for use in treatment processes necessary to produce a marketable petroleum product, eg expenditure on a crude oil stabilisation plant, or a gas liquids fractionation plant …
151 In late 1984 or early 1985 the drafting of the PRRTA Act commenced. In late 1985 the Petroleum Revenue Act 1985 (Cth) was passed into law. The purpose of this Act was to encourage State governments to introduce resource rent taxes and for that revenue to be shared with the Commonwealth in exchange for the Commonwealth waiving its right to impose excise duty. As the Explanatory Memorandum to the Bill introducing that legislation provided:
On 25 June 1985 the Minister for Resources and Energy, Senator Evans and the Western Australian Premier, announced agreement to arrangements to introduce a Resource Rent Royalty (RRR) for petroleum produced from Barrow Island and to the introduction of general legislation offering all States the opportunity of introducing a RRR …
This Bill provides for the Commonwealth to consider waiving its right to levy excise if:
• a State and producers have entered into a relevant RRR agreement;
…
• a State has requested the Commonwealth to enter into a relevant revenue-sharing agreement in relation to royalty paid under the resource rent agreement.
152 Undoubtedly this Act has some of the features of a resource rent tax of the kind described above in the extrinsic materials. It was the Commonwealth’s first enactment of a resource rent tax, albeit in the form of a sharing of revenue for projects taxed by a State using a resources rent tax. Thus s 5 provided:
Where:–
(a) a State and the person or persons who produce market petroleum from a production unit have entered into a relevant resource rent royalty agreement providing for a royalty in respect of market petroleum produced from that unit on or after 1 July in a year after 1984 specified in the agreement; and
(b) the State requests the Commonwealth to enter into a relevant revenue-sharing agreement in respect of royalty payable under that relevant resource rent royalty agreement;
the Minister may arrange for the Commonwealth to enter into that relevant revenue-sharing agreement with the State.
153 Schedule 1 of that Act defined a ‘relevant resource rent royalty agreement’ as one providing for the payment of a ‘royalty’ to the “State in respect of the market petroleum produced from a production unit specified in the agreement …”. The rate payable was “40% of the accumulated net receipts from the relevant petroleum disposed of in that year”.
154 The term ‘petroleum’ was defined in s 3 broadly by reference to its meaning in the PSLA. The term ‘market petroleum’ was defined as follows:
market petroleum means:–
(a) petroleum in a form in which petroleum is commonly sold; or
(b) a product that is derived from petroleum and is of a kind that is commonly sold; but does not include petroleum, or a product, that is derived from petroleum to which paragraph (a) applies or from a product to which paragraph (b) applies.
155 It was submitted by Esso that the foregoing reveals that in the early to mid 1980s:
(a) the intention was to enact a RRT which taxed producers by reference to the net profit whether realised or unrealised from particular projects;
(b) the outer-bounds of the project were expected to be whenever a petroleum product was sold or first produced in a “commercially saleable” form; and
(c) there were words and phrases that were both known and available which could delineate these intentions for the purposes of drafting RRT legislation.
156 Then it was contended by Esso that these elements were reflected in an early draft of the PRRTA Act prepared in early 1985.
157 The first draft required a taxpayer to bring to account “the gross proceeds from marketable prescribed resources of the taxpayer in respect of the prescribed resource project for the year of income” (cl 11(1)(a)). The term ‘gross proceeds from marketable prescribed resources’ was defined in cl 11(2) as follows:
(a) in the case of marketable prescribed resources which have been sold during any year of income being prescribed resources which have been sold at arm’s length at or prior to the point where they were first commercially marketable – the gross proceeds received during the year of income from the sale of those marketable prescribed resources; and
(b) in the case of marketable prescribed resources not included in paragraph (a) which have become marketable prescribed resources during the year of income – the market value of those prescribed resources at the time when they became marketable prescribed resources.
158 The term ‘marketable prescribed resource’ was defined in cl 3 as follows:
marketable prescribed resource means a prescribed resource which:–
(a) has been sold at arm’s length for a consideration which, in the opinion of the Commissioner, is the arm’s length consideration of that resource; or
(b) has reached a point in processing where it is first commercially marketable.
159 The term ‘prescribed resource’ was defined in cl 3 as follows:
prescribed resource means petroleum, being petroleum obtained from prescribed resource operations, including:
(a) crude oil;
(b) condensate;
(c) natural gas;
(d) liquid petroleum gas; and
(e) ethane.
160 None of these resources was separately defined in this early draft. The term ‘prescribed resource operations’ was, however, defined as follows:
prescribed resource operations means mining operations for the extraction of one or more prescribed resource from its natural site, being operations carried on within a prescribed area of Australia.
161 The first draft of the PRRTA Bill defined ‘marketable prescribed resources’ by reference to an actual sale or by the ‘point in processing’ where it is ‘first commercially marketable’. It also had an inclusive definition of ‘marketable prescribed resource’ which expressly referred to “natural gas”.
162 It was submitted by Esso that these words and concepts were never enacted and were removed from the draft PRRTA Bill in favour of the specific and exhaustively defined products ultimately enacted. Esso contended that ‘marketability’ as a concept was discarded because the designers of the PRRTA Act and Parliament ultimately recognised the difficulty of knowing when a product might or might not be marketable and favoured instead clear technical definitions. Esso then referred to various letters and file notes:
(i) in a letter written to the Department of Resources on 27 November 1984 from Assistant Commissioner Lennon of the Australian Taxation Office (‘the ATO’), there is recorded the expectation that the PRRTA Act will contain a definition of ‘prescribed resources’ referring to specific products. The letter asks whether it is “possible to specify each product which will be subject to RRT” and whether it is “possible to specify the point, in time or processing, at which the product becomes commercially marketable”;
(ii) a reply to this letter was given by the Department of Resources and Energy on 21 December 1984. The Department set out the two competing views as to the scope of projects that would come within the RRT tax net. The ATO’s view was “that projects will be defined for RRT purposes in physical terms in relation to technical features of a defined list of petroleum projects, and that such a definition would be applied to all projects.” The Department was concerned not to have “restrictive physical definitions of products and boundaries”. In an attachment to the letter of 21 December 1984 the Department responded to the ATO request to define ‘petroleum products’. It listed a series of “petroleum products which might be marketed”. This included “unprocessed natural gas (mainly methane, or methane and ethane)”. The attachment records the observation that “[i]t would be difficult to give an exhaustive and technical definition of the petroleum products likely to be marketed from a petroleum project” and suggested “that a general definition of ‘petroleum’ be included”. It is then stated:
Defining a point at which products become marketable would vary from project to project. We are working on some guidelines which attempt to define the maximum acceptable point at which a product may be marketed, however, it is inevitable that a final ‘catch-all’ such as ‘such other point as may need to be determined’ will be necessary.
(iii) in January 1985 the ATO sent further drafting instructions to the Office of Parliamentary Counsel (‘the OPC’) with a copy to the Department. On page 4 of that letter clarification concerning the criterion for liability by reference to ‘marketability’ was raised. It stated:
Another matter which will require clarification is whether there is a need to specify the point at which products become commercially marketable. The draft provisions so far merely refer to a liability arising at the point of sale or the point at which the product first becomes commercially marketable, whichever occurs first … We had it in mind that, if possible, the point at which various products would normally become commercially marketable should be specified in the legislation to create certainty both for taxpayers and the Commissioner … However, in discussions with officers from that Department [of Resources and Energy] it became clear that that ‘point’ was likely to differ from project to project and even over time within a project. It may well be that the provisions already drafted will be the way to go in view of the information provided by Resources and Energy but, in the upshot, it may be necessary to seek further advice from Ministers.
(iv) in an ATO file note dated “June 1985” Mr Farrell of the ATO records the contents of a telephone conversation during which the difficulties associated with the ‘marketable’ test were again considered. The ATO view was:
that each case would need to be judged on its facts. For example, I said that oil in the ground may be commercially marketable if there is a severe shortage such as in the early 70s and people are actually contracting to take oil before it is produced. And I noted that we had been informed that circumstances change even from day to day on the same platform.
Mr Farrell then noted that the intention was to put a clear definition of the relevant products into the legislation.
163 Esso contended that the above “dialogue” indicated:
that the drafters were trying to find the words which would clearly identify the taxing ‘point’. That point was not synonymous with the sale of a product. Even at this early stage, it has contemplated that the taxing ‘point’ might be reached before sale;
that using marketability as the measure for identification was unsatisfactory: it lacked certainty because the issue of marketability “was likely to differ from project to project and even over time within a project” (quoting the ATO drafting instructions referred to above);
that unprocessed natural gas could be a marketable commodity; and
that the preference was to clearly define the relevant ‘products’ by reference to technical definitions.
164 A further draft PRRTA Bill was prepared by 30 September 1986. A concept of ‘first marketable point’ was used. Thus:
A. Clause 15 provided that:
For the purposes of this Part, a reference to the assessable petroleum receipts of a petroleum project, is a reference to the sum of –
(a) where any petroleum recovered from the production licence area or areas in relation to the project is sold [disposed of? To cover gifts] at or before its first marketable point – the consideration for the sale …
(b) in the case of any other petroleum recovered from the production licence area or areas in relation to the project that reaches its first marketable point – the market value of the petroleum at that point …”
B. Clause 2 contained these definitions:
‘first marketable point’, in relation to petroleum or petroleum of a particular kind, means such point as is declared by regulations for the purposes of this definition to be the first marketable point in relation to petroleum or petroleum of that kind, being –
(a) the point at which the petroleum leaves the well-head [define along lines of s 8 of the Royalty Act?]; or
(b) a point in the processing or treatment of petroleum or petroleum of that kind after it leaves the well-head.
[Should the provision allow any other means of specifying the point eg by reference to ‘transportation, storage or other criteria’ See Notes]
…
‘petroleum’ has the same meaning as in the [PSLA].
165 The Petroleum Resource Rent Tax Assessment Bill 1986 (‘the 1986 Bill’) was introduced into Parliament in November 1986. The Explanatory Memorandum to the 1986 Bill stated, amongst other things, that the Bill:
identifies the receipts – or, in the case of certain petroleum products that have not been sold by the point in the production process at which they become marketable, amounts deemed to be receipts – that are to be assessable for PRRT purposes.
166 I also observe that the 1986 Bill contained the same definitions of ‘petroleum’, ‘marketable petroleum commodity’ and ‘sales gas’ as first enacted in the PRRTA Act. However, cl 24 differed in two significant respects from the form in which it was ultimately enacted. First, cl 24(c) of the 1986 Bill provided that the disposal of petroleum, or a constituent of petroleum, whether processed or unprocessed, otherwise than by sale or destruction, should still give rise to an assessable receipt, calculated by reference to the market value of such petroleum. Secondly, cl 24 did not employ any concept of ‘excluded commodity’. In so far as cl 24 applied to marketable petroleum commodities, it would have fixed the assessable petroleum receipts derived by a taxpayer from the production of marketable petroleum commodities as follows:
where any marketable petroleum commodity “is or was sold at or immediately after the point at which it is or was produced – the consideration received by the person for the sale”: see cl 24(b); and
where any marketable petroleum commodity “is or was not sold at or immediately after the point at which it is or was produced – so much of the market value of the commodity at that point, or, where there is insufficient evidence of that market value, of such amount as, in the opinion of the Commissioner, is fair and reasonable…”: see cl 24(d).
167 After the 1986 Bill was introduced into Parliament, the Government received submissions from BHPBP and the Australian Petroleum Exploration Association Ltd (‘APEA’) which argued, inter alia, that the Bill as then drafted could have the effect of excluding from the scope of the petroleum project the costs of any on-site storage of a marketable petroleum commodity. BHPBP in its submission, stated:
Storage facilities
To be deductible, storage facilities must come under the definition of General Project Expenditure (clause 38) i.e., … expenditure incurred by a person in relation to a petroleum project … clause 19(4) defines the reference to operations facilities and other things and it limits the expenditure to the point at which marketable petroleum is produced. Because of this, costs incurred in storage of product after it reaches a marketable state would not be deductible. Such an interpretation would appear anomalous as the produce in the storage facility (i.e. stock on hand) is to be assessable).
168 APEA’s submission stated:
9. Allowable Project Expenditure – Clause 19
The definition of a petroleum project in Clause 19 limits the allowable project expenditure to that incurred up to the first point of production of a marketable petroleum commodity. This would exclude any deductions for transport to a point of shipment outside the licence area and of storage and landing facilities at a terminal.
While APEA agrees that downstream activities such as refineries and petrochemical plants should be excluded, activities which are clearly upstream and are essential to the production and storage of marketable petroleum commodities from a particular project should be allowed. Disallowing such deductions is totally inconsistent with the cash flow basis of the tax and the contention that the tax is profit-related.
169 The APEA submission also raised the concern that the 1986 Bill may result in petroleum production that was re-injected, flared or used for the purposes of a project. It said:
13. Conflict of Definition of ‘Petroleum’ & Clause s 24(c) & 25(c)
There appears to be a conflict between the definition of ‘Petroleum” and Clauses 24(c) and 25(c) of the Bill. The Bill states that ‘Petroleum’ should have the same meaning as that contained in the Petroleum (Submerged Lands) Act. The definition of ‘Petroleum’ in the P(SL) Act includes re-injected gas, liquids, etc.
As Clauses 24(c) and 25(c) deem a sales value for RRT purposes for any ‘Petroleum’ recovered but disposed of ‘otherwise than by sale or destruction’, it is possible that re-injected gas, liquids, flared and own-use product, petroleum recovered and taken for testing, etc. could be subject to RRT upon initial production, and where applicable again on any subsequent production. APEA recommends that the Act be amended to specify that the application of Clauses 24(c) and 25(c) excludes re-injected gas, liquids, flared and own-use product, petroleum recovered and taken for testing, etc.
170 BHPBP’s submission referred to the potential effect of cl 24(c) on “production which is flared or which is used in the production process”. It did not refer to production which is re-injected. The problem that was identified with the 1986 Bill in its original form was therefore that it contemplated that petroleum, whether processed or unprocessed, which was used for re-injection or flaring, etc, would be assessable.
171 In response to these submissions, the ATO agreed that these potential consequences of the 1986 Bill as then drafted were unintended and that the Bill should be amended. In a Minute to the Treasurer dated 4 March 1987, Senior Assistant Commissioner of the ATO stated:
Recommendations
It is recommended that you agree to amendments of the Bill to –
…
• provide for the bringing to account of the value of an unsold marketable petroleum commodity stored in an on-site storage facility only after the commodity has left that facility (paragraphs 21 and 22) and for the deductibility of on-site storage facilities and of other costs of selling a marketable petroleum commodity (paragraphs 23 and 24); and
• not bring to account the value of a marketable petroleum commodity that is re-injected, flared-off or provided for own use on the project (paragraphs 33 and 34).
172 The ATO subsequently sent drafting instructions to the OPC for amendments to the 1986 Bill to provide for:
• the bringing to account of the value of an unsold marketable petroleum commodity that is stored in an on-site storage facility, only after the commodity has left that facility; and
• non-assessability of the value of a marketable petroleum commodity that is re-injected, flared-off or provided for own use on the project.
173 Amendments to the 1986 Bill were subsequently introduced into Parliament. The amendments introduced the concept of an excluded commodity into the 1986 Bill and brought cl 24 into the form in which it was ultimately enacted. The introduction of the concept of an excluded commodity ensured that marketable petroleum commodities stored in on-site or adjacent storage facilities would not become assessable until they were either sold or otherwise excluded from the project and that the costs of such storage would be deductible. In moving the amendments, the Minister stated:
Following introduction of this Bill during the 1986 Budget sittings, representations have been made by the petroleum industry seeking various amendments of the Bill. After consideration of those representations, the Government has agreed to certain amendments that will clarify the intended operation of the Bill and ease the administrative burden on the industry…
A further significant amendment to which the Government has agreed is the shift in the point at which the value of a marketable petroleum commodity becomes assessable. This amendment will allow such a commodity to be stored prior to sale in an on-site storage facility without its value being brought to account as an assessable receipt at that point. An assessable receipt will in these circumstances arise only when the commodity is sold or moved from on-site storage, other than for re-injection, destruction or use on the project. Expenditure associated with an on-site storage facility will, by further amendment, qualify for deduction, as will expenses such as freight, insurance and demurrage in relation to the sale of a marketable petroleum commodity.
174 The amended 1986 Bill subsequently lapsed when Parliament was dissolved for the 1987 federal election.
175 However, Esso’s main contention was that by the time the 1986 Bill was presented to Parliament in November 1986, there was a preference for the “bright lines” of listing exhaustively the ‘products’ to be taxed and defined, where necessary, by reference to chemical composition or by the use of clearly understood terms such as ‘stabilised crude oil’, thus securing maximum certainty. In essence, ‘marketability’ was not to be incorporated within the operation of s 24, nor within the definition of ‘marketable petroleum commodity’.
176 The Petroleum Resource Rent Tax Assessment Bill 1987 (‘the 1987 Bill’) was introduced into Parliament in 1987 in the same form as the amended 1986 Bill.
177 The Explanatory Memorandum to the 1987 Bill stated, in describing the main features of the Bill, that “[u]nlike royalty and excise arrangements, the petroleum resource rent tax is profit-based, rather than being based on production. It will apply only where there is an excess of project-related receipts for a financial year over – project-related expenditure for the year” and other types of expenditure.
178 In describing the concept of a petroleum project, the Explanatory Memorandum to the 1987 Bill stated:
Petroleum projects
(Clauses 19 and 20)
The petroleum resource rent tax is to apply to taxable profits from a petroleum project… A petroleum project can only exist when a production licence comes into force and, broadly, will consist of the production licence area, as well as treatment facilities and other facilities and operations outside that area which are integral to the processes for production and initial on-site storage of a marketable petroleum commodity…
The boundaries of a petroleum project will not extend beyond the point at which a marketable petroleum commodity is initially stored after production. That is, the project boundaries will not extend to “downstream activities” such as refineries and facilities for the transport of marketable products from that storage.
…
The concept of the petroleum project is fundamental to the Bill as petroleum resource rent tax is to be assessed on a project basis.
…
PART IV – PETROLEUM PROJECTS
As petroleum resource rent tax is to be assessed on a project basis, the concept of a petroleum project is an essential aspect of the tax. This Part provides the rules by which the project and its boundaries will be determined. Broadly, a petroleum project will exist in relation to a production licence area and will comprise recovery, treatment and other facilities and operations which are integral to the production and initial onsite storage of a marketable petroleum commodity. The project boundary will not extend beyond the point at which a marketable petroleum commodity is initially stored, on-site, after production.
179 The Second Reading Speech was largely identical to the Second Reading Speech for the 1986 Bill (prior to amendment). In the Second Reading Speech, the Minister for Primary Industries and Energy stated:
The Petroleum Resource Rent Tax Assessment Bill is the first in a package of four Bills that will give effect to the Government’s decision to introduce a petroleum resource rent tax on profits from certain off-shore petroleum projects. The proposed tax regime was announced in detail in June 1984, after extensive consultation with the industry and the States. These Bills are now being reintroduced in the same form in which they were before the Senate when Parliament was dissolved for the election and the Bills consequently lapsed.
… The Government believes that a resource rent tax related to achieved profits is a more efficient and equitable secondary taxation regime than the excise and royalty system that it is to replace. I emphasise that the proposed tax replaces the existing system – it is not in addition to it.
… The provisions of the Bill, … follow closely the proposal as announced in June 1984.
…
In broad terms, a petroleum project incorporates the production licence area, and such treatment and other facilities and operations outside that area as are integral to the production and initial on-site storage of marketable petroleum commodities such as stabilised crude oil, condensate and liquefied petroleum gas…The boundaries of a petroleum project will not extend beyond the point at which a marketable petroleum commodity is initially stored after production – that is, the project boundaries will not extend to ‘downstream activities’ such as refineries and facilities for the transport of marketable products from initial storage.
Assessable Receipts
Liability for petroleum resource rent tax is to be assessed on the accruals basis that generally applies in determining income tax liability. Assessable receipts from the project will, therefore, be taken into account in the financial year in which they are receivable. Assessable project receipts will include amounts receivable from the sale of petroleum or of a marketable petroleum commodity. In the event that a marketable petroleum commodity is not sold after the point of initial on-site storage, the market value – or a fair and reasonable value – of the commodity will be treated as an assessable receipt of the project. The need to attribute a value could arise, for example, in the case of an integrated producer which both extracts crude oil and refines it.
Deductible Expenditure
…
General project expenditure comprises expenditure on a production licence area, or combined production licence areas, on the establishment of a project, on recovering and producing a marketable petroleum commodity and on storing that commodity adjacent to the production site. It includes relevant expenditure on storage and processing facilities and employee amenities.
180 The reference to the announcement made in June 1984 is a reference to the June 1984 Joint Statement by the Treasurer and the Minister for Energy and Resources, referred to above.
181 As I have said, the PRRTA Act was subsequently enacted in December 1987 and commenced operation in January 1988.
182 At the time of its enactment, the PRRTA Act did not apply to the Gippsland facilities or the Bass Strait project, which had been conducted by Esso and BHPBP since the late 1960s. The April 1984 Discussion Paper stated that the inclusion of the project would have resulted in “considerable disturbance to existing working arrangements”. However, the Bass Strait project was subsequently brought under the PRRTA Act, with effect from 1 July 1990, by the enactment of the Petroleum Resource Rent Legislation Amendment Act 1991 (Cth) (‘1991 Amendment Act’).
183 The extension of the PRRT regime to Bass Strait was announced in the 1990-1991 Budget Statements. A Joint Statement by the Treasurer and the Minister for Resources stated:
The RRT will replace the excise and royalty charges currently levied on petroleum production in Bass Strait. The new tax will be a 40 per cent charge on net revenues after exploration and development costs have been deducted. Excise charges are currently levied on production volumes.
The Ministers noted that the RRT will be more efficient than the excise and royalty arrangements by not distorting production and investment decisions by the industry. Because the tax is based on profits, it will be sensitive to changes in prices and costs. This flexibility will remove the need for continuous changes in excise rates as production declines or market conditions vary.
184 The Explanatory Memorandum to the Petroleum Resource Rent Legislation Amendment Bill 1991 stated that ‘petroleum project’ was to incorporate “the production licence area and such treatment and other facilities and operations outside the area as are integral to the production and initial on site storage of marketable petroleum commodities; which include crude oil, natural gas, condensate, LPG and ethane.” The Explanatory Memorandum described the effect of the proposed amendments as follows:
The majority of offshore petroleum production in Australia beyond the territorial sea is subject to PRRT. The offshore areas presently excluded from PRRT are the Bass Strait and North West Shelf production licence areas and associated exploration permit areas. Where PRRT applies, it replaces the excise and royalty regime.
…
This Bill will make changes to the Petroleum Resource Rent Tax Assessment Act 1987 … to extend the petroleum resource rent tax (PRRT) to the Bass Strait production licences and the unrelinquished areas of the associated permit VIC/P1.
…
A single project will be taken to exist in respect of all production licences drawn from the Bass Strait exploration permit VIC/P1. This is in contrast to the current rule that each production licence is treated as a single petroleum project.
…
185 In the Second Reading Speech for the Bill, the then Treasurer said that the purpose of the extension of the PRRT regime to the Bass Strait project was “to promote the optimal recovery of Bass Strait petroleum reserves.”
186 One further aspect of the enactment of the 1991 Amendment Act, relevant to Questions 11 and 12 (the take or pay issue), may be noted. On 4 March 1991, the OPC provided to the ATO a draft of the Bill that became the 1991 Amendment Act. The draft Bill contained a transitional clause relating to the application of the PRRT regime to the Bass Strait project. A note under the draft transitional clause raised the following query:
Could receipts be derived before 1 July 1990 in respect of Bass Strait petroleum recovered after that day? If so, may need a provision taking the receipts to be derived in the financial year in which the petroleum is recovered.
187 In a letter dated 12 March 1991 to the OPC, the Department of Primary Industries and Energy responded to the OPC’s query. It stated:
Discussions with Victorian Government officials confirm that there are instances where Bass Strait petroleum has been paid for but not recovered as of 1 July 1990. The case so far identified relates to commercial gas (natural gas) purchased under a take-or-pay contract between the Bass Strait producers and the State Electricity Commission of Victoria (SECV), under which the SECV has paid for gas that it has not taken (the gas has not been recovered). As the draft Bill now stands this would place the gas paid for but not taken outside the reach of both royalty and RRT.
We are taking up with Victoria whether there might be other instances where Bass Strait petroleum has been paid for but not recovered prior to 1 July 1990.
188 Clause 33(4) was subsequently added to the 1991 Bill. It 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.
189 The Explanatory Memorandum to the 1991 Bill 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. [sub-clause 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. [Sub-clause 33(4)]
This provision ensures that the petroleum not subject to the excise and royalty regime will be subject to PRRT.
The helpfulness of the extrinsic material
190 As can be observed, the parties have placed before the Court various file notes, submissions, letters and communications to seek to persuade the Court as to the legislative intention of the PRRTA Act, and in particular s 24. I have already indicated the relevant principles in considering the extrinsic material of the class sought to be relied upon by the parties in these proceedings.
191 Putting aside the various Explanatory Memoranda and Second Reading Speeches, I am not assisted by the extrinsic material sought to be relied upon by the parties. In the main part, the documentation was just the expression of opinion at various stages along the drafting path, with no necessary connection between the individual communications or statements and the final Bill that was presented to Parliament. The expression of opinions from members of government, BHPBP, Esso and APEA about the perceived operation of the provisions of the legislation is of no assistance. Similarly with drafts of proposed legislation. Differences between various drafts of legislation may arise for a variety of reasons, and not necessarily because of some principled decision relating to the operation of an enactment. Therefore, Esso’s reliance on amendments to the wording of the Bills as they were before the Parliament cannot assist in the interpretation of s 24 of the PRRTA Act, at least without some express statement in the Parliament which accompanies the amendments and explains their purpose.
192 Further, subject to one qualification I make below, to the extent that documents forming part of the extrinsic material placed before the Court do post date the initial enactment of the PRRTA Act, but are prior to the 1991 Amendment Act, they do not assist in identifying the mischief or purpose of the PRRTA Act, as originally enacted. All parties accepted that the 1991 Amendment Act did not affect a change in the general application of the initial enactment of the PRRTA Act to the so called ‘taxing points’. In any event, the terms of the 1991 Amendment Act do not give any assistance as to the proper interpretation or operation of the original PRRTA Act prior to its amendment.
193 I should also indicate now that extrinsic material relevant to the 2001 Amendment Act is in a similar category. Even if I could make use of the 2001 Amendment Act to construe the original PRRTA Act for the purposes of these proceedings, nothing in that amending legislation in my view sheds any light on the matter principally in contention in these proceedings, namely to relevant ‘taxing points’.
194 Whilst the various Explanatory Memoranda and Second Reading Speeches talk in general terms, and confirm ‘general propositions’, they too do not shed much light on the debate about the ‘taxing point’ issue in these proceedings. As will be apparent from my observations and views expressed below, the Explanatory Memoranda and Second Reading Speeches assist in indicating the general operation of the PRRTA Act, but do little more.
195 The one qualification I make as referred to above is in relation to the transitional provision (s 33(4)) in respect of the 1991 Amendment Act.
196 Having regard to the context in which the communication with the OPC appears, I am satisfied that such material is at least capable of assisting in the interpretation of the transitional provision. However, as I will come to later in dealing with the ‘take or pay’ issue, and the operation of s 33(4), that provision readily construed by looking at the wording of the provision, and its purpose and context by reference to the 1991 Amendment Act itself.
CONSIDERATION OF OPERATION OF PART IV AND V OF THE PRRTA ACT
197 I commence by making this observation.
198 The fact that Esso has or has not returned its assessable receipts under the PRRTA Act, or has or has not conducted its commercial dealings consistent with the operation of the PRRTA Act it now contends for, cannot influence the correct application of the PRRTA Act.
199 According to Esso, only a small part of the sales gas product that was sold to its customers was a marketable petroleum commodity and the balance of it was not a marketable petroleum commodity. All of the liquefied petroleum gas products that were sold were not marketable petroleum commodities, all of the ethane product was not a marketable petroleum commodity, and part of the stabilised crude oil product was a marketable petroleum commodity and part of it was not.
200 The consequence, according to Esso, is that the corresponding part of the sales proceeds received from the sale of the sales gas, the whole of the sales proceeds received from the sale of the liquefied petroleum gas products, the whole of the returned market value of the ethane and the corresponding part of the returned market value of the stabilised crude oil product are to be excised from the assessment of assessable petroleum receipts.
201 If this is so, it arises because of the proper operation of the PRRTA Act as contended for by Esso.
202 In this context, I make mention of one subsidiary issue that arose in the course of these proceedings: that issue concerned the relevance of the settlement of the “pass-on dispute”, which involved Esso, BHPBP and third parties.
203 The Commissioner sought to rely upon the settlement of this dispute to contend that in commercial dealings with its customers Esso (and BHPBP) acted contrary to the contentions now made to this Court.
204 I do not regard this dispute and its settlement to be of any assistance or relevance to the questions for determination before me.
205 The pass-on dispute concerned Esso’s ability, as a matter of contract, to increase the price payable for gas sold to GFC, the SECV and other buyers to take account of the introduction of the PRRTA Act. As Hill and Heerey JJ observed in BHP Billiton Petroleum (Bass Strait) Pty Ltd v FCT (2002) 126 FCR 119:
The buyers disputed the right of the sellers to adjust the price payable for gas to take into account the rent resource tax after allowing for the change in royalty and abolition of excise. There followed an exchange of correspondence. At the heart of the dispute was a disagreement as to whether the resource rent tax was "attributable" to the production or supply of gas (or ethane) with the effect that the sellers were entitled to pass on the liability to the buyers under cl 12.8 or equivalent clauses. In some, but not all, agreements (the provisions of cl 12.8 of the agreement presently being discussed in an example) the word "directly" appeared immediately before the word "attributable"). The buyers argued that there should only be a reduction in the amount payable to take account of the effective abolition of royalties and excise but no increase to take account of the resource rent tax. (at 124-125)
206 The dispute proceeded to arbitration and was ultimately settled. The settlement was described by Hill and Heerey JJ as follows:
The settlement was reached in the context of the desire of the State of Victoria to introduce structural reforms and increased competition into the Victorian gas industry. Accordingly the parties agreed not merely to settle the claim for the pass-on amount for the past but also to settle claims for entitlements that would arise in the future. The settlement involved the payment of two lump sum amounts, one for the past claim and one for the future claim. The lump sum amounts were paid, respectively, to settle all:
(a) amounts outstanding to [the sellers] on partially paid invoices for gas sold and delivered .... And unpaid invoices and letters of demand for the pass-on of PRRT in respect of gas sold and delivered to [the buyers] between 1 July 1990 and 31 October 1996 ...
(b) future entitlements to pass on PRRT from 1 November 1996 pursuant to the [Supply Contracts] ...
The settlement, when reached did not merely include the buyers and sellers. Taxation was an integral part of the settlement and letters of understanding were entered into between the Australian Taxation Office and BHP and Esso in effect agreeing to the quantum of amounts but leaving it open to Esso and BHP to challenge in objection proceedings the question when income was derived from the sale of the gas for the purposes of income tax and when assessable receipts were derived for the purpose of the resource rent tax. (at 126-7)
207 Like any settlement, the payment of the two lump sums did not necessarily reflect the correct application of the PRRTA Act. Rather, it reflected compromises made by the parties “in the context of the desire of the State of Victoria to introduce structural reforms, etc…” As Gyles J observed in the BHP Billiton case:
A recited basis for settlement was the wish of the Government of Victoria to introduce a number of changes relating to the regulation and operation of the gas industry in Victoria. Settlement appears to have been a means of clearing the decks before reform. Settlement of the SECV dispute was dependent upon and interrelated with settlement of the Gas & Fuel Corp dispute. The settlement involved all claims for gas sold and delivered, including pass on of PRRT, between 1 July 1990 and 31 October 1996, and future entitlement to pass on PRRT from 1 November 1996, by one lump sum, although there was express dissection of the make up of the lump sum. The settlement was at least partly influenced by policy considerations and cannot be taken as reflecting the legal position. (at 149)
208 An integral part of the settlement of the pass-on dispute was that a large part of the amounts of income tax and PRRT payable on each lump sum to the Commissioner were to be returned by the Commonwealth to the State of Victoria. The sharing of this revenue effectively reduced the real burden to the SECV and GFC, and thus the State, of the making each lump sum payment.
209 It was in this context that Esso agreed to receive the lump sum payments in settlement of its dispute and pay income tax and PRRTA tax on those sums. That arrangement was the product of a commercial compromise. It cannot determine or be relevant to liability to pay tax under the PRRT Act, at least in the context of an appeal under Pt IVC of the TAA.
210 I now turn to what I consider to be the correct interpretation of the PRRTA Act in the context of the facts relating to the joint venturers and the Gippsland facilities.
211 It is apparent that the PRRTA Act replaced a royalty and excise regime, and applied a tax to profits from activities within the boundaries of petroleum projects. The focus is thus on profits not production. It is clear that a petroleum project is not just the area of the eligible production licence. However, the term ‘project’ and the boundaries of petroleum projects are not explicitly defined. Section 19(4) does not directly define a petroleum project, nor is it expressly made applicable to the interpretation of s 24. By that I mean, s 24 in its own terms makes no reference to “the operations, facilities and other things comprising a petroleum project”. I observe that when it comes to expenditure, for example general project expenditure in s 38, express reference is made to “the operations, facilities and other things comprising a petroleum project”, thus incorporating for that purpose the ‘definition’ in s 19(4) of a ‘petroleum project’. I further note that s 20(1), in dealing with combining of petroleum projects, specifically picks up s 19(4) by reference to what comprises a petroleum project. So I proceed on the basis that the ambit of a petroleum project is at least informed by the terms of s 19(4), even if not expressly so defined.
212 Further, whilst not explicitly defined in the legislation itself, the concept of ‘project’ must envisage a scheme or plan carried out with a particular commercial purpose in mind. Relevantly, in these proceedings, the joint venture.
213 The concept of the petroleum project then combines the various operations, facilities and other things comprising a petroleum project as ‘defined’ in s 19(4), taking into account the overall objective of the joint venturers in the carrying out of the various operations within the Gippsland facilities.
214 As I have found, the joint venturers implemented the plan to recover petroleum and in an integrated process ‘to yield’ (in the words of Mr Heath) the five hydrocarbon products eventually sold. There was a plan to do this in stages, but such stages were not ends in themselves, but necessary to yield or produce the products in fact sold.
215 To interpret the concept of project in this way is not incorporating within s 24 a concept of ‘intention’ or ‘commercial purpose’, which concepts are not there. However, as s 24 applies not just to Bass Strait, but to other projects of a different nature, one is entitled to look at the objective of the facilities themselves and their overall purpose or object to determine the exact nature and extent of a particular petroleum project for the purposes of the PRRTA Act.
216 As Esso contends, one can readily accept that the PRRTA Act does not apply to ‘downstream activities’. However, what are the downstream activities? I have already referred to s 19(4) which informs this enquiry.
217 It is to be recalled that the Explanatory Memorandum to the 1987 Bill said this:
The boundaries of a petroleum project will not extend beyond the point at which a marketable petroleum commodity is initially stored after production. That is, the project boundaries will not extend to “downstream activities” such as refineries and facilities for the transport of marketable products from that storage.
…
In the event that a the marketable petroleum commodity is not sold at or immediately after the point of initial on-site storage (e.g., where stabilised crude oil is refined by the producer), the market value at that point (or such other value as is fair and reasonable) will be treated as an assessable receipt of the project.
218 Ultimately, the facts pertaining to the particular petroleum project in issue will determine the scope of the petroleum project for the purposes of the PRRTA Act and the application of s 24, including the scope of downstream activities.
219 If one looks to s 19(4)(b)(ii), it talks in terms of operations and facilities involved in the processing or treatment of petroleum so recovered to produce any marketable petroleum commodity. On the facts I have found, this would include the various processes and treatment on the platforms and at Longford if the concept of ‘produced’ and ‘marketable petroleum commodity’ is as contended for by the Commissioner.
220 An issue arose in relation to s 19(4)(b)(ii), and that relates to the definition of ‘petroleum’. It is to be recalled that the definition of petroleum in the Petroleum (Submerged Lands) Act 1967 (Cth) is incorporated into the PRRTA Act. Petroleum is generally a ‘naturally’ occurring substance.
221 It is always to be recalled that the definition of petroleum applies unless a contrary intention appears, and in any event a definition must be read in context. In my view, the reference in s 19(4) to the composite phrase “petroleum so recovered to produce any ‘marketable petroleum commodity” is a reference to the petroleum (which whilst in some respects may be treated or processed) before it reaches the stage of being ‘produced’ into a ‘marketable petroleum commodity’ in the way I consider that these terms should be interpreted. In other words, whilst at many stages on the platform, and at least at the LVO, the petroleum may not be ‘naturally occurring’, it has not reached the stage of being ‘produced’ into a ‘marketable petroleum commodity’. Therefore, up to that point, there is still in existence petroleum recovered to be produced into such a commodity for the purposes of s 19(4)(b)(ii).
222 As I have stressed, the PRRTA Act imposes a tax on profits, not on production. Section 24 itself focuses on the ‘consideration receivable’ (s 24(a) and (b)) or ‘market value’ (s 24(c)). Whilst s 24 does envisage the possibility of “insufficient evidence of that market value” (s 24(c)), the whole basis of the liability to the tax, and in determining one part of the equation, is based upon determining receipts following a sale or where there is a market. This points to an actual sale or ‘marketability’ being a concept at the heart of the determination of liability under the PRRTA Act.
223 Esso emphasised the exhaustive nature of various definitions in the PRRTA Act. However, it is the operation of s 24 in the context of the PRRTA Act as a whole that is relevant. The definitions relied upon by the parties - ‘marketable petroleum commodity’, ‘sales gas’ and ‘excluded commodity’ are not to be read in isolation, but only in the context of s 24 and the PRRTA Act as a whole. It is important to recall that definitions do not control the meaning to be given to the substantive provisions of the enactment.
224 In Gibb v FCT (1966) 118 CLR 628 at [635] Barwick CJ, McTiernan and Taylor JJ said:
The function of a definition clause in a statute is merely to indicate that when particular words or expressions the subject of definition, are found in the substantive part of the statute under consideration, they are to be understood in the defined sense – or are to be taken to include certain things which, but for the definition, they would not include. Such clauses are, therefore, no more than an aid to the construction of the statute and do not operate in any other way…
225 In Kelly v R (2004) 205 ALR 274 at [103] McHugh said:
… the function of a definition is not to enact substantive law. It is to provide aid in construing the statute. Nothing is more likely to defeat the intention of the legislature than to give a definition a narrow, literal meaning and then use that meaning to negate the evident policy or purpose of a substantive enactment. There is, of course, always a question whether the definition is expressly or impliedly excluded. But once it is clear that the definition applies, the better – I think the only proper – course is to read the words of the definition into the substantive enactment and then construe the substantive enactment – in its extended or confined sense – in its context and bearing in mind its purpose and the mischief that it was designed to overcome. To construe the definition before its text has been inserted into the fabric of the substantive enactment invites error as to the meaning of the substantive enactment.
226 Then as Stone J stated in St George Bank Limited v Commissioner of Taxation [2009] FCAFC 62 at [28]:
While words may have a stand-alone meaning or meanings which may be found in a dictionary, generally oral or verbal communication does not proceed by way of individual words but by language; by words used in conjunction with one another to express propositions or sentiments or otherwise communicate meaning. The task of a court in construing a statute is to construe the language of the statute, not the individual word. (emphasis added)
227 Whilst reference has been made to other legislation by the parties to aid my consideration of the operation of s 24, including the Petroleum Revenue Act 1985 (Cth), I do not consider any assistance can be obtained from such legislation in interpreting the PRRTA Act. Just because (arguably) the Petroleum Revenue Act 1985 (Cth) adopted a marketability requirement, which in terms was not adopted in the PRRTA Act, does not assist in the interpretation of s 24 and the concept of assessable receipts when applied to a petroleum project. This is particularly so having regard to the history behind the introduction of the PRRTA Act. Further, I do not consider assistance can be derived from cases dealing with such terms as ‘mining operations’, ‘mining process’, ‘production process’, ‘production’, ‘marketable commodity’, and ‘market petroleum’. Each of these terms was interpreted in the context of the legislation in which they appeared, based upon factual findings peculiar to each proceeding in which the interpretive task was undertaken.
228 The appropriate approach is to consider the meaning of each term employed in the context of the legislative provisions to be applied to the facts before the Court.
229 I first turn to the use of the expression ‘recovered’ in s 24. Not all petroleum is produced pursuant to a production licence. Some may be produced in the course of exploration activities (see eg s 25). This explains the need to use the word ‘recovered’ in s 24 when referring to the petroleum, or a constituent of petroleum being recovered from the production licence area in relation to the project. The word ‘recovered’ simply identifies the source of the petroleum and in my view has no other significance for the purpose of these proceedings. However, the words ‘recovered’ and ‘produced’ connote different concepts relevantly for determining the ultimate product relevantly identified in s 24, to which I will come.
230 However, before considering the concept of ‘produced’, the definition of ‘marketable petroleum commodity’ needs consideration. Generally, this would be treated as an exhaustive definition.
231 Further, it is impermissible to construe a definition by reference to the term defined. As Gibbs J (as he then was) stated in Wacal Developments Pty Ltd v Realty Developments Pty Ltd (1978) 140 CLR 503, at 507:
The expression … given by the statute a special meaning … must be applied whether or not it accords with the ordinary meaning.
232 In The Owners of the Ship “Shin Kobe Maru” v Empire Shipping Co Inc (1994) 181 CLR 404, the whole Court in referring to Wacal said that the use of a word in the term to be defined does not colour the meaning to be given to the definition which follows it. As the Court said at 419:
It would be quite circular to construe the words of a definition by reference to the term defined.
233 However, this does not mean that the definition is not to be read in the context of the substantive provision to be applied. Relevantly, in the context of s 24, the defined term precedes the important concept of being “produced” – a concept which involves more than just deriving one product from another as contended for by Esso.
234 I do not colour or otherwise define the special meaning given to the defined term ‘marketable petroleum commodity’ by the statute. I place it within the context of s 24, and ask whether (for example) “sales gas” as specially defined has been produced as contemplated by the operation of s 24. It is this context that gives rise to the conclusion that just because a substance within the defined list (eg sales gas) exists immediately before some point, does not mean that it has been ‘produced’ as contemplated by the PRRTA Act.
235 In my view, the concept of products ‘produced’ from petroleum (referred to in s 24 and again in the definition of ‘marketable petroleum commodity’), along with the nature of a petroleum project, envisages the bringing into existence of something that is sold or will create value or command a price. As I have already said, the focus of the tax liability in s 24 is upon sale or market value. A factual enquiry is then to be made as to when liability actually arises in any given tax year in relation to a petroleum project, remembering that the tax is not imposed by reference to units of production, but by reference to taxable profit, and then only as defined in the PRRTA Act.
236 The ordinary meaning of ‘produce’ or ‘produced’ in the PRRTA Act should not be read simply to mean ‘derived’, but should be read by reference to its context and the purpose of the petroleum project.
237 According to the Oxford English Dictionary “product” means something “produced by any action, operation or work; a production; the result. Now frequently that which is produced commercially for sale…”. The word “produce” means “To bring forth, bring into being or existence… To bring (a thing) into existence from its raw materials or elements, or as the result of a process”.
238 The chief current meaning of the word “process” is “a continuous and regular action or series of actions, taking place or carried on in a definite manner, and leading to the accomplishment of some result; a continuous operation or series of operations”.
239 The various processes undertaken by Esso are all happening to produce products that are to be sold. There is a production line of considerable size and complexity to produce the sales product. The production phases require the ongoing operation of the Gippsland facilities. In very simple terms, the products sold or to be marketed in the way described by Mr Heath were products of the Bass Strait project. It is these products that the PRRTA Act is primarily focusing upon. In fact, sales occurred in the whole period. If no sale occurs, the legislature has sought to identify a point where the product is in fact marketable or able to be sold, and then determine the ‘market value’ at that point. It may be better to call this point a ‘valuation point’, as distinct from a ‘taxing point’, but whatever term is used, the concept is clear. Even though there may be “insufficient evidence of that market value”, the primary position is that a market can be identified.
240 To the extent that any assistance can be gleaned from the Explanatory Memorandum to the 1987 Bill, the following statement in the Explanatory Memorandum indicates that notwithstanding that otherwise a particular substance may come within the description of one of the products listed in the definition of ‘marketable petroleum commodity’ this is not sufficient:
[the Bill identifies] … in the case of certain petroleum products that have not been sold by the point in the production process at which they become marketable, amounts deemed to be receipts – that are to be assessable for PRRT purposes. (emphasis added)
241 The Commissioner, in submissions concerning the preferred construction to PRRTA Act, referred to a number of complexities that arise out of Esso’s construction. Undoubtedly there are complexities and consequent difficulties of compliance and administration of the PRRTA Act if the approach contended for by Esso is adopted. I do not place much store upon these complexities in reaching the conclusion as to the operation of the PRRTA Act. The methodologies that may need to be used for allocations and apportionment are not novel, and are well known to the law. In any event, I treat submissions based on complexity with some caution – see comments in Esso Australia Resources Ltd v FCT (1998) 83 FCR 511, at [519] (per Black CJ and Sundberg J).
242 If Esso’s construction was otherwise accepted, I do not consider that the complexities raised by the Commissioner should otherwise defeat the operation of the PRRTA Act – see Cooper Brookes (Wollongong) Pty Ltd v FCT (1981) 147 CLR 297.
243 However, for the reasons given above, I reject Esso’s contentions concerning the interpretation to be given to the PRRTA Act.
244 I now deal with the questions for determination, based upon the foregoing reasons.
SALES GAS – FIRST PERIOD – QUESTIONS 1 AND 2
Primary Position
245 On the basis of the facts as I have found them and on my interpretation of the PRRTA Act, Question 1 would be answered ‘None’. Question 2 is then not applicable. The position can be summarised as follows.
246 The Bass Strait production licences give rise to a single petroleum project for the purposes of the PRRTA Act. That petroleum project comprises all of the offshore platforms and all of the onshore facilities and operations involved in the recovery of petroleum and the production of products from that petroleum which are marketable petroleum commodities as defined.
247 As part of the petroleum project, during the first period, Esso and BHPBP recovered petroleum and in a series of integrated operations that were carried out on the various platforms and at Longford produced a product from the petroleum for sale, which it described as sales gas or natural gas. The product so described was sales gas as defined and therefore a marketable petroleum commodity. It was a product produced from petroleum recovered from the production licence areas where the product was a mixture that included methane which comprised more than 50% by weight of the mixture.
248 The product was not one to which the exclusion in the definition of marketable petroleum commodity applied because it was not a product produced from another product of a kind referred to in paragraphs (a) to (f) (inclusive).
249 The sales gas product was sold. By that act of sale the sales gas became an excluded commodity. Accordingly, the consideration receivable less expenses payable by Esso in relation to the sale of the gas constituted assessable petroleum receipts under s 24(b) during the first period. Section 24(c) of the PRRTA Act was not applicable.
250 In the present case, the sales gas product was produced by Esso when the petroleum recovered from the various wellheads on the offshore platforms completed the final processing at Longford. Prior to that point the product was not produced. It was in the course of being produced. The mixture of hydrocarbons on the offshore platforms, in the offshore and onshore pipelines and within the gas plant was committed to and being subjected to a continuous process of separation, filtration and commingling carried out for the purposes of creating an end marketable product. The sales gas obtained at the end of the process at Longford was one of the products that Esso produced from the petroleum it had recovered.
Alternative position
251 If I am wrong about my interpretation of the PRRTA Act and its application to the facts as I have found them, I now deal with the contention of Esso that products were produced before one or a number of points on the various offshore platforms during the first period.
252 In order to succeed Esso must establish that the hydrocarbon mixtures at the various points on the platforms relied upon comprised more than 50% methane by weight (the ‘50% methane by weight criterion’) from time to time across the first period at the various points alleged by it.
253 In its evidence, Esso identified the points and monthly periods during the first period at which it contended the 50% methane by weight criterion was satisfied, on an average monthly basis. There were periods of time in which the hydrocarbon streams at some of those points on some of the platforms did not meet the 50% methane by weight criterion. This has been accepted by Esso.
254 According to data from a system called the Mass Balance System (‘MBS’), the hydrocarbon streams were more than 50% methane by weight on the main gas platforms (Marlin, Barracouta and Snapper), save for the Whiting gas stream upon entering Snapper, and West Tuna. However, the hydrocarbon streams were not more than 50% methane by weight at all times at Flounder and Tuna. Graphs illustrating the points and times at which Mr Heath in evidence contended that the 50% methane by weight criterion was satisfied for the various taxing points on the platform are contained in various exhibits the detail of which I need not repeat for the purposes of these reasons. In some cases, the methane composition fluctuated between just below and just above 50%.
255 The Commissioner accepted that it is reasonable to assume that a stream of gaseous petroleum which is sourced directly and solely from the Barracouta, Snapper and Marlin fields will, in normal operating conditions, satisfy the 50% methane by weight criterion, at least on a monthly averaged basis. These are the petroleum streams that are sourced directly and solely from wells drawing on free gas pools in those fields. It would not include, for example, streams that are a mixture of petroleum drawn from gas pools and petroleum drawn from oil pools, such as the mixture that exists in the Snapper gas header when it is connected to both gas wells and high pressure oil wells. This acceptance by the Commissioner is on the basis that sampling of the composition of these free gas pools has consistently shown a composition considerably in excess of 50% methane by weight criterion. However, normal operating conditions would not include the watering out of a gas well and other miscellaneous events and upsets on the platform.
256 For all other streams at issue the Commissioner submitted that the Court cannot be satisfied that Esso has shown that the 50% methane by weight criterion is satisfied.
257 Esso has not sought to establish compliance with the 50% methane by weight criterion by any process of regular sampling of the liquid or gaseous petroleum streams at the first period taxing points. The continual variation in operating conditions (pressures, temperatures and flow rates) on the platforms can result in large changes in gas flow rates and compositions so that such a sampling program is either not feasible or difficult to carry out. However, Mr Heath in his evidence said that it was not necessary to undertake such sampling because the composition of the petroleum within a given reservoir is generally fixed and homogeneous and as such the composition of the effluent from a platform can be calculated through the MBS.
258 It is necessary to consider the evidence, particularly that of Mr Heath and Mr Aron. Mr Heath I have already described. Mr Aron was an expert called by the Commissioner, who has had a great deal of experience in the petroleum industry. No attack was made on either witness as to their credit, but numerous submissions were made concerning errors in their evidence. The resolution of the factual issues in this case depends upon the merits of the competing views, and not on any assessment of the candour of Mr Heath or Mr Aron (or for that matter any other witness). I have treated each witness as being candid and as honestly attempting to inform the Court as to the actual or likely operation of the facilities conducted by Esso in Bass Strait.
259 However, I make two qualifications to this approach. Mr Heath has had a great deal of experience with and knowledge of the operations of the Gippsland facilities. Whilst Mr Aron has experience with and knowledge of other facilities, which I accept have some similarities with Bass Strait, Mr Aron effectively hypothesized over daily or hourly events that may affect the operations in Bass Strait. The principal difference between these two witnesses concerned Esso’s reliance on monthly averaging of the quantity and quality of products produced from petroleum to establish compliance with the PRRTA Act.
260 Whilst it is for the Court to assess the appropriateness of this reliance, and whether Esso can satisfy the burden upon it to establish certain facts, I have taken to be more persuasive the views of Mr Heath as to the events that are likely to affect the operations of the Gippsland facilities at various times and places. Mr Heath is in a better position than Mr Aron to give evidence about these matters. Mr Aron was raising more theoretical difficulties with the methodology used by Esso.
261 The second qualification is this. Extensive affidavit evidence was filed by Mr Heath and Mr Aron before trial, as was a joint expert report. At trial (over objection by Esso), further evidence was led by the Commissioner from Mr Aron as to the topic of ‘watering out’.
262 Mr Aron was candid that it was not until after he met Mr Heath to prepare the joint expert report that he appreciated the differences of opinion on the topic of ‘watering out’ between Mr Heath and himself. It was apparent that Mr Aron did not consider he had enough production data to make any definite conclusions on watering out, and was disputing whether Mr Heath could draw appropriate conclusions from limited monthly data over a ten year period. Mr Aron had raised this issue in his Expert Witness Report (dated 19 January 2010) where at paragraph 342 he said:
To date I have received reports giving production data for three months only (January to March 2002), and I have received sample pressure and temperature data on 10 November 2009. The data is limited and is incomplete and not comprehensive.
263 For instance, Mr Aron observed that the water production could have all occurred in one month, or could have been in smaller amounts over a longer period of time. Nevertheless, as Mr Aron himself accepted, the task is to understand a “complex phenomena”, which involves application of reservoir engineering, and this necessarily involves an understanding of Bass Strait and the Gippsland facilities. Whilst all the data that could have been made available was not before the Court, the Court does have the benefit of Mr Heath’s extensive knowledge and experience (upon which there was no attack) to form a view of, in Mr Aron’s words, “how things actually work”. I do not agree with Mr Aron that in these circumstances, without looking at every single well throughout the entire period, you cannot make any conclusions about what is happening, at least for the purposes of these proceedings and on the balance of probabilities.
264 In any event, the real issue between the parties seemed to be the extent to which Esso could prove the composition of the hydrocarbon streams at the various first period taxing points by the use of the MBS. Mr Aron had “reservations regarding the use of it as it applies to this case”.
265 If contrary to my view, s 24(c) was applicable, Esso would need to demonstrate that it comes within its operation. Relevantly on the issue of sales gas, it needs to satisfy the 50% methane by weight criterion. As the answer to whether this criterion is met will affect the assessable receipts (‘the value’ of the ‘marketable petroleum commodity’), which will be different depending upon when the ‘sales gas’ becomes an excluded commodity, the Court will need to be satisfied more than on a monthly basis. However, there is no burden other than the civil onus of proof on the balance of probabilities.
266 Esso relies upon data which gives average results for a period, as distinct from daily or minute by minute results. Esso contends that it demonstrates, on the balance of probabilities, what the composition of the mixture is for each month, and provides a rational basis for the making of findings about composition, absent the presence of evidence which would suggest otherwise.
267 Esso argues that use of estimates, averages and statistics for this purpose is relatively commonplace in tax cases. In, for example, RACV Insurance Pty Ltd v FCT [1975] VR 1, Menhennitt J was required to determine whether the RACV was entitled to a deduction for claims in relation to liabilities which had yet to be reported to it in the year of income, but which, based on statistical data, it knew it had already incurred. The presence of such claims was based on conservative estimates booked in RACV’s accounts. A deduction for such claims, on the basis of being a loss incurred, was allowed even though it was based on no more than statistics and reasonable estimates. This decision has been followed and applied on numerous occasions since: see, for example, Coles Myer Finance Ltd v FCT (1993) 176 CLR 640; C of T v Australian Guarantee Corporation Limited (1984) 2 FCR 483 and Commercial Union Assurance Co of Australia Ltd v FCT (1977) 77 ATC 4,186.
268 The first consideration is to determine what is required to be proved as a requirement of the PRRTA Act. Are monthly periods sufficient, or must Esso go further to prove the 50% methane by weight criterion was reached through the whole of the relevant period in respect of the relevant taxing point? Once this is answered, then the Court can determine whether the evidence proves the factual issue to be determined. Of course, as I conclude later, actual monthly information may be used to conclude, on the balance of probabilities, what events occurred day by day, or minute by minute.
269 In my view, the PRRTA Act requires a specific identification of the time and place the 50% methane by weight criterion is satisfied and upon which Esso relies in respect of each tax year. Section 24(c) (if applicable) will primarily require the determination of the market value of the commodity “immediately before it becomes or became an excluded commodity”. This can only be determined if a time and place is ascertained.
270 Even if one could conclude in 80% of the first period during the relevant tax year, sales gas became an excluded commodity at, say, the LVO, it is difficult to see how the primary determination of ‘market value’ could be ascertained unless a specific time was specified.
271 On Esso’s case, tax points may change from time to time, so even at any given moment the valuation point is not certain. If the correct approach, which I have rejected, is to apply s 24(c), then the consequence is that Esso would need to prove, to the extent it claims a particular ‘value’, the time and place that value is to be determined pursuant to s 24(c).
272 If s 24(c) applied I would have concluded that there was an “excluded commodity” within the meaning of the PRRTA Act at each of the wellhead taxing points on the 3 main gas platforms by reason of the facts that:
(a) the gas met the physical properties required to bring it within the term ‘sales gas’, and was accordingly one of the ‘following products’ produced (ie derived) from petroleum contemplated by the definition ‘marketable petroleum commodity’;
(b) upon the sales gas passing through the wing valve, the choke valve and into the production facilities (with consequential changes in pressure), the gas underwent ‘further processing’ or was ‘treated’ as contemplated by paragraph (b) of the definition of ‘excluded commodity’ such that the point immediately before the sales gas became an excluded commodity is at the exit of the wing valve (or at the exit of the choke valve);
(c) alternatively to (b), the passage of the gas through to the choke valve, on the other side of the firewall isolating the wellheads and which formed part of the production facilities, and then onwards into the further processing infrastructure (the production headers) led to the gas having been moved away from the place of production (i.e. the wellhead) to a place other than an adjacent storage facility, as contemplated by paragraph (c) of the definition of ‘excluded commodity’.
273 I would have concluded similarly in relation to the other taxing points contended for Esso on the 3 main gas platforms, which such adoptions as necessary in relation to paras (b) and (c) above.
274 There was no real dispute as a matter of construction or evidence that if the gas met the physical properties required to bring it within the term ‘sales gas’, the other requirements set out above would be satisfied.
275 I now set out the basis of this conclusion as to the physical properties if s 24(c) applied.
276 As to the three main gas platforms - Marlin, Barracouta and Snapper - I can readily infer on the balance of probabilities that on each day, subject to specific times identified by Mr Heath, the 50% methane by weight criterion was met at the various points identified by Mr Heath, and I so find.
277 In relation to the other platforms, I cannot make the same inference. I will seek to explain the difference in my approach and conclusion.
278 With homogenous reservoirs the composition of the fluid flow from the reservoir into the well bores is not expected to change over time.
279 The three principal gas reservoirs - Snapper, Barracouta and Marlin - are all homogeneous. Mr Aron described such reservoirs as “free gas fields”. Mr Aron gave evidence that 94% of the Bass Strait project gas production came from free gas fields.
280 The difference between homogeneous and heterogeneous reservoirs was explained by Mr Heath as follows:
The difference between homogeneous and heterogeneous is that where the fluid flow from the reservoir into the well bores is expected to and observed to be constant from month to month, it’s sufficient to use the reservoir compositions as representative of what’s going out of the well. What we find with a heterogeneous reservoir, on the other hand, is that it’s not the uniform initial reservoir fluids that are flowing in, but it’s typically a mixture of oil and overlying gas which finds its way into the well bore, in varying proportions typically from month to month, and therefore we have to adopt an approach which says, “All right. We don’t have a uniform body of fluids that are going into the well each month – a uniform composition. We’ve in fact got different compositions in different proportions and so each month we need to carry out a separate calculation to account for those varying inflowing quantities”.
281 With heterogeneous fields (such as the Tuna and Flounder oil reservoirs), where the relative proportions of gaseous and (heavier) liquid hydrocarbons contained in the well effluent may vary due to the phenomenon of ‘coning’.
282 I accept that monthly calculations were done of the “full well stream” to allow for this variation. As Mr Heath explained:
Every month we know, from well tests, how much each well has produced and we know, as a matter of fact, from which reservoir horizons the wells are producing. Therefore we can determine where the oil is coming from and we sample it on the surface to know what the composition is, and we combine the rates with the compositional data and come up with a combined full well stream every month.
283 Mr Heath gave an explanation of the means by which the respective monthly volumes of gas and liquids produced from heterogeneous reservoirs, as ascertained via well tests, are converted to measurements of mass. Ascertaining the mass of the hydrocarbons produced in turn enables the calculation by weighted average of the mass percentages of the constituent parts of the full well stream for the month, given that the respective compositions of the gas and liquids produced are known. The monthly composition data in respect of the heterogeneous (and homogeneous reservoirs for that matter) updated from time to time with results from sampling, was input into the MBS.
284 However, the important evidence upon which I rely in distinguishing the various platforms, is the data from the MBS compiled and included in exhibit 89A (in respect of fields other than Snapper) and exhibit 90 (in respect of Snapper). As an example by reference to the LVO, Mr Heath explained that:
(a) In the case of the Barracouta platform, the gas at the LVO (taxing point 4) met the 50% by weight criterion for the whole of the first period. In fact the charts at exhibit NMH93 show that at Barracouta there was consistently shown to be about 70% methane by weight at LVO and just before the addition of MEG (taxing point 3);
(b) In the case of the Marlin platform, the gas at the LVO (taxing point 4) met the 50% by weight criterion for the whole of the first period. The December 1998 result was an anomaly. Again the charts at exhibit NMH96 show that at Marlin there was consistently gas which comprised 60% methane by weight at LVO and at each of the other taxing points alleged by Esso;
(c) In the case of the Snapper platform, the gas at the LVO (taxing point 4) met the 50% by weight criterion for the whole of the first period. Again the charts at exhibit NMH109 show that at the LVO and just before MEG injection (taxing point 3) the stream is consistently 70% methane by weight;
(d) In the case of the West Tuna platform, the gas at the LVO (taxing point 4) met the 50% by weight criterion for the whole of the first period when it was flowing. Again the charts at exhibit NMH106 show that when flowing, the gas at West Tuna was consistently at or above 60% methane by weight;
(e) In the case of the Flounder platform, the gas at the LVO (taxing point 4) met the 50% by weight criterion for part of the first period;
(f) In the case of the Tuna platform, the gas at the LVO (taxing point 4) met the 50% methane by weight criterion for part of the first period.
285 Mr Heath referred to other data in respect of other taxing points contended for by Esso.
286 Therefore, on the basis of the nature of homogeneous reservoirs and the data explained by Mr Heath, it can be inferred in relation to Barracouta, Marlin and Snapper that the 50% methane by weight criterion has been satisfied, at least in normal operating conditions. It is more than probable that throughout the whole of the first period, other than on any specific occasions identified by Mr Heath, the 50% methane by weight criterion was met not just month by month, but continuously. This is sufficient to satisfy the burden of proof placed upon Esso.
287 This is further supported by the following evidence.
288 On the Commissioner’s own evidence, the percentage by weight of methane in the Snapper gas reservoir was well over 50% and was in fact over 70%. Further, according to the Department of Primary Industries and Energy, Australian Petroleum Accumulations Report 3, the molecular percentage of methane in the Snapper gas reservoir is 84.3%, in the Marlin reservoir it is 72.97% and at Barracouta the molecular percentage is 86.7%.
289 As I have indicated above Mr Aron said that 94% of the gas produced from the Bass Strait project comes from free gas fields rather than associated gas. This would have resulted in the 50% methane by weight criterion being generally met at most of the first period Taxing Points where the streams are sourced directly from free gas fields.
290 Mr Aron also referred to Mr Heath’s evidence as to stream compositions on the mainfields and stated:
(a) that he was not surprised by Mr Heath’s conclusion that for the Barracouta field at all first period Taxing Points, the 50% methane by weight criterion was met other than for June 2000 which had been suggested to be a database error;
(b) that he was not surprised by Mr Heath’s conclusion that for the Marlin field at all first period Taxing Points, the 50% methane by weight criterion was met other than for December 1998 which had been suggested to be a database error; and
(c) that he was not surprised by Mr Heath’s conclusion that for the Snapper platform at all first period Taxing Points, the 50% methane by weight criterion was met most of the time.
291 In cross-examination, Mr Aron agreed that in normal operating conditions it would be reasonable to assume that the gas derived from the free gas reservoirs on the three main platforms would generally meet the 50% methane by weight criterion.
292 As to normal operating conditions, Mr Heath gave this evidence:
I cannot conceive of circumstances in normal operating conditions, particularly on the main gas platforms (Barracouta, Snapper and Marlin) where the percentage by weight of methane is well over 50%, where the composition of the streams would change to such an extent that the percentage by weight of methane would be at or below 50%. In theory it is possible that there could be a mechanical failure in a separator which could lead to liquids not being removed from the bottom of the vessel and instead flowing out with the gas streams: an extreme event such as this however would be likely to require the entire platform to be shut down immediately and there would be no production until the problem was remedied. The separators each have alarms which are activated if the liquid level rises beyond a safe working level, whereupon the separator is shut down. The extreme theoretical possibility of liquids coming out of the top of the separator would require a failure of both the separator and the alarm system and assumes that operators have not detected the high level of liquids upon usual inspection of the sight glass.
293 I accept this explanation as it applies to the main gas platforms. Therefore, on the balance of probabilities it has been shown that throughout the first period in relation to the Barracouta, Snapper and Marlin platforms, the 50% methane by weight criterion has been met to the extent indicated by reference to the data produced by Mr Heath.
294 However, with the other fields the position is different, and I do not consider that Esso has demonstrated the required weight criterion by reference to the alleged tax points. This is because Esso did not introduce evidence enabling me to reach the conclusion as to the 50% methane by weight criterion at the various points on the platforms.
295 I need to explain a little more of the way in which Esso seeks to prove its case on the basis that s 24(c) applies. The comments I make apply to the main platforms as well, but the difference in result is explained by the nature of the streams, the extent of the percentage methane by weight, and the fact that I am not persuaded that circumstances could not occur to upset normal operating conditions on these platforms. I observe that Mr Heath himself distinguished between the main gas platforms and the other platforms in this regard.
296 The approach taken by Esso seeks to infer the average monthly gas flow rates and compositions by adapting a pre-existing computer model that simulates the flows across the platforms. Esso purports to use this computer model to infer actual average monthly stream compositions to an accuracy of 0.01%. It is those inferred average monthly compositions that have been relied upon by Esso in these proceedings as the basis for its contentions concerning satisfaction of the 50% methane by weight criterion.
297 The pre-existing computer model, known as ROYAL, forms part of the MBS and was devised by Esso for the purposes of calculating its statutory royalty and excise obligations. In order to calculate those obligations Esso needed to be able to proportionally allocate the commercial products it sold each month to the source petroleum fields. For this purpose the petroleum pools that make up the Bass Strait fields were grouped in the computer model into Allocation Base Points (‘ABP’), each containing one or more petroleum pools. The model then calculated what proportion of the monthly commercial product sales was to be allocated to each ABP. That model was not devised for the purpose Esso seeks to put it to, namely the calculation of the precise composition of various streams at points on the platforms. That model has been adapted by Esso for the purposes of these proceedings in an attempt to calculate the composition of the liquid and gaseous petroleum flows at the first period Taxing Points alleged by Esso. This is not to say that the adaption does not enable proper conclusions to be drawn for the purpose of these proceedings, but just that the limitations upon the use of the model need be recognised.
298 However, I am not satisfied that the adaptation of the ROYAL program is adequate to establish whether the 50% methane by weight criterion has been satisfied at the times and points alleged by Esso for the streams other than the Barracouta, Snapper and Marlin gas fields throughout the first period.
299 It is to be recalled that I do not have the other evidence I have referred to in relation to Barracouta, Snapper and Marlin that I have relied upon to reach the conclusion above in respect of these fields, other than the data referred to in the evidence of Mr Heath and referred to above. The data does show in relation to the West Tuna, Flouder and Tuna platforms the required weight criterion, but not to the extent of the main gas platforms.
300 It was submitted by the Commissioner that there were a variety of factors operating with respect to these streams that mean Esso’s approach of using a monthly inferred composition from the MBS cannot be relied upon as an accurate measure of the points and times during the first sales gas period where the 50% methane by weight criterion was satisfied.
301 I need not determine all the factors raised by the Commissioner. I make the following observations in support of my conclusion.
302 The MBS relies upon two main inputs to simulate the flows occurring across the platforms each month:
(a) measurements of total monthly fluid flows taken by meters located at various points on the platforms and at Longford; and
(b) a database of “fullwellstream” compositions. These compositions represent a calculated sample of the entirety of the flow from an ABP from all the wellheads comprising that ABP at the time of sampling.
303 It is these simulated flows that were relied upon by Mr Heath to calculate the proportion of methane in the flow at any particular point. To the extent that these inputs are not accurate any calculation based on them must also be inaccurate. This will be particularly the case where commingling occurs. Errors in the measurement of the volume of the commingling streams will mean that the proportions contributed to the commingled stream will be erroneous. Also, to the extent that these inputs rely on assumptions or averaging then the accuracy of the results obtained by Mr Heath will be dependent on the validity of those assumptions and only represent an averaged result over the course of a month.
304 In evidence, Mr Heath accepted that:
(a) the gas flow meters used on the platforms are only accurate in a range varying from about plus or minus 1% to about plus or minus 5% depending on the volume of flow;
(b) the meters are only designed to measure a single phase: if a stream contains more than one phase the accuracy of the meters will be further reduced; and
(c) meters designed to measure liquids cannot distinguish between oil and water.
305 Then in relation to “fullwellstream” compositions, Esso’s fullwellstream composition data is contained in a database known as the “Gippsy database”. The entirety of this database which covers all of Esso’s platforms over the period to date was introduced into evidence by Mr Heath. Esso identified which parts of that database were relied upon by Mr Heath to calculate the methane compositions at the points and times in issue in this proceeding.
306 I accept the submission of the Commissioner that a review the fullwellstream composition data indicates:
(a) there are a number of fullwellstreams where no samples, or no samples considered valid by Esso’s computer system, have been taken for a considerable time before the start of the first sales gas period. While Esso contended that the compositional data is updated from “time to time” with results from sampling, for many fullwellstreams there has been little or no such sampling during the first period;
(b) there are a number of fullwellstreams where the sampling that has been done shows considerable variation in the methane content; and
(c) there are a number of fullwellstreams where there is very considerable variation in the methane compositions used in the MBS system.
307 Mr Heath accepted in evidence that the sampling taken showed “considerable” and a “high degree” of variability in the sampled methane content for some fullwellstreams. Esso’s approach was to average out these compositions so as to produce a running average composition.
308 Mr Heath explained that the considerable variation in the methane composition figure used in the MBS for some fullwellstreams was due to the action of gas coning into an oil pool. I have already alluded to this phenomenon of ‘coning’. Gas coning produces varying methane compositions due to the extent of gas coning from time to time and depending on which particular wells are being drawn upon and at what flow rates. In such cases Esso treats the reservoir as being heterogeneous instead of homogeneous, and calculates compositions on a monthly basis and uses the monthly figure in the MBS. This monthly figure is derived by taking a monthly sample of the varying gas and liquid flows and applying the running average of previous sampled compositions for each of the gas and liquid streams and not by additional composition sampling. The purpose of the calculation is to produce a “best estimate” of the quantities of hydrocarbons taken in respect of a fullwellstream in each month.
309 The monthly compositions used often show considerable variation in methane composition from month to month. Variations may not occur precisely on the exact days each month where gas and liquid compositions are measured. The nature of an average of a fluctuating quantity over time is that it must conceal individual days where the measurement was above the average and days when it was below. That is particularly the case where there is considerable variation in the monthly averages themselves.
310 Mr Heath agreed that because of the varying action of gas coning on methane composition a monthly average would not represent the day to day variation in methane composition and that resort to more detailed data would be necessary.
311 Esso has not presented any such data or records showing daily variations.
312 A further cause of the considerable variation in methane compositions from month to month identified by Mr Heath was that the fullwellstreams are calculated as the sum of the average monthly flows from what can be a group of reservoirs with varying methane compositions. Mr Heath identified Flounder New Oil as such a fullwellstream, with petroleum being drawn from discrete reservoirs with methane compositions varying from about 2% to about 40%. Mr Heath agreed that in such cases a mean or average composition is calculated for all of the reservoirs. Mr Heath also agreed that this introduces an extra level of variability for such fullwellstreams – the composition of the fullwellstream can vary not only depending on the extent of gas coning, but also depending on which combination of reservoirs and wells is being drawn upon from time to time.
313 Therefore, a consequence of Esso’s approach in using monthly flow data and monthly compositions is that the compositions inferred by this method can only be a monthly average. As such they may not accurately reflect events that occur on a timescale of less than a month. Thus, without the benefit of the evidence I have been shown in relation to the main gas fields, I cannot make the similar inference I have drawn to conclude that the 50% methane by weight criterion is satisfied at the places and times variously contended for by Esso.
314 Therefore, if s 24(c) applied, in the case of the streams other than the main platforms, Esso has not demonstrated that in the relevant tax year sales gas had become an excluded commodity within s 24(c) at any of the particular times and places contended for by Esso.
SALES GAS – SECOND PERIOD – QUESTIONS 3 TO 5
Primary Position
315 The second period for the purposes of these proceedings begins on 1 April 2002 with the commencement of the 2001 Amendment Act which amended the definition of ‘sales gas’ in s 2 of the PRRTA Act and s 24 of the Act.
316 From the first period to the second period, there was no relevant change to any aspect of the process of production and sale of sales gas (or to any other marketable petroleum commodity produced as part of the Gippsland facilities) by Esso. As with the first period, Esso recovered petroleum at the offshore platforms in Bass Strait and in a series of integrated operations carried out on the platforms, and at Longford produced a product from the petroleum for sale, which it described as sales gas or natural gas.
317 For the reasons given in relation to the first period, the product so produced was sales gas and was therefore a marketable petroleum commodity. That product became an excluded commodity by virtue of being sold at the Longford gas metering station. The assessable petroleum receipts derived by Esso in respect of that product were therefore the consideration receivable, less expenses payable, in relation to the sale pursuant to s 24(1)(d)(ii) of the PRRTA Act. Neither s 24(1)(c) nor s 24(1)(e) of the PRRTA Act was applicable.
318 Esso contended that during the second period the whole, or almost the whole, of the sales gas sold to its customers at the exit of the Longford Plant was not a marketable petroleum commodity. According to Esso, the whole, or almost the whole, of the sales gas that was sold was not a marketable petroleum commodity because it was a product that was produced from another marketable petroleum commodity, namely sales gas, which is said to have been produced before a number of alternative points, 45 in total, within each of the three gas plants that form part of the Longford Plant. Esso further submitted that a relevant act occurred at one or other of those points by which the marketable petroleum commodity became an excluded commodity. I reject Esso’s contentions for the reasons given in relation to the first period. Question 3 would be answered ‘None’. Questions 4 and 5 are not applicable.
Secondary Position
319 If I am wrong about my interpretation of the PRRTA Act and its application to the facts as I have found them, I now deal with the contention that products were produced at various taxing points within the Longford Plant.
320 The various taxing points contended for by Esso in the second period were identified by Mr Heath and summarised in the following table:
Taxing Point Reference | Location (Gas Plant) | Location – Description |
LFD1(a) | N/A | Exit from top of Barracouta/Snapper slug catchers |
LFD1(b) | N/A | Exit from top of Marlin slug catchers |
LFD2(a) | GP1 | Exit from top of inlet separator GP-1101 |
LFD2(b) | GP2 | Exit from feed gas knock-out drum GT-1101N |
LFD2(c) | GP3 | Exit from feed gas knock-out drum GN-1101 |
LFD3(a) | GP1 | Exit from inlet gas filter separator AX-1407 |
LFD3(b)(i) | GP2 | Exit from slug catcher filter separator GT-1470B |
LFD3(b)(ii) | GP2 | Exit from slug catcher filter separator GT-1470A |
LFD3(c)(i) | GP3 | Exit from slug catcher filter separator GN-1407 |
LFD3(c)(ii) | GP3 | Exit from slug catcher filter separator GT-1407 |
LFD4(a)(i) to LFD4(a)(vi) | GP1 | Exits of mol sieves |
LFD4(b)(i) to LFD4(b)(viii) | GP2 | Exits of feed gas treaters (mol sieves) |
LFD4(c)(i) to LFD4(c)(viii) | GP3 | Exits of feed gas treaters (mol sieves) |
LFD5(a)(i) | GP1 | Top of Absorber A |
LFD5(a)(ii) | GP1 | To of Absorber B |
LFD5(b) | GP2 | Top of Demethaniser GT-1112 |
LFD5(c) | GP3 | Top of Demethaniser GN-1112 |
LFD6(a)(i) | GP1 | Entry to heat exchanger GP901B |
LFD6(a)(ii) | GP1 | Entry to heat exchanger GP901D |
LFD6(b) | GP2 | Entry to heat exchanger GT911 |
LFD6(c) | GP2 | Entry to compressor GT305 |
LFD6(d) | GP3 | Entry to heat exchanger GN911 |
LFD6(e)(i) | GP3 | Entry to compressor GN302A |
LFD6(e)(ii) | GP3 | Entry to compressor GN302B |
LFD7(a) | GP1/2 | Exit of Longford Plant |
LFD7(b) | GP3 | Exit of Longford Plant |
321 The Commissioner submitted that the hydrocarbon mixtures at or before the various points within the Longford Plant relied upon by Esso during the second period did not meet the criteria required by the amended definition of sales gas because:
(a) the substance passing through the various taxing points was not in a gaseous state when at a temperature of 15°C due to the presence of liquid hydrocarbon/water carryover from the slug catchers and/or the presence of liquid MEG. Compliance at taxing points LFD1(a), 1(b), 2(a) and 2(b) and potentially LFD2(c), LFD5(b), LFD5(c), LFD6(b), LFD6(c), LFD6(d), LFD6(e)(i) and (ii), LFD7(a) and LFD7(b) is affected by this issue. Alternatively, it is impossible to determine what state it would be in because the answer depends on the presence or absence of immeasurably small quantities of heavier hydrocarbons. Potentially this issue affects all taxing points;
(b) the substance passing through the various taxing points did not consist of naturally occurring hydrocarbons, or a naturally occurring mixture of hydrocarbons and non-hydrocarbons, due to the presence of non-naturally occurring compounds; namely, the synthetic chemicals MEG, methanol and corrosion inhibiters which were either present in the gas pipeline streams when they arrived at Longford or were added by Esso at various points inside the Longford Plant. Potentially this issue affects all taxing points;
(c) the substance passing through the various taxing points was not to be used as feedstock for conversion to another product. This issue affects all taxing points; and
(d) the substance passing through the various taxing points was not processed so that it was suitable for direct consumption as energy This issue affects taxing points LFD1-6 in Gas Plant 1 and taxing points LFD1-4 in Gas Plants 2 and 3.
322 There is no issue that, absent some major plant upset, the substances moving through the various taxing points in the second period consisted principally of methane.
323 It is to be recalled that the amended definition of sales gas in s 2 of the PRRTA Act, effective as of 1 April 2002, was 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.
324 I now propose to make some observations on the evidence, particularly in relation to the issue of the gaseous state criteria.
Longford Taxing Point 1 – Exit of the slug catchers
325 The first taxing points for which Esso contends are at the exit of the slug catchers, from where the gas passes through gas risers and then into the individual gas plants for further processing. Each of the slug catchers has four risers and four barrels. The gas from the risers then flows through as inlet gas to Gas Plant 1, Gas Plant 2 or Gas Plant 3.
326 Esso’s evidence sought to establish by two methods that, at the exit of the slug catchers, the gas meets the physical requirements necessary to be “sales gas” within the amended definition of that term as applicable for the second sales gas period, under ordinary operating conditions:
(a) First, Mr Stephen Henzell, a chemical engineer and employee of WorleyParsons, a company that provides professional services to the energy, resource and complex process industries, undertook a modelling exercise to test whether the hydrocarbon stream at various points would have been in a gaseous state when at 15°C temperature and at normal atmospheric pressure.
(b) Secondly, Mr Andrew Troupis, a chemist and laboratory manager of the Port Melbourne Laboratory of Intertek Testing Services Australia and Mr Graeme Marks, a chemist and senior analyst, undertook testing and analysis of whether the hydrocarbon stream passing through certain points at Longford is in fact in a gaseous state when at a temperature of 15°C and at normal atmospheric pressure.
327 Each method was based upon ordinary operating conditions.
328 Mr Henzell explained that thermodynamic modelling determines whether hydrocarbon streams are in vapour or liquid state. He used “Hysys” computer software to undertake his modelling.
329 Mr Henzell obtained log sheets for each of the platforms and the Longford Plant for three dates between April and June 2002, and input the operating data recorded in the log sheets into the Hysys model.
330 Although the gas on the platforms did not meet the test criteria, Mr Henzell concluded that the modelling points at the Longford slug catchers produced hydrocarbons which satisfied the test condition, namely being in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
331 Mr Henzell discussed the modelling points that meet the test, referring to the slug catcher locations (modelling points 1 and 2) and stated:
Once the entrained liquids from Modelling Points 1 and 2 [i.e. the slug catchers] are recovered in the Inlet Separators to each gas plant, the gas leaving the Inlet Separators will have minimal entrainment and will meet the Test Condition. This extends through to the Mol Sieves. Testing has been performed with a range of arrival temperatures to reflect seasonal variation and with consideration of the rich gas stream returning to the KVRs to Gas Plant 1 – see Section 9.4 below. This indicates that the Test Condition is robust to the range of operating conditions experienced at Longford.
332 This, Esso contended, supported a conclusion that in ordinary operating conditions the relevant hydrocarbon streams at taxing points that are “downstream” from the slug catchers (which is all of them) would have been in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere. Mr Henzell went on to express the opinion that although he cannot be definitive he would expect that the slug catchers would be able to meet the test condition for much of the time despite there being no internal fittings in the gas risers which separate out any liquids that are entrained with the gas. He stated that, however, during events of high liquid loads such as pigging of the pipelines or ramp-up of the flow in the pipelines, the high liquid loading would incur greater carryover and would fail to meet the test conditions. During these high liquid load times, the relative fraction of the liquid in the pipeline would temporarily increase.
333 Mr Troupis and Mr Marks, who were not required for cross-examination, gave evidence of having tested gas samples from the Longford Plant, in order to attempt to ascertain whether or not the gas:
(a) is in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere; and
(b) whether or not the principal constituent of the gas was methane.
334 In order to undertake the first of the two exercises described above, they undertook dew point testing to confirm the presence or absence of condensable hydrocarbons. Their report explains that the absence of a visible dew point confirms at the specific temperature of 15°C and pressure of one atmosphere that there are no condensable hydrocarbons present.
335 In order to undertake the exercise of determining whether or not the principal constituent of the gas was methane, Mr Troupis and Mr Marks had a gas chromatography analysis carried out. Testing was undertaken on 22 May 2008.
336 As for the Barracouta slug catcher, there was no dew point detected and Mr Troupis and Mr Marks concluded that there were no condensable hydrocarbons, ie liquid, at a temperature of 15°C and a pressure of one atmosphere.
337 Although it was not possible to test the gas from the other slug catcher due to a problem with one of the valves, Mr Troupis gave evidence that using the average flow data for the Barracouta slug catcher and with the dew point test result from the gas plant into which the Marlin slug catcher feeds, an inference can be drawn as to the dew point of the gas at the slug catcher. Mr Troupis and Mr Marks stated that in light of the other sample points not yielding any dew point:
… it can be inferred that the Marlin Slug Catcher 2 will not yield a dew point at 15 degrees C and a pressure of one atmosphere, thus remaining in a gaseous state.
Longford Taxing Point 2
338 From the slug catchers, the gas passes towards the Longford gas plants, of which there are three. Gas Plant 1 relies on the use of refrigerants to separate the heavier gas molecules from the lighter gas molecules. Unlike Gas Plant 1, Gas Plants 2 and 3 are cryogenic plants, which means that they use very low temperatures to separate the heavier hydrocarbons and rather than relying on the use of refrigerants, the inlet gas is subjected to a series of substantial pressure reductions which cause the temperature of the gas to fall significantly. The taxing points for which Esso contended prior to the streams entering the gas plants are described below.
Gas Plant 1 – Inlet Separator
339 Esso contended taxing point 2(a) is at the inlet separator to Gas Plant 1, known as GP1101. The inlet separator it is designed to remove any remaining liquids, particularly those which have carried over from the slug catcher. As the slug catchers work effectively as separators of gas and liquids, the flow of liquids from the bottom of the separator is typically negligible.
340 Mr Henzell’s report is relied on by Esso to support the contention that at all of the Longford taxing points in respect of the second sales gas period, the hydrocarbon streams were in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere and when under normal plant operating conditions (ie other than at times of high liquid loads such as pigging of the pipelines or ramp-up of the flow, at which points the streams at the slug catchers may not have been in an entirely gaseous state).
341 Also supporting this conclusion, and in particular in respect of taxing point 2(a) at the inlet separator in Gas Plant 1, Esso pointed to the results of Mr Troupis’ and Mr Marks’ testing which showed the absence of a dew point.
342 By this point in the plant, liquids – ie condensate and any aqueous combination of water and MEG – have been progressively removed, firstly by the slug catchers and with a further liquid removal stage occurring at the separator itself.
Gas Plant 2 – Feed Knockout Drum
343 Esso contended taxing point 2(b) is at the feed knockout drum, GT-1101N, used for Gas Plant 2. This is essentially a separator, the purpose of which (like the inlet separator for Gas Plant 1) is designed to knock out or remove any entrained liquids not already eliminated by the slug catchers.
344 Again, Mr Henzell’s report was relied upon by Esso to support the contention that at the feed knockout drum GT-1101N in Gas Plant 2, the hydrocarbon streams were in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere. As Mr Henzell stated:
Once the entrained liquids from modelling points 1 and 2 [i.e. at the slug catchers] are recovered in the Inlet Separators to each gas plant, the gas leaving the Inlet Separators will have minimal entrainment and will meet the Test Condition. This extends through into the Mol Sieves.
345 Also supporting this conclusion in respect of knockout drum GT-1101N are the results of Mr Troupis’ and Mr Marks’ testing which showed the absence of a dew point.
Gas Plant 3 – Feed Knockout Drum
346 Esso contended taxing point 2(c) is at the feed knockout drum for Gas Plant 3, known as GN-1101. Again, it is designed to remove any entrained liquids not already eliminated by the slug catchers.
347 Mr Henzell’s report was relied upon to support the contention that at the feed knockout drum GN-1101 for Gas Plant 3, the hydrocarbon stream was in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
348 Also supporting this conclusion and in particular in respect of feed knockout drum GN-1101, are the results of Mr Troupis’ and Mr Marks’ testing which showed the absence of a dew point.
Longford Taxing Point 3
Gas Plant 1 – Inlet Gas Filter Separator
349 Esso contended taxing point 3(a) is at the inlet gas filter separator, AX-1407, for Gas Plant 1. It is located very close to the inlet separator GP-1101 (taxing point 2(a)) and is an additional separator designed to protect the mol sieves from liquids that might pass through the inlet separator in the event of some upset in the operation of the plant. The evidence is that at this stage of the process there is usually little or no liquid in the inlet gas.
350 Again Mr Henzell’s report was relied on to support the contention that at the inlet gas filter separator AX-1407 in Gas Plant 1, the hydrocarbon stream was in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
351 Given the proximity of inlet gas filter separator AX-1407 to inlet separator GP-1101, and in light of the fact that the gas at the earlier testing points was concluded to be in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere, it was contended that it may safely be inferred that at taxing point 3(a), and particularly given that this additional separator was required to protect the mol sieves from liquids, the hydrocarbon stream was in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
Gas Plant 2 – Slug Catcher Filter Separator
352 Esso contended taxing point 3(b) is at the slug catcher filter separators for Gas Plant 2, GT-1470B and GT-1470A which operate in parallel. The quantity of liquids drained from these filter separators is negligible but they are installed to ensure that there is no possibility of entrained liquids being carried to the mol sieves.
353 Again, Mr Henzell’s report was relied upon to support the contention that the hydrocarbon stream at the slug catcher filter separators GT-1470B and GT-1470A were in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
Gas Plant 3 – Slug Catcher Filter Separator
354 Esso contended taxing point 3(c) is at the filter separators for Gas Plant 3, GN-1407 and GT-1407 which operate in parallel.
355 Again, Mr Henzell’s report is relied on to support the contention that at separators GN-1407 and GT-1407, the hydrocarbon streams were in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
Longford Taxing Point 4 – Mol sieves in each gas plant
356 The mol sieves, or molecular sieves, are large diameter steel pressure vessels filled with small pellets of clay-like material which act like sieves but at a molecular level, allowing hydrocarbon molecules to pass through but blocking the passage of water and other contaminants which may remain in the hydrocarbon stream. There are molecular sieves in each of the gas plants.
357 The taxing points in question are at the exits of the mol sieves. There are six mol sieves in Gas Plant 1, eight mol sieves in Gas Plant 2 and eight mol sieves in Gas Plant 3.
358 Mr Henzell’s report was relied on to support the contention that at the exits of the mol sieves, the hydrocarbon streams were in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
359 Mr Henzell had concluded that at the mol sieve exits, the gas meets this requirement. Further, Esso submitted that the testing undertaken by Mr Troupis and Mr Marks confirmed this, as no dew point was detected at the exit of the mol sieves.
Further Taxing Points at Longford
360 Further alternative taxing points, described as points 5 and 6, were contended for by Esso in the event that the Court concluded that the various taxing points identified as 1 – 4 above were not the correct point at which to ascertain the point at which Esso’s assessable petroleum receipts are to be assessed.
361 As a further alternative, the final taxing point for which Esso contended is the boundary of the Longford plant where gas which has been produced in Gas Plants 1, 2 and 3 leaves the boundary of the plant for distribution to customers.
Longford Taxing Point 5
Gas Plant 1 – Absorbers A and B
362 Taxing points 5(a)(i) and 5(a)(ii) are at the exit of the absorbers, which are vessels used to strip the gas stream of any remaining heavy hydrocarbons through a process of absorption. From the mol sieves, the gas is cooled before being passed into the absorbers.
363 From the absorbers, the gas is then heated to a temperature suitable for delivery to the customers.
364 Mr Henzell’s second report addresses the composition of the gas streams, again by thermo-dynamic modelling, in relation to taxing points 5 and 6. Esso contended that the results of the modelling illustrates, as the conclusion states, that all of the hydrocarbon streams at the additional modelling points (ie those for taxing points 5 and 6) were considered to be gaseous at a temperature of 15°C and a pressure of one atmosphere.
Gas Plant 2 – Gas leaving the de-methaniser
365 Taxing point 5(b) is at the exit of the de-methaniser in Gas Plant 2. In addition, liquid streams which have been separated from the gas stream in earlier separators, are also processed in the de-methaniser. The liquids which are drawn off the bottom of the de-methaniser flow to re-boiling units and ultimately become feed for the crude stabilisation plant, whereas residue gas leaves the de-methaniser and is ultimately delivered to customers after being warmed and compressed.
366 Mr Henzell’s second report notes that gas leaving the de-methaniser passes his test (ie does not have a dew point and therefore is in a gaseous state at a temperature of 15°C and a pressure of one atmosphere).
Gas Plant 3 – Gas leaving the de-methaniser
367 Gas Plant 3 largely parallels Gas Plant 2. The gas leaving the de-methaniser is at taxing point 5.
368 Again, Mr Henzell’s second report concludes that the gas leaving the top of the de-methaniser is in a gaseous state at a temperature of 15°C and pressure of one atmosphere.
Longford Taxing Point 6
Gas Plant 1 – Gas entering heat exchanger GP901B and GP901D
369 The gas which exits the absorbers (taxing points 5(a)(i) and 5(a)(ii)) is then heated by being passed through a series of heat exchangers. The points at which the two parallel gas streams enter the first of these heat exchangers are where taxing points 6(a)(i) and 6(a)(ii) are found. The heat exchangers warm the gas to a temperature of 20 degrees Celsius before it passes through the Residue Gas Scrubber prior to final delivery to customers. From the scrubber, the gas passes through the metering station and is co-mingled before leaving the Longford Plant.
Gas Plant 2 – Gas entering heat exchanger at GT911 and compressor GT305
370 The gas which exits the de-methaniser, which is taxing point 5(b) discussed above, flows to heat exchanger GT-911 in Gas Plant 2 which is taxing point 6(b), following which the residue gas, by then heated, enters compressor GT-305 which is taxing point 6(c). This compressor, which is the last in a series of compressors, is necessary in order to raise the pressure of the gas to a pressure sufficient for delivery to customers.
371 According to Mr Henzell, at this point, the gas is in a gaseous state when at a temperature of 15°C and a pressure of one atmosphere.
Gas Plant 3 – Gas entering heat exchanger GN911 and compressors GN302A and GN302B
372 The gas which exits the de-methaniser (taxing point 5(c)) is warmed by passing through a series of heat exchangers – GN-911 being the first. Again, the purpose of the heat exchanger is to warm the gas and it is then compressed before being cooled, at which time it is ready for delivery to the gas transmission pipeline. Taxing points 6(d), 6(e)(i) and 6(e)(ii) are at heat exchanger GN-911 and compressors GN-302A and GN-302B respectively, in Gas Plant 3.
373 Mr Henzell’s second report was relied upon to support the proposition that the gas at these points is gaseous when at 15°C and at a pressure of one atmosphere.
Final taxing point – Exit of the Longford Plant
374 It appears common ground that the gas which exits the Longford plant was in a gaseous state at a temperature of 15°C and a pressure of one atmosphere in relation to the second sales gas period.
Specific issues raised by the parties
375 An issue arose as to the relevance of water droplets and additives. In my view, the presence of water droplets or additives is relevant to determining the gaseous content. It was accepted by Esso that under certain operational scenarios such as when gas production is increased rapidly (known as ramping-up) liquids in the pipelines comprising both condensate and a water/MEG solution may be swept into the slug catchers as liquid slugs, and that on such occasions it is likely that some of the condensate and water/MEG will be carried over into the overhead gas stream from the slug catchers in droplet form.
376 According to Mr Heath, this would occur, however, for a matter of hours at a time and not for extended periods of a day or longer. From the top of the slug catchers, the streams pass through two sets of further separators before entering the mol sieves in the gas plants themselves: the separation equipment is known as the inlet separator (Gas Plant 1) and the feed knockout drums (Gas Plants 2 and 3) which are followed by the filter separators in each plant which are prior to the mol sieves.
377 Mr Heath gave evidence that although MEG is added to the gas streams at the top of the slug catchers, very little if any of it passes through the inlet separators to the filter separators which lie beyond them.
378 In any event, it is common ground that by the mol sieves, after which the streams have been through the slug catchers, the inlet separators (or knockout drums) and the filter separators, the streams would be free of liquids, including water, and contamination (ie MEG).
379 Although Mr Aron suggested that methanol may also be present if introduced, and would be carried downstream through pressure vessels equipped with mist eliminators as a vapour, Mr Aron accepted that if methanol was used to treat hydrates at Longford, that part of the plant where the hydrate occurs would normally be isolated and bypassed.
380 In any event, according to Mr Heath methanol was not used in normal operating conditions and would only have been used if hydrates formed.
381 I accept Mr Heath’s evidence relevant to water droplets and additives.
382 Another issue concerned the presence of heavier hydrocarbons. Whether or not a hydrocarbon stream satisfies the condition of being gaseous at standard temperature and pressure (‘STP’) is dependent on the presence or absence of very small quantities of the heavier hydrocarbons C11-C14. Mr Henzell noted that the sampling carried out by Messrs Marks and Troupis was only able to establish that, at the time of sampling, there were less than 0.001 mol percent of these hydrocarbons present (that is, ten ten-thousandths of one percent). Mr Henzell then modelled the effect of varying quantities of these hydrocarbons and concluded that a change of five ten-thousandths of one percent made the difference between the stream being gaseous and liquid at STP.
383 Mr Henzell accepted that it was beyond the scope of measurement technology being used to ascertain whether or not the streams contained five ten-thousandths or ten ten-thousandths of one percent of C11-C14 at the time of sampling. No sampling was undertaken throughout the second period so as to establish the exact C11-C14 compositions at the various taxing points relied on by Esso.
384 Mr Henzell only carried out this analysis at the exit to the Gas Plant 1 inlet separator (that is, taxing point LFD2(a)).
385 I accept that this is a position where satisfaction of the criterion that the stream be gaseous at STP depends on the presence or absence of minute quantities of C11-C14 that are immeasurably small. However, I accept the evidence of Messrs Troupis and Marks as referred to previously, and the evidence given by Mr Henzell, as referred to above, which indicates that I should rely upon the inference sought to be drawn that heavier hydrocarbons were not present from the taxing point 3, which is the separation immediately before the mol sieves. In theses circumstances, I can be satisfied, that at taxing point 3 and beyond the required gaseous state has been proved as contended for by Esso.
386 Further, I need to make mention of the issues raised by Mr Aron, upon which the Commissioner made submissions.
387 In his second report Mr Aron concluded with respect to the physical characteristics that:
(a) the substance passing through points LFD1(a) and LFD1(b) would not comply due to the presence of liquid MEG and the presence, at times unknown, of liquid hydrocarbons and water carrying over from the Slug Catchers during certain operations;
(b) the substance passing through taxing points LFD2(a) and LFD2(b) would not comply due to the presence of liquid MEG; and
(c) the substance passing through taxing points LFD1(a), LFD1(b), LFD2(a), LFD2(b), LFD2(c), LFD5(b), LFD5(c), LFD6(b), LFD6(c), LFD6(d), LFD6(e)(i) and (ii), LFD7(a) and LFD7(b) would not comply, at times unknown, due to the presence of liquid MEG.
388 I have already considered the issue of the presence of heavier hydrocarbons, and now turn to MEG and the liquid carryover issues.
(i) MEG
389 I have in part dealt with this issue in dealing with the relevance of water droplets and additives. MEG is injected on the platforms and is present in the gas pipeline streams that arrive at the Longford Plant. MEG is always present in the liquids entrained in the gas flow from the top of the slug catchers (that is, taxing point LFD1). MEG is also continuously injected at points between the slug catchers and the inlet separators (that is, between taxing points LFD1 and LFD2).
390 Mr Heath and Mr Henzell agreed that the MEG is present at the exit stream from the slug catchers either as a liquid film on the walls of the pipe or as a mist (that is, tiny droplets carried in the vapour stream) but that it is not possible to quantify the relative proportions of liquid and mist. This MEG mist does not evaporate at STP and its presence means that the substance would not be gaseous due to the presence of liquid MEG.
391 As MEG is present both in the exit stream from the slug catchers and is injected between the slug catchers and the inlet separator, Mr Aron concluded that some of this MEG would carryover through to the inlet separator exit (that is, taxing points LFD2). Mr Henzell’s evidence is that he would expect MEG to penetrate this far only during periods of ramping-up and heavy entrainment. As I have indicated already it is common ground between the parties that MEG would not penetrate as far as the mol sieves (that is, taxing points LFD 3 and 4).
392 On the basis of Mr Henzell’s evidence, and the evidence of Mr Heath described above as to the use of methanol, I do not consider that the Commissioner’s submissions based on the presence of liquid MEG can be accepted.
(ii) Liquid Carryover
393 The second potential cause for the substance not to be gaseous at STP is liquid carryover from the slug catcher exits. Liquid carryover refers to the condition where liquids (that is, heavier hydrocarbons and water) are entrained in the gas flow that exits the slug catchers. There are always some liquids present in the gas flow because the slug catchers only perform a rough gas/liquid separation and they are not fitted with mist elimination devices. The issue is whether there would be liquids present at STP. The gas plants contain two layers of separators (the inlet separator and the inlet filter separator) downstream of the slug catchers that are designed as precautions to remove any such liquids before they reach the mol sieves.
394 In his second report Mr Aron concluded that during ramping-up (that is, increases in the gas flow) and pigging operations there would be a high liquid loading on the slug catchers. This liquid loading would be sufficient to ensure that the exit stream from the slug catchers (that is, taxing points LFD1) would contain liquids at STP at these times.
395 In his report Mr Henzell reached a like conclusion, namely, that during periods of high liquid loading in the slug catcher, such as pigging or gas flow ramp-up, it is likely that the exit stream will contain liquids at STP.
396 The only dispute seemed to be when ramping-up events would occur, and this is in relation to the LFD1 taxing points.
397 I agree with the Commissioner that the testing by Messrs Marks and Troupis, being limited to one day, would not assist in this enquiry.
398 I also agree with the Commissioner that Esso would need to show that the ramping-up events did not occur so as to affect the substance passing through the LFD1 taxing points in circumstances where there is evidence that ramping up events have and could occur.
Other matters
399 Other issues arose as to the application of the criterion required by the amended definition of sales gas.
400 In the main my conclusions above are relevant to the other requirements. As the trial progressed the parties seemed not to be in disagreement over whether the other criteria were satisfied depending upon certain facts found by the Court.
401 In these circumstances and having regard to the factual matters I have found, I do not delve further into the other criterion.
LIQUEFIED PETROLEUM GAS – QUESTIONS 6 AND 7
Primary Position
402 Among the products produced by Esso as part of the Gippsland facilities for sale by the joint venturers were commercial propane and commercial butane (‘the liquefied petroleum gas products’). Each of these products was a mixture of propane and butane in which the propane and butane comprised more than 50% by weight of the mixture: commercial propane typically comprised around 97% propane and 3% butane; and commercial butane typically comprised around 97% butane and 3% propane.
403 In substance, these products were produced by subjecting the petroleum recovered from Bass Strait to a continuous and integrated process of separation and filtration which took place on the offshore platforms, at Longford and at LIP. They were produced upon the completion of the processing carried out at LIP.
404 I make the following findings about the liquefied petroleum gas products and the process of their production:
(a) the liquefied petroleum gas products, together with ethane, were three of the five products which Esso recovered from the petroleum for sale;
(b) they were produced as part of the one integrated process that was applied to the whole of the recovered petroleum, which in essence involved separating the petroleum into its constituent components; and
(c) the hydrocarbon stream at the exit of Longford described as “raw LPG” which was subject and dedicated to the ongoing process of producing the products at the exit of LIP and, at the exit of Longford, was not in a marketable state.
405 Esso’s Manual sets out the following description:
The petroleum produced from the Bass Strait project yields five commercial products after it has been recovered at the offshore platforms and processed onshore.
Commercial propane and commercial butane are collectively referred to as LPG, liquefied petroleum gas. Raw LPG is a term used to identify the mixture of ethane, propane and butane that is transported by pipeline from the Longford plant to the Long Island Point plant.
The typical unprocessed gaseous petroleum stream arriving at Longford consisted of components which were further processed into saleable products.
Long Island Point … receives raw LPG (ethane, propane and butane) from Longford via a pipeline dedicated for that purpose. LIP has a fractionation plant which splits the raw LPG into its components, namely, ethane, propane and butane. The fractionation plant would normally be part of the gas processing plant, but for economic reasons, the final separation is made at the shipping point at LIP.
Generally speaking, the objectives of processing the raw natural gas is to recover the natural gas liquids and remove the impurities and to produce sales gas. The sales gas must burn well, not burn too hot. This is achieved by producing a sales gas for customers which meets the technical specifications stipulated in the sales agreement. The predominant component of sales gas is methane. The other components of the raw natural gas are separated and sold as propane, butane, ethane, and stabilised crude.
The raw LPG [from the CSP at Longford] together with raw LPG from the gas plants [at Longford] is piped to Long Island Point for separation into its constituent commercial products.
The raw LPG form Longford is processed at Long Island Point (“LIP”) in three parallel processing plants to separate the raw LPG components and produce three products: commercial ethane, commercial propane and commercial butane.
406 Throughout both the first and second periods, LPG was defined in s 2 of the PRRTA Act to mean a mixture that includes propane and butane, where the propane and butane comprise more than 50% by weight of the mixture.
407 Following from my interpretation of the PRRTA Act and my findings the following would follow.
408 The liquefied petroleum gas products produced upon completion of the processing at LIP constituted LPG and therefore a marketable petroleum commodity as defined in s 2 of the PRRTA Act. Prior to that, there was no LPG product. The liquefied petroleum gas products were not products to which the exclusion in the definition of marketable petroleum commodity applied because none of them was a product produced from another product of a kind referred to in paragraphs (a) to (f) (inclusive).
409 The liquefied petroleum gas products produced upon completion of the processing at LIP became an excluded commodity by virtue of being sold at the exit of LIP. Accordingly, the assessable petroleum receipts derived by Esso in respect of LPG were the sales consideration receivable, less expenses payable, in relation to the sale of commercial propane and commercial butane pursuant to s 24(b) of the PRRTA Act (for the first period) and s 24(1)(b) (for the second period).
410 However, Esso made these contentions:
(a) during the first period, it produced sales gas at a number of alternative points within the plant on the offshore platforms and, during the second period, it produced sales gas at a number of alternative locations within the plant at Longford. Esso says that part of the liquefied petroleum gas products sold at LIP were products produced from this sales gas and hence were excluded from the definition of a marketable petroleum commodity; and
(b) the remainder of the liquefied petroleum gas products sold at LIP (that is, that part of those products not said to have been produced from sales gas) or, in the alternative, all of the liquefied petroleum gas products sold at LIP were produced from LPG produced at the exit of Longford and hence were excluded from the definition of a marketable petroleum commodity.
411 Esso’s first contention is dependent on the success of its contentions in relation to sales gas in the first and second periods. For the reasons given in relation to these periods, the first contention is rejected, as is Esso’s contention in relation to the liquefied petroleum gas products said to have been produced from such sales gas.
412 I also reject the second contention.
413 On the way I have interpreted the PRRTA Act and upon the findings I have made, nothing occurred at or before the exit of Longford that created from a process of production an end product in the form of LPG. The “raw LPG” at that point was and remained committed and dedicated to a process of production designed to create particular products by subjecting the mixture of hydrocarbons to separation, filtration and commingling.
414 Further, the “raw LPG” which left Longford was not a marketable product. It was committed and dedicated to the process of production which commenced on the platforms, continued at Longford and was to be completed at LIP. There were no sales of LPG at the exit of Longford and at that point the “raw LPG” did not meet Esso’s specifications for the commercial propane and commercial butane sold by it. This is not to say that meeting these specifications is necessarily required for a product to be marketable. The fact is that in the relevant tax years the product was not sold or marketed when it left Longford.
415 Esso contended that the processing involving the “raw LPG” is comparable to that concerning stabilised crude oil and hence it would be unremarkable for the “raw LPG” to be taxed at the exit to Longford. However, the stabilised crude oil that exits Longford is the final marketable product and is sellable as such. It is moved to LIP for sale as that is the nearest deepwater port. The “raw LPG” that exits Longford is still only in an intermediate and unmarketable state and will undergo further processing at LIP to produce the three marketable products commercial ethane, commercial propane and commercial butane. Further, any later refining of the crude oil in an oil refinery so as to produce (via both separation and chemical reaction) a large variety of oil products is not comparable to the processing that the “raw LPG” undergoes at LIP. The latter processing is merely the last stage in the ongoing separation and filtration that the raw petroleum undergoes to produce the marketable products.
416 Question 6 would be answered ‘None’. Question 7 is not applicable.
Secondary Position
417 In case I am wrong in my approach to these questions, I make the following findings.
418 LPG is produced from the top of the product debutanisers at Longford, two of which are part of the CSP and are located near the back section of Gas Plant 1 and one of which is in Gas Plant 2. The LPG is stored in tanks known as ‘bullets’ before being transported by a dedicated pipeline to Long Island Point for fractionation into the commercially sold products propane, ethane and butane.
419 Mr Heath gave evidence about the composition of the LPG streams leaving Longford where he again exhibited data from the MBS showing that for the duration of the relevant period the percentage by weight of propane and butane was well over 50%. He referred to and exhibited data obtained from tests of the composition of the streams coming from the debutanisers which confirmed this. His evidence was not challenged in cross-examination. I accept the evidence given by Mr Heath.
420 Mr Aron’s evidence was that the LPG stream (when averaged on a monthly basis as provided for by the MBS) constitutes a mixture that includes propane and butane, where the propane and butane comprise more than 50% of the mixture. According to Mr Aron, the propane and butane percentage by weight varied from a minimum of 79.08% (in December 1998) to a maximum of 89.81% (in November 1993).
421 Mr Aron qualified his conclusion by reference to the statement that:
It cannot be discerned from evidence presently on the record as to whether or not there were short-term within-month instances (e.g. operational upsets) when the propane and butane content of the stream flowing through the LPG Taxing Point fell below 50 wt.%, and so I have not been able to conclude my investigations in that regard.
422 I agree with Esso that such qualification does not result in the conclusion that the statutory requirement has not been met if Esso’s contentions were otherwise accepted for the following reasons:
(a) First, it is not disputed that the average composition exceeded 50% propane and butane by weight by a very substantial margin. Given this, the Court can conclude on the balance of probabilities that the requirement was met in the same way it did in relation to the main gas platforms and the 50% methane by weight criterion.
(b) Secondly, there is no factual evidence of any short term operational upsets having occurred save for the Longford fire in 1998 which resulted in production of LPG ceasing.
(c) Thirdly, Mr Heath responded to Mr Aron’s speculation about possible upsets and within-month incidents and referred to the following factors:
(i) the fact that the ninety or so laboratory tests of LPG samples were, in his view, reliable – the samples were consistent with the conclusions drawn from the MBS and in addition the samples were taken from the debutanisers, which are upstream from the surge tanks. In evidence that was again not challenged in cross-examination, Mr Heath explained that the surge tanks had an effect of “damping out” any possible fluctuations in production;
(ii) the fact that Mr Heath was unaware of any operational upsets as contemplated by Mr Aron which would have been sufficient to result in the stream being less than 50% by weight propane and butane. His evidence was that any operational upset necessary to result in the stream being less than 50% propane and butane would be of such a significant magnitude that the production of LPG would cease. The only such incident in the relevant period was the Longford fire in 1998 which resulted in cessation of production of LPG for several months.
423 If Esso’s primary contention was accepted, then when the LPG left the bullets and entered the dedicated LPG pipeline for transport to Long Island Point it would have moved away from the place of its production (either the debutanisers in the Longford Plant or the plant itself) other than to a storage site adjacent to that place, or alternatively would have moved away from a storage site adjacent to the place of production (the “storage site” being the LPG bullets in which LPG is temporarily stored before transport).
ETHANE AND STABILISED CRUDE OIL – QUESTIONS 8 AND 9
424 Esso’s contentions in relation to ethane and stabilised crude oil are consequential on Esso’s contentions in relation to sales gas and LPG. For the reasons given above, those contentions have been rejected. Esso’s contentions in relation to ethane and stabilised crude oil must also be rejected. As no quantity of gas became an excluded commodity as referred to in Questions 1 and 3, and no quantity of LPG became an excluded commodity as referred to in Question 6, Questions 8 and 9 do not arise.
425 The position can be summarised as follows.
426 Ethane, as a marketable petroleum commodity, was produced at the LIP from the “raw LPG” stream sent via pipeline from Longford to LIP. From LIP, the ethane was sent via pipeline owned and operated by the joint venturers to Altona where it was sold to Esso’s customers. Title to the ethane transferred close to the customers’ premises at the end of the pipeline. Ethane became an “excluded commodity” by virtue of being moved away from the place of its production at LIP to Altona. The assessable receipts derived by Esso in respect of ethane were thus the market value of the ethane immediately before it was moved away from LIP pursuant to s 24(c) (for the first period) and s 24(1)(c) (for the second period).
427 Stabilised crude oil was produced at Longford and piped to a storage facility (the ‘tank farm’) at LIP, from where it was 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 is not owned or operated by the joint venturers. Title to the stabilised crude oil passes at the point it is loaded onto the ships or at the exit of LIP into the WAG pipeline. Stabilised crude oil therefore became an ‘excluded commodity’ by virtue of being moved away from the place of its production to the tank farm at LIP. The assessable receipts derived by Esso in respect of stabilised crude oil are thus the market value of that product immediately before it was moved away from Longford pursuant to s 24(c) (for the first period) and s 24(1)(c) (for the second period)
428 In these circumstances, I do not need to consider the further submission of the Commissioner that the terms of the Netback Settlement Agreement dated 25 February 2002 between Esso and the Commissioner preclude Esso from excising the assessable receipts derived by it in respect of ethane or stabilised crude oil. However, I say this in passing. I do not consider that the Netback Settlement Agreement has any relevance to the question formulated for the Court’s determination. Further, I do not consider that the Netback Settlement Agreement has any relevance in the context of the tax appeal brought under Pt IVC of the TAA. Any remedy that the Commissioner may seek under the terms of the Netback Settlement Agreement must and could be pursued outside the statutory tax appeal brought under Pt IVC. In any event, I need not pursue these issues.
GAS USED FOR ELECTRICITY GENERATION – QUESTION 10
429 Esso had included in its assessable receipts for each of the years of income in dispute an amount representing the market value of gas used by it to generate electricity at Longford and sold into the Victorian electricity grid. Esso has then objected to the inclusion of these amounts in its assessable receipts.
430 The electricity has been generated using six electricity generators at the Longford Plant and has been used, primarily, to produce power for the pumps at the CSP and GP1, GPR2 and GP3, and for general building amenities (eg air-conditioning) and lighting. Surplus electricity, however, has been sold into the Victorian grid. The circumstances of the generation and use of this electricity are described by Mr Heath, which evidence I accept as relevantly described below.
431 The Commissioner accepted that sales gas used to generate power consumed at Longford does not become an excluded commodity and as such give rise to assessable petroleum receipts. However, the Commissioner contended that the market value of gas which resulted in the production of surplus power sold to the SECV should be brought to account as assessable petroleum receipts under s 24(c) (for the first period) and s 24(1)(c) or s 24(1)(e) (for the second period).
432 Esso submitted that the amounts so included should be excised for these reasons:
(a) First, if Esso’s primary contention concerning the taxing point for sales gas is accepted by this Court, then the taxing point for the vast majority of gas used to generate electricity sold into the grid will be at the six platforms, and not when sold at Longford.
(b) Secondly and in the alternative, if, as the Commissioner contended, the taxing point for sales gas is when natural gas is sold, then no part of the gas used for electricity was sold, nor did it become an excluded commodity by reason of it having been further processed or treated or moved from the place of its production.
433 I do accept though that even if it could be demonstrated that the gas used to generate electricity became an excluded commodity (prior to use in generating electricity, but other than for the reasons contended for by Esso in these proceedings), any such treatment or processing or movement for that purpose would have been for “use in carrying on or providing operations, facilities ...” that comprise the Longford project, thus engaging the exclusions found in s 24(c)(ii) for the first period and in s 24(e)(ii) for the second.
434 It seems to me to be question of fact as to the connection between the processing, treatment or movement on the one hand and the carrying on of the facilities at Longford on the other. Mr Heath explained how the gas has been used to generate electricity for use at the Longford Plant. Power requirements differed significantly as different operations dictated how much power was made available. Mr Heath explained that there was a need to maintain “absolute security over power supply”, particularly with respect to gas plants. All the gas may be needed to ensure a sufficient supply of reliable electrical power to meet all the demands of the plant. Generating surplus power permits Esso to apply the surplus it has produced to cure immediately any cut in supply following a failure at one of the six generators, thus avoiding the instability arising from “brown outs”, ie where overall voltage stops because of generator failure. Any eventual sale of surplus power is an incidental outcome of its production. The purpose of using the gas for electricity generation is to ensure a safe and reliable flow of electricity in the carrying on of the facilities at Longford. The treatment and processing of the gas was in fact for use (when treated or processed) in carrying on the operations and facilities at Longford.
435 In my view, Esso has also demonstrated that all the gas to be used for electricity generation was obtained before the completion of the process at Longford. Therefore, all the gas being used to generate the electricity was in fact obtained before the completion of the process at Longford. Mr Heath, particularly at paragraph 484 of his affidavit sworn on 22 December 2007 differentiated between processed gas and sour fuel gas. I consider that his evidence indicates that the relevant sales gas was not at the stage of being ready for sale, but was being solely used in carrying on operations at the Gippsland facilities.
436 I find that during the whole period and at the time the relevant gas was treated or processed, it was being so treated and processed for the generation of the power at Longford to ensure a sufficient supply of reliable electrical power to meet the demands of the facilities.
437 Therefore, I reject the Commissioner’s contentions regarding gas for surplus electricity.
TAKE OR PAY AND MLMDQ – QUESTIONS 11, 12 AND 13
438 Both the MLMDQ and take or pay issues concern whether the relevant payments are assessable petroleum receipts. The central question for the Court to determine is whether one or more of the payments constitute “consideration receivable … in relation to the sale” of gas for the purpose of paragraph 24(b) of the PRRTA Act.
439 If Esso had been successful in the taxing point dispute, the MLMDQ and take or pay issues would then have only been relevant to the sales gas derived from liquid hydrocarbons coming from the Longford crude stabilisation plant.
Summary of the facts relevant to the take or pay issue
(a) Relevant provisions of the SECV Agreement
440 Under the 1981 Consolidated Natural Gas Sales Agreement made on 1 January 1981 between Esso and Hematite Petroleum Proprietary Limited (which subsequently assigned its rights to BHPBP) (together, ‘the SECV Sellers’) and the SECV, the SECV Sellers agreed to supply natural gas to the SECV. The SECV Agreement consisted of two parts: Part A, which is the part relevant to these proceedings, and Part B, which set out principles to apply if the parties wished to enter into a further agreement for the supply of gas after the expiry of Part A. All references below are to Part A of the agreement.
441 Under clause 2.1 of Article II of the SECV Agreement, the agreement expired when SECV took the Total Contractual Quantity of Gas or on midnight, 31 December 1996, whichever occurred first. Because SECV did not take the Total Contractual Quantity of Gas the agreement expired on midnight, 31 December 1996.
442 Under clause 7.3 of Article VII of the SECV Agreement it was agreed that if the amount “otherwise paid or payable” by the SECV to the SECV Sellers for gas in any year (excluding certain defined amounts) was less than an amount equal to the Minimum Annual Payment (‘MAP’) for that year, the SECV was obliged to pay the difference to the SECV Sellers. MAP was defined in clause 7.1 of the SECV Agreement in the following terms:
The Minimum Annual Payment in respect of a particular Year shall be the amount calculated by adding to the sum of the Monthly Fixed Charges applicable in the Year under Clause 19.1 an amount determined by multiplying the Minimum Annual Quantity of Gas for that year by the average of the twelve Unit Commodity Charges applying in each of the Months of that Year and used for calculation of the Monthly Variable Charge as set out in Clause 19.1.
443 The difference between the amounts paid by the SECV under Article XIX and the MAP in a given contract year is referred to as a ‘Shortfall Payment’.
444 Article XIX of the SECV Agreement dealt with pricing. Clause 19.1 set out that the SECV was to be charged a Monthly Fixed Charge determined under cl 19.1(a)A (invoiced as the ‘Demand Charge’) plus a Monthly Variable Charge, based on the quantity of gas supplied in that month, exclusive of Make Up Gas, and determined under cl 19.1(a)B (invoiced as the ‘Commodity Charge’). There was an obligation on the SECV to make the MAP.
445 It was further agreed under clause 7.4 of the SECV Agreement that no rights accrued to SECV by reason of the payment of a Shortfall Payment other than the right to receive Make Up Gas. Clause 8.1 of the SECV Agreement stated that if the amount of gas taken by SECV in any year was less than the Minimum Annual Quantity (‘MAQ’) for that year (as defined in clause 7.2), SECV had the right to take the difference between the two quantities, being the Make Up Gas, over the next succeeding four years. It was agreed that Make Up Gas, when taken by SECV, would be free of further payment save in certain defined circumstances (clause 19.6 of the SECV Agreement).
446 Although the parties intended that the Make Up Gas be calculated by reference to the MAQ, the averaging of the twelve monthly commodity charges means that the relationship between the MAP and MAQ could diverge if gas was not supplied evenly throughout the year and the unit price fluctuated throughout the year.
447 Clause 8.3 of Article XIII of the SECV Agreement provided that the right to Make Up Gas would not be able to be exercised after Part A of the SECV Agreement expired unless circumstances of force majeure existed:
Make Up Gas will not be available after the expiration of this Part save that if, at such expiration, Buyer wishes to take Make Up Gas and establishes that Buyer's inability to take Make Up Gas was due to circumstances of Force Majeure as provided in Article XXIV, Sellers shall, notwithstanding and within one Year after such expiration, deliver up to 133.5 x 106 Therms of Make Up Gas to Buyer in accordance with the terms and conditions of this Part which shall be deemed to continue in full force and effect as far only as may be necessary to regulate such delivery.
(b) Esso’s PRRT and income tax treatment of Shortfall Payments
448 Esso returned the payments it received from SECV under clause 7.3 of Article VII of the SECV Agreement as assessable petroleum receipts in the year in which SECV took the Make Up Gas to which each payment related.
449 Both Esso’s income tax treatment of the Shortfall Payments and its PRRT treatment were consistent with Taxation Ruling TR 96/5 Income Tax: Take or Pay Contracts, save for the fact that Esso did not treat the 1997 payment as an assessable petroleum receipt in the year of tax ended 30 June 1997.
(c) Year of tax ended 30 June 1997
450 Genvic took less than half of its MAQ of gas for the 1996 calendar year. Mr Heath explained that the reason for Genvic taking so little gas in the final year was that it had been taking more gas than it really needed. The Newport Power Station was using the gas to generate additional electricity, which it was selling into the spot market at a discount. The sales of electricity at a discount were driving down the price of electricity, which had the potential to interfere with the State Government’s privatisation of the power industry. The Government therefore took steps to relieve Genvic from incurring losses from its take or pay obligation, as a result of which it reduced the amount of gas it took in the final year. Therefore, there was a shortfall to the MAP, and under cl 7.3 of Article VII of the SECV Agreement it was required to pay the resulting shortfall between the invoiced amounts and its MAP for that year. But no Make Up Gas could be taken by SECV in the succeeding four years by virtue of having made that payment, because Part A of the SECV Agreement expired on 31 December 1996 (cl 2.1 of Article II and cl 8.3 of Article VIII of the SECV Agreement).
451 The principal take or pay issue is whether the 1997 payment, which is the amount that SECV paid to satisfy its obligation to make the MAP for the 1996 calendar year under cl 7.3, is an assessable petroleum receipt for the purposes of s 24(b) of the PRRTA Act in the year of tax ended 30 June 1997.
452 Esso did not return the 1997 payment as an assessable petroleum receipt, but it did disclose it in Schedule 4 to its PRRT return for the year ended 30 June 1997, together with an explanation for its omission. The Shortfall Payment that was invoiced for the year ended 31 December 1996 ($11,753,357.87) differs slightly from the amount that was initially set out in Schedule 4 to the applicant's PRRT return for the year ended 30 June 1997 ($11,754,349.00). No issue arises out of this slight discrepancy.
(d) Background to the take or pay issue in the years of tax ended 30 June 1991, 1993, 1995 and 1996
453 Esso returned the Shortfall Payments it received from SECV as assessable petroleum receipts in the year in which SECV took the Make Up Gas. Some of the Make Up Gas that the SECV took after 1 July 1990, which was the date when PRRT commenced to apply to the Bass Strait, related to Shortfall Payments for the 1987 and 1988 calendar years, which preceded the introduction of PRRT. The SECV also applied the Shortfall Payments in the 1991 and 1993 calendar years to Make Up Gas, which Esso returned progressively as the SECV took the Make Up Gas.
454 If the Commissioner was correct in his contentions that the MAP received on the expiration of Part A of the SECV Agreement is either “for” or, alternatively, “in relation to”, the sale of a marketable petroleum commodity produced from petroleum recovered from the production licence areas recovered from the Bass Strait project in the 1996 calendar year, then there would be an apparent inconsistency in the treatment of those earlier Shortfall Payments. As such, Esso contended, in the alternative to its position in respect of the year of tax ended 30 June 1997, that these amounts were assessable petroleum receipts in the year in which Esso received the Shortfall Payments, and not in the years in which the SECV took its entitlement to Make Up Gas.
(e) Consequential increases in assessable petroleum receipts
455 The SECV made Shortfall Payments in the 1991 and 1993 calendar years but Esso did not return these payments as assessable petroleum receipts in those years. Therefore, consistently with an undertaking Esso gave to the Court (Esso Australia Resources Pty Ltd v Commissioner of Taxation [2009] FCA 272) at [37], consequential increasing adjustments will be required in the years of tax ended 30 June 1992 and 30 June 1994 if Esso succeeds in having the Shortfall Payments excised from assessable petroleum receipts in the year in which the SECV took its entitlement to Make Up Gas.
Summary of the facts relevant to the MLMDQ issue
(a) Terms of the Sales Agreement
456 The MLMDQ payments arose from a variation of the Sales Agreement which was made as of 1 January 1975 between Esso and Hematite Petroleum Proprietary Limited (which subsequently assigned its rights to the entity that is now BHPBP) (together, ‘the sellers’) and GFC (‘the buyer’).
457 The Sales Agreement provided for a specified volume of natural gas, sourced from dedicated gas fields (the Marlin, Barracouta and Snapper gas fields), to be sold to GFC. Over the term of the Sales Agreement, the sellers agreed to deliver 50 billion therms of natural gas to GFC. Of that amount, 30 billion therms of gas was deemed to be dedicated to GFC’s ‘C’ Market, which broadly comprised GFC’s industrial customers, and the remaining 20 billion therms of gas was deemed to be dedicated to GFC’s ‘D’ Market, which comprised all other customers.
458 In addition to providing for the sale of the gas, the Sales Agreement also included rules (primarily in Articles IV and V) governing how much gas could be taken in a 24 hour period for the purposes of supply and demand management. Demand for gas could vary significantly day to day. Therefore, it was in GFC’s interest to be able to acquire sufficient gas to satisfy its consumers' needs on days of peak demand. It was also in the sellers’ interests to limit the daily rate at which gas could be delivered due to infrastructure and other constraints, such as the limited capacity of the sellers’ infrastructure to produce gas from the dedicated fields, transport it to Longford and process the gas to the required specifications.
459 Under cl 5.1 of Article V, the sellers were only required to deliver the quantity of gas required by GFC each day during the term of the Sales Agreement up to an agreed amount (the MDQ). Under cl 4.3(a) of Article IV GFC was required to inform the sellers of the MDQ to be set for the contract year five years in advance (the MDQ for the years 1975-1979 was pre-determined and set out in Table I to the Sales Agreement). Subject to a minimum requirement, the MDQ nominated by GFC had to be equal to or less than the sellers’ maximum daily supply capacity (described as ‘the maximum limit to MDQ’ or ‘MLMDQ’) determined in accordance with the Sales Agreement.
460 Table I to the Sales Agreement set out the MLMDQ to apply from 1980 to 1989. Under cl 4.3(b), for contract years from 1990 the sellers were required to nominate their MLMDQ 10 years in advance. When nominating the MLMDQ 10 years in advance the sellers were required to use their best endeavours to satisfy the buyer’s Maximum Daily Requirement (‘MDR’). Under cl 4.3(c) the buyer was required to provide the sellers with its bona fide forecast of MDR 10 years in advance.
461 These provisions dealing with the rate at which gas could be taken during any day did not alter the total volume of gas to be acquired by GFC under the Sales Agreement. Nor under the Sales Agreement did GFC pay any specified consideration to Esso under the mechanism by which the parties established the MDQ.
(b) The sellers' MLMDQ nominations under the Sales Agreement
462 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 |
463 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 |
464 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
465 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’).
466 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 |
467 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.
468 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’.
469 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
470 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 |
471 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
472 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.
473 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.
474 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.
475 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.
476 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).
477 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.
478 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.
479 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.
480 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.
481 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.
482 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.
483 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.
484 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.
485 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.
486 On this basis I do not accept the position taken by the Commissioner in relation to the MLMDQ payments.
487 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.
488 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).
489 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.
490 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.
491 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.
492 Justices Johnson and Higginbotham concurred in the judgment.
493 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.”
494 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.
495 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.
496 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.
497 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.
498 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.
499 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.
500 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.
501 I turn to the 1991 and 1993 Shortfall Payments.
502 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.
503 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.
504 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.
505 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.
506 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.
507 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.
508 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.
509 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
510 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.
511 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.
512 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.
513 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.
514 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.
515 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 Act 1995 (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
516 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:
