Areas examined The ANAO examined whether the amounts subtracted from sales receipts to calculate the amount of royalty payable are likely to be accurate and valid. Conclusion The amount of royalty paid is reduced by producers being permitted to claim significant deductions in areas such as operating costs and the depreciation of capital assets. There has been limited scrutiny of the claimed deductions. Some errors in the claiming of deductions have been identified, but the available evidence indicates that the problems are much greater than has yet been quantified. Areas for improvement The ANAO made one recommendation to improve the future approach taken to examining claimed deductions, as well as to thoroughly scrutinise past claims.

How much have producers claimed as a deductions in the calculation of the amount of royalty to be paid?

More than $5 billion worth of deductions were claimed against petroleum revenues in the 18 months to December 2015. These deductions were claimed under the broad categories of: operating costs; depreciation; cost of capital; depreciated asset disposal; crude oil excise; condensate excise; processing tariffs and joint venture participant costs.

4.1 The 2006 consolidated Royalty Schedule has been the vehicle used to define costs that may be claimed as deductions for royalty purposes. As was shown in Figure 1.2, deductions can be claimed for costs incurred in moving petroleum from a valve at the top of a well to a defined point of valuation (post-well-head costs). This includes the costs of processing, storing and transporting petroleum from each production well to an operating platform and on to an inlet (if piped) or discharge point (if shipped) at the treatment plant on Burrup Peninsula in Karratha, Western Australia.

4.2 The Schedule establishes monthly limits on the total amount of post-well-head expenditure that may be claimed as deductions, with any expenditure above those limits carried forward to the next month. With some adjustments for fuel gas, deductible costs can vary up to a limit of 50 per cent of the gross value of production for oil projects or 90 per cent of the gross value of production for gas projects for each royalty period.

4.3 Table 4.1 provides a summary of the cost categories nominated as deductible, in the Royalty Schedule.

Table 4.1: Summary of deductable cost categories in the Royalty Schedule

Cost category Comprises Operating costs Examples include costs of operating platforms in petroleum fields, environmental monitoring activities and some on-shore costs. Petroleum produced but not sold The value of gas used as fuel and the value of petroleum lost, used (excluding fuel gas), flared or vented. Depreciation of capital assets Examples include helidecks, platform mooring, storage tanks, and payments towards town and community services. Decommissioning costs Arms-length costs associated with removing post-well-head capital assets after petroleum recovery is completed. Joint venture participant costs (where additional to NWS operator costs) An agreed portion (13 per cent) of post-well-head costs associated with production, processing, storage, transportation or marketing of petroleum from the licence areas (including some insurance costs). Processing tariff The post-well-head component of any processing tariff incurred by the NWS producers for the use of infrastructure they don’t own in the NWS royalty area (provided that there is no overall increase in total post-well-head cost if the tariff had not applied). Liquefied natural gas shipping costs Operating and capital costs associated with project-owned LNG vessels including, for example, an annual capital charge for each vessel.

Source: ANAO analysis of the Royalty Schedule.

Is adequate information obtained on claimed deductions to inform compliance activities?

Any costs that are claimed as deductions by NWS producers reduce the royalty amount that is payable. DIIS relies on DMP’s compliance work and does not undertake any further activities to gain assurance that only eligible deductions have been claimed. DIIS has not agreed with DMP the deductions data that DMP should obtain and the information obtained is not sufficiently detailed to be adequately assured that only valid deductions are being claimed.

4.4 During the audit, DMP provided the ANAO with a monthly data report it receives from the NWS operator that aggregates figures across the various cost categories identified in Table 4.1 above. Another document obtained from DMP suggests that, in the past, reporting has included some more detailed information such as:

movements in non-commissioned capital asset expenses, deductions relating to commissioned capital assets and, capital asset retirements; and

operating expenditure cost items by field and facility and the percentage of those costs that are claimed to be post-well-head.

4.5 Given the actual and potential size of allowable deductions being claimed by NWS producers on a monthly basis, it would be reasonable to expect DIIS, in consultation with DMP, to have developed and implemented a robust compliance strategy and included strong controls around verifying the validity of deductions being claimed. In this regard, DIIS has not agreed any procedures with DMP or sought to obtain any direct assurance, on behalf of the Australian Government, that deductions are being claimed correctly. DIIS considers that this is not its role, and advised the ANAO that validity of deductions is a task delegated to DMP as the day-to-day administrator and that DIIS did not undertake additional verification of claimed deductions against the terms of the Royalty Schedule. As such, the Australian Government’s interests are not being adequately protected.

Does the Royalty Schedule clearly permit all of the claimed categories of deductions?

The Royalty Schedule does not permit all the deductions currently being claimed. On this basis, the ANAO has doubts about the eligibility of deductions claimed for the cost of debt and equity funded capital, excise paid on crude oil and excise paid on condensate.

4.6 As discussed in paragraph 3.2, the Royalty Schedule sets out parameters for the calculation of the well-head value including deductions. It was developed by DMP and is not a public document. Notably, the Schedule allocates responsibility to the NWS operator to review the costs and percentages that apply to deductions and to seek agreement to changes from the WA state minister. In addition, under the Royalty Act, DIIS and DMP have responsibilities, as follows:

the state minister is assigned responsibility for negotiating or determining the well-head value (including deductible costs); and

the state minister is required to comply with directions issued by the Joint Authority, on which the Australian government minister has power to decide matters (as a decision of the Joint Authority), where there is disagreement.

4.7 Based on DIIS records and advice to the ANAO only one Joint Authority direction was identified. It was dated 12 August 1993 and was issued under legislation that was repealed in 2006. The instrument directs that deductions be allowed for the cost of debt and equity funded capital and for excise paid on crude oil.

4.8 This direction is not reflected in the 2006 consolidated Royalty Schedule. For example, in regard to the cost of capital deduction, the merging of Royalty Schedules in 2006 resulted in key parts of the deduction section being omitted from the consolidated Schedule. The remaining clause no longer identifies that it is an allowable deduction. Similarly, no deductions for crude oil excise are mentioned in the Royalty Schedule.

Condensate excise deductions

4.9 Notwithstanding that the current Royalty Schedule does not explicitly provide for the deductibility of any form of excise, data supplied by DMP indicates that condensate excise deductions totalling $705.1 million were claimed for the 18-month period 1 July 2014 to 31 December 2015. The related reduction in royalty revenue as a result of those deductions was $88.1 million.

4.10 The charging of excise on the value of condensate production was first introduced by the Australian Government in 2008, with the relevant announcement noting that:

As part of this measure, the Australian Government will provide the Western Australian (WA) Government with ongoing compensation for the loss of shared Offshore Petroleum Royalty revenue resulting from imposing the Crude Oil Excise on condensate. This arises because Crude Oil Excise payments are a deductible expense for calculating the Offshore Petroleum Royalty.

An initial payment of $80 million will be paid to the WA in 2007–08, with payment in subsequent years adjusted to equal the impact of removing the condensate exemption on royalty payments to Western Australia.

4.11 Given the intended policy position that condensate excise be deductible, the ANAO sought advice from DIIS on where the Royalty Schedule provides for such deductions. DIIS was not able to identify such a clause. In April 2016, DIIS advised ANAO that the deductibility of payments made under the Excise Tariff Act 1921 was provided for by the 12 August 1993 direction and that:

In this regard we envisage that the deductibility of these costs is implicitly captured by the definition of post well head costs in the Schedule as outlined below:

“post well head costs” means:

(a) (i) such operating costs incurred between the well-head and the point of valuation as are agreed or determined to the extent that such costs are actually and necessarily incurred;

4.12 The direction instrument expressly directs that excise payable on crude oil is to be deductible, but does not refer to excise paid on condensate. Further, to the extent that the existing Royalty Schedule defines post-well-head costs, it lists them in a schedule to the Royalty Schedule or requires an agreement or a determination to be made. DIIS’ view is also inconsistent with the approach taken by DMP in relation to similar payments to government. For example, in July 2013, DMP advised the NWS operator that carbon tax payments were not an allowable deduction from the well-head, noting that:

“post well-head costs” are set out extensively in the definition of that term in item 1 of the Royalty Schedule. These do not include costs under or associated with the Clean Energy Act 2011 or any other taxing statute. … There is nothing in the Royalty Schedule to support a petroleum royalty reduction… for carbon tax related expenses.

Is there adequate scrutiny of claimed deductions?

There has not been adequate scrutiny of claimed deductions. Of note: it has been 17 years since there has been an audit of the NWS operator’s control procedures for royalty calculations;

there have been recent annual reviews by DMP of cost deductions, but this work has involved quite limited testing and there has been no major, comprehensive examination since 2006. The limited work that has been undertaken has, nevertheless, highlighted potential problem areas. But little action has been taken in response to those findings; and

more recently, the Western Australian Government commissioned consultants to undertake some data analytic procedures on capital and operating expenditure items claimed by NWS producers. That work, although quite limited in scope, has also provided some valuable insights. The report’s findings indicate that there is a risk of significant errors in the claiming of deductions. To date, there has been agreement that a net amount of $8.6 million in royalties has been underpaid requiring adjustments, but many matters identified by the consultants have not yet been addressed, and a comprehensive review of claimed deductions has not been commissioned, such that the full extent of any errors in the calculation and payment of royalties has not been quantified.

1999 examination of control procedures

4.13 In June 1999, the NWS operator’s external auditor performed procedures, requested by the NWS operator in relation to the royalty, over the controls supporting the calculation of deductions calculations for January, February and April 1998. The findings were that, subject to noted exceptions, the calculation methods were in accordance with the Royalty Schedules and the calculations and procedures were performed correctly. During the course of this ANAO performance audit, DMP provided the ANAO with a copy of the Report of Factual Findings, but it was unable to locate a copy of the appendices setting out the procedures employed and the nature of the exceptions.

4.14 DMP advised the ANAO that it had met with the NWS operator in June 1999 to discuss the factual findings and that it had ‘expressed concern that there was not an indication of internal controls testing’. This led to DMP sharing (with the NWS operator) the cost of an audit of the NWS operator’s control procedures in relation to royalty deduction calculations for January and February 1998. The purpose of this work was to express an opinion about the effectiveness of those control procedures in place at that time. The September 1999 report stated that:

the NWS operator had maintained, in all material respects, effective control procedures in relation to the calculations for January and February 1998;

the internal controls structure, within which the audited control procedures operate, was not audited and no opinion was expressed as to its effectiveness; and

any projection of the evaluation of control procedures to future periods was subject to the risk that the procedures may become inadequate because of changes in conditions, or the degree of compliance with them deteriorating.

4.15 DMP has not had any such further audits of control procedures undertaken in the subsequent 17 years.

Annual reviews by the state department of cost deductions

4.16 DIIS does not seek to obtain monthly deductions data from DMP. In April 2016, DIIS advised the ANAO that an assessment of the validity of claimed deductions is the responsibility of DMP and that it does not undertake additional assessment of claimed deductions against the terms of the Royalty Schedule. Rather, DIIS relies on work undertaken by DMP.

4.17 DMP describes this work as being a ‘royalty cost audit’. But the work is not conducted in accordance with the Australian Auditing Standards. During the ANAO performance audit, three reports were provided to the ANAO outlining the key findings of DMP’s review of deductions claimed for the calendar years: 2012, 2013 and 2014. The 2012 and 2013 reports examined a single month, with small sample sizes (the ten highest value assets capitalised in that month being reviewed along with the ten highest value operating cost items) and reliance on assurances from the NWS operator (including that the correct post well-head percentages were used for operating costs).

4.18 Each of the 2012, 2013 and 2014 reports highlighted potential problem areas relating to deductions.

4.19 DMP’s 2012 review identified problems with the NWS operator’s systems, including incorrect:

useful life periods being used in the NWS operator’s depreciation system leading to under-claiming of deductions; and

coding of depreciation methods, leading to the wrong depreciation method being used.

4.20 Importantly, the 2012 report also noted problems with how some assets were categorised in the NWS operators accounting systems, including incorrect deduction percentages being applied to expenses. In this regard, the Royalty Schedule assigns a deductible percentage to a range of operating and capital expenses that partly or fully relate to non-deductible pre-well-head (exploration and extraction) expenses and partly or fully to deductible post-well-head (transport and processing) expenses. A correct categorisation (as pre-or post-well-head, or part thereof) in the NWS operator’s accounting systems is required for the accurate calculation of deductions. The balance between pre-and post-well-head may also change over time depending on how assets are used.

4.21 DMP’s 2013 cost report outlined that deduction percentages for one of the NWS fields may no longer accurately reflect the split between pre and post-well-head costs, noting:

There is also an indication that the current approved NRA Royalty Deductions Schedule requires to be reviewed as some cost elements have changed their PWH [post-well-head] % greater than 5% requiring a review of these elements.

4.22 Both the 2012 and 2013 cost reports highlight that only limited testing was undertaken by DMP of operating cost deduction percentages (only the top 10 cost items by value were checked), but that the NWS operator had provided assurances that the rates listed in the Royalty Schedule were being used. Many of these problems were not adequately addressed following those reports, as a range of similar issues were raised in more detailed analysis commissioned by DMP, which is the subject of the 2014 cost review. This is a major weakness in the arrangement between DIIS and DMP. In particular, DMP’s 2014 cost report highlights that a ‘major’ review had not been undertaken since 2006, and that DMP lacks some of the necessary skills:

It was determined that due to the commissioning of the NRB [North Rankin B] platform and the passage of time taken since the last major audit review (i.e. 2006), that a major cost deductions review needed to be performed with the latest audit IT techniques. As this audit expertise is not held by [DMP], it was decided that experts in this field would be contracted.

4.23 In April 2016, the ANAO sought advice from DIIS about whether it had made any representations to DMP about the scope or findings of the DMP cost reports and any evidence in which it could demonstrate consideration of these documents supporting a conclusion that due process has been followed or otherwise. Notwithstanding the significant deficiencies identified by DMP, on 13 May 2016, DIIS advised ANAO that it had held discussions with DMP, but that:

DIIS officers have not had any material findings or issues that warrant formalisation of these discussions or DIIS intervention. DIIS primarily review and obtain WA DMP cost audits as a sample of the work WA DMP undertakes. This is largely a record keeping exercise to gain assurance that this function, which we would expect to form part of due processes by the administrator, has been undertaken. DIIS would only engage in additional scrutiny if there was an area of disagreement between WA DMP and the NWS Participants. [ANAO emphasis added]

2014 external review

4.24 As part of the 2013 cost report, it was recommended that a more detailed review of post-well-head percentages and claimed costs should be undertaken. In April 2015, DMP commissioned an external consulting company to perform ‘data analytic procedures’ on capital and operating expenditure items claimed by NWS producers, as part of the 2014 cost review. This was the same firm that undertook the work in 1999 (see paragraphs 4.13 to 4.15). This firm is the NWS operator’s external auditor.

4.25 The objective of the work contracted by DMP was to identify anomalies between the deductions that were claimed and those allowed, as outlined in the Royalty Schedule. The cost of the work was $30 000. This represents 0.001 per cent of the value of deductions claimed during the period reviewed. It was not undertaken as an audit under the Auditing Standards. In this respect, DMP advised the ANAO in July 2016 that:

DMP wanted flexibility and cost efficiencies in this process that could not be gained had this work been conducted under a particular level of assurance approach.

DMP wanted to keep ownership of the assessment of impacts from findings identified as opposed to allowing [the consultants] to define what was material or not.

DMP wanted to keep ownership of the risk assessment process; more specifically, the commissioning of this work was to directly address risks identified as a result of the process.

DMP wanted to be actively involved in discussing and settling [the consultant’s] approach for their analytical procedures.

DMP wanted to keep ownership of the decision making process during the review in light of any challenges and findings identified. This means that DMP actively met with and directed [the consultants] and the external engineering consultant during the conduct of their work.

DMP wanted to obtain extracts of [the consultant’s] working papers as well as a full record of all misstatements identified during the review.

DMP wanted to make sure that the engineering component and analysis conducted by the external consultant was considered in the context of legislation, the Royalty Schedules as well as any possible royalty interpretation.

4.26 The report identified some key areas of concern, summarised in Table 4.2. The findings suggest that there have been a range of incorrectly claimed deductions and a significant group of deductions for which the eligibility of the expenditure, or the magnitude of the percentage claimed, was questioned. The final report was provided to DMP in October 2015 and forwarded to DIIS on 30 November 2015. It included the following four recommendations to DMP:

review and revise the Royalty Schedule to better align with NWS expenditure;

consider further analysis and review of the NWS operating and capital expenditure for prior periods to determine and quantify any over or under payments in royalties;

analyse the trends of the asset retirements to identify unusual movements in the deduction amount; and

request that the NWS operator identify the royalty impact as a result of variances identified between the asset capitalisation dates and depreciation start dates.

Table 4.2: Key findings of the report

Expenditure Amount over/under claimed ($m)1 Estimated royalty impact ($m)2 Operating expenditure identified to have been incurred prior to the well-head (such as costs associated with the deconstruction of drilling equipment and facilities) 24.7 3.2 Operating expenditure requiring ‘operational judgement’ to determine the appropriateness of the percentage claimed (such as engineering, business improvement and marine services for some fields) 218.4 Not quantified Capital expenditure identified to have been incurred prior to the well-head (such as drilling, standby drilling services and the retention of rig crews between drilling campaigns) 21.6 2.7 Capital expenditure for which additional deductions might be claimable. This includes where a lower than allowable percentage of the cost was claimed or the cost was not in a category listed in the Royalty Schedule (for example, the report questioned the degree to which costs relating to field development plans and feasibility studies were fully deductable) -21.1 -2.6 Capital expenditure for which additional operational information was required to determine the appropriateness of the percentages applied to costs claimed (such as an appraisal well, substructure studies and a power generation system) 21.1 Not quantified

Note 1: Potential under-claiming is indicated by a negative value.

Note 2: Estimated by the report using the maximum royalty rate of 12.5 per cent.

Source: ANAO analysis of the report.

4.27 In July 2016, DMP advised that it had consulted with the NWS operator and agreed on a net figure of $8.6 million in underpaid royalties based on the report’s detailed findings. Based on DMP figures, the net underpayment consists of:

$17.0 million in underpaid royalties based on over-claiming of $135.9 million (noting that where individual expenditure items were identified by the report as being over-claimed in 2014, DMP followed those items back to 2008); and

$8.4 million in overpaid royalties based on under-claiming of $67.0 million. Specifically, DIIS advised the ANAO that this related to a capital deduction that had been under claimed in the past due to an accounting error by the NWS operator.

4.28 Significant effort is required to resolve the status of another $218.4 million in operating expenditure deductions and $21.1 million (items two and five in Table 4.2) in capital expenditure deductions for which the size of the percentage claimed was questioned by the report. These deductions were identified as requiring ‘operational judgement’ and further ‘operational information’ to determine the appropriateness of the percentages applied to 49 operating cost categories and 21 capital assets. Based on calculations advised by DIIS to the ANAO in July 2016, the maximum underpayment of royalties is suggested to be in the order of $11.6 million, if all such deductions were found to be non-compliant.

4.29 In a broader context, the findings of this review highlight the absence of a shared understanding of the application of the Royalty Schedule. The lack of available information also makes it difficult to gauge the extent of incorrect claiming. In July 2016, DMP advised the ANAO that it considers the data analytical procedures used in the review to have been consistent with that required to obtain a reasonable level of assurance over claimed deductions. But, the report explicitly disclaimed providing any level of assurance which, reflected limitations such as:

the report only examined deductions claimed in calendar year 2014 ;

; the sampling method adopted was not designed to be representative of the population of deductions, therefore, the results of the report cannot be extrapolated in a way such that the magnitude of deductions incorrectly claimed in the broader (not sampled) population could be estimated without additional work being undertaken. Instead, the testing was limited in scope to: 'fuzzy' word searches of cost category descriptions to identify possible pre-well-head expenses ; identifying changes to the percentage being claimed against individual cost items within the 2014 calendar year and matching operating expenditure cost items to the Schedule, where possible; and recalculation of depreciation and cost of capital deductions for some assets;

some report findings were ‘not able to be quantified due to the information available and require further commercial discussions’; and

no examination of deductions for expenses specific to individual producers. Producers are permitted to claim a ‘Joint Venture Participant Cost’ for costs they individually incur from the production, processing, storage, transportation or marketing of petroleum. The Schedule permits claims of a fixed portion (13 per cent) of operating costs and LNG shipping costs, as well as any insurance costs agreed with each producer. But, the Schedule also notes that if there is a significant change to the level and nature of the operating costs, the claimable percentage will be reviewed. In this regard, the Schedule anticipates that the deductions claimed will match the costs individual producers have incurred. This has not been reviewed as producers are not asked to provide evidence to substantiate any such costs that have been incurred.

4.30 The issues identified in the report suggest that there may have been incorrect claiming going back several years that requires further examination. For example, capital assets are depreciated over multiple years and where such an asset was fully depreciated and decommissioned prior to 2014, incorrect claiming would not have been identified and examined in the report. Based on evidence provided by DMP, items incorrectly claimed in 2014 have been reviewed back to 2008 to establish whether incorrect claims had been made against those items in consecutive years. However, there has not been a review of deductions claimed for assets retired between 2008 and 2013. DIIS and DMP both indicated to the ANAO that they are not intending to conduct such a review.

4.31 The findings of the report indicate a risk of considerable errors in the claiming of deductions that warrants further, more forensic investigation. In July 2016, DIIS advised the ANAO that the report:

highlighted the magnitude of the task to perform a deeper analysis of the costs relating to the NWS project. As resourced, neither DIIS nor DMP has the time or expertise to scrutinise deductions claimed in their entirety. DIIS is supportive of commissioning this type of work for future cost audits, however recognises that even then, there can be no guarantee of absolute assurance due to the size of the NWS project. It is unreasonable to expect that DIIS and DMP should deliver 100 per cent assurance over the completeness and accuracy of NWS royalty revenue. [ANAO emphasis added]

4.32 The work undertaken to date provides further support for updating and improving the descriptions contained in the Royalty Schedule and requiring reporting that demonstrates compliance with the Royalty Schedule.