Brave new world of Queensland Petroleum Royalties
Announcement of implementation of volume-based model
Please note this article has been updated as at 25 September 2020
On 8 June 2020, the Queensland Government announced a new petroleum royalty regime which is intended to provide greater certainty in relation to the royalty payable by petroleum producers. The new rules are set to come into effect from 1 October 2020.
How did we get here?
The changes are as a result of a review of the royalty regime initiated in November 2019. That review proposed a variety of recommendations by the Petroleum Royalty Review Working Group (Group). This Group was established as a result of producers in the gas sector rallying together to raise concerns about the complicated and burdensome nature of the existing royalty regime. Following the Group’s review in late 2019, it was recommended that the following three royalty models be evaluated prior to the implementation of a new royalty regime:
1. Volume Model;
2. Industry Model; and
3. Legislated Netback Model.
The Industry Model was submitted by APPEA and its overarching principle was that petroleum royalties should be payable to the State based on what APPEA refer to as the true wellhead value of petroleum sold.
The Legislated Netback Model involved a legislated formula for netting back from the ultimate sale price of LNG to a deemed arm’s length price in the field, but the Group ultimately found that it ‘was not suitable for the existing configuration of the Queensland gas industry’.
The Volume Model was ultimately selected by the Government as the preferred scheme and is explained further below.
The new regime – Volume Model
As a result of the review, the Government selected the volume-based model as the appropriate method for calculating royalties in the petroleum sector moving forward. In the June 2020 initial announcement, the Treasurer and Minister for Infrastructure and Planning, Cameron Dick, said that ‘the new volume-based model would support affordable supply for domestic customers, appropriate returns for Queenslanders and fairness for gas producers’.
On 13 August 2020, the proposed regime was formalised in the Royalty Legislation Amendment Act 2020 (Qld).
Actual sales price or benchmark
Under the volume-based model, royalties will be calculated on the volume of petroleum produced multiplied by the ‘average sales price’ per GJ multiplied by a percentage rate on a sliding scale.
In circumstances where the person purchasing the petroleum is not a related entity for either the producer or the producer’s related entity reseller (i.e. a sale to an independent buyer) the ‘average sales price’ will be the actual sales price per GJ of petroleum sold by the producer directly, or indirectly through a related entity.
In circumstances where:
1. the person purchasing the petroleum is a related entity for either the producer or the producer’s related entity reseller;
2. information required for determining the royalty rate is not available for a producer when the royalty return is lodged; or
3. a benchmark price decision applies (i.e. where the Commissioner or the Producer elect to use a benchmark price rather than actual sales price).
The ‘average sales price’ is the benchmark price – as prescribed in the Petroleum and Gas (Royalty) Regulation 2004 (Qld) (Regulations) (which is based on market indicators for that type of petroleum).
Different classes of petroleum
Both the relevant benchmark price and the royalty rates depend on the petroleum type, with the following four classes of petroleum being established:
1. gas that is not converted into LNG and is sold domestically (not to an LNG project) – referred to in the Regulations as domestic gas;
2. gas supplied by a producer that is not a member of an LNG project to an LNG project (feedstock gas supply gas);
3. gas produced by an LNG project that is not domestic gas (export LNG) – referred to in the Regulations as project gas; and
4. petroleum in liquid form (including crude oil and condensate) – referred to in the Regulations as liquid petroleum.
The royalty rates for each class of petroleum are on a sliding scale that escalates depending on the average sales price for the petroleum:
1. for domestic gas – the highest rate bracket is for gas with an actual average sales price or benchmark price in excess of $8 per gigajoule. The royalty rate in that bracket is 46 cents per gigajoule plus 0.10 cents per gigajoule for each 1 cent per gigajoule more than $8 per gigajoule;
2. for supply gas – the highest rate bracket is for gas with an actual average sales price or benchmark price in excess of $8 per gigajoule. The royalty rate in that bracket is 65 cents per gigajoule plus 0.125 cents per gigajoule for each 1 cent per gigajoule more than $8 per gigajoule;
3. for project gas – the highest rate bracket is for gas with an actual average sales price or benchmark price in excess of $14 per gigajoule. The royalty rate in that bracket is 72 cents per gigajoule plus 0.125 cents per gigajoule for each 1 cent per gigajoule more than $14 per gigajoule; and
4. for liquid petroleum – the highest rate bracket is for gas with an actual average sales price or benchmark price in excess of $100 per barrel. The royalty rate in that bracket is $7.25 per barrel plus 0.125 cents per barrel for each 1 cent per barrel more than $100 per barrel.
It has been confirmed that percentage royalty rates will be locked in for five years.
The benchmark price for domestic gas for a royalty return period is the firm End of Day Wallumbilla Benchmark Price averaged over the period.
For supply gas, project gas and liquid petroleum, the benchmark price for a royalty return period is determined by reference to the daily Europe Brent Spot Price FOB (Dollars per Barrel) converted into Australian dollars at the average hedge settlement rate for the royalty return period (Spot Price). The formulas for determining the relevant benchmark for each class of petroleum by reference to the Spot Price are set out in sections 148C, 148H and 148J of the Regulations.
Arrangements for non-tenure holders
In response to requests from industry, the reforms will allow non-tenure holders to lodge royalty returns and pay royalty, as if they are the petroleum producer, for their commercial share of petroleum produced from the tenure. This means that commercially sensitive sales information would not need to be provided by the non-holder to the tenure holder to enable a royalty to be calculated.
Implications on commercial arrangements
Whilst the new royalty regime is generally seen as a win for industry in terms of certainty and simplicity, the changes may have inadvertent outcomes. This includes impacts on existing contractual arrangements, such as:
- private royalties, which often reference government royalty regime legislative concepts,
- farm-out or deferred payment arrangements, or
- other contractual dealings with reversionary rights.
In its Consultation Paper, these issues were acknowledged, but the Government suggested that this type of flow on issue is a matter for the parties as to how the new legislative concepts are given effect, verified and enforced.
It is important that petroleum producers get on the front foot to mitigate the commercial and legal impacts of these changes, which may include:
- breach of contract,
- frustration of contract,
- default, or
- potential dispute.
Our industry leading resources team is on hand to support you in understanding how the Queensland Petroleum Royalty regime will impact your projects, and to identify practical next steps to reduce your commercial and legal risk.
Please click here if you would like to discuss this, or reach out to a member of McCullough Robertson’s specialist team (listed below).
This publication covers legal and technical issues in a general way. It is not designed to express opinions on specific cases. It is intended for information purposes only and should not be regarded as legal advice. Further advice should be obtained before taking action on any issue dealt with in this publication.