Opinion: Indonesian Government Broadens Scope of Mine Mouth Coal Pricing Regime
By: Hadiputranto, Hadinoto & Partners (www.hhp.co.id)
Monday, June 16 2014 - 09:59 AM WIB
To accommodate the development of the mine mouth program within the generally applicable framework of the Government setting a market price-based benchmark price for all sales of Indonesian coal, the Government had, in 2011, introduced regulations which exempted mine mouth power plants from the benchmark pricing scheme (thereby reflecting that there was no "market" for mine mouth coal supply).
Regulation of the Minister of Energy and Mineral Resources No. 10 of 2014 on the Procedures for the Supply and Determination of Coal Price for Mine Mouth Power Plants dated 4 April 2014 ("Regulation 10") revises the 2011 mine mouth coal pricing regime, and the amendments have been aimed further enhancing securing the supply of coal and certainty of coal price for the development of mine mouth power plant projects.
What's new?
The new features for pricing of mine mouth coal introduced under Regulation 10 include the following:
▪ Under the previous regime, in order for a coal mine to automatically qualify for the "cost plus 25%" pricing regime applicable to coal supplied for mine mouth power generation, the calorific value of the coal had to be lower than 3,000 kcal/kg (gross as received or GAR). This calorific value limitation has now been removed, and accordingly coal above 3,000 kcal/kg GAR now can receive the same cost plus pricing treatment as coal below 3,000 kcal/kg GAR.
▪ The new pricing regime is available to mine mouth power plants developed by traditional Independent Power Producer ("IPP") developers, as well as State-owned integrated power generation, transmission and distribution companies (i.e. PLN).
▪ There is now further definition of the various production cost components which are taken into account to determine what the "cost" element is, in the cost plus 25% pricing model;
▪ There are new requirements imposed before a coal supplier can be treated as a supplier of mine mouth power plant coal; and
▪ Express provisions have been introduced which imposes an obligation on mine mouth IPPs to bear the royalties payable by coal suppliers on mine mouth coal supplied to the IPP.
Coal Sale Price and Coal Base Price
Mine mouth coal pricing had previously been regulated under Regulation of the Directorate General of Mineral and Coal No. 1348.K/30/DJB/2011 on the Determination of Coal Price for Mine Mouth Power Plants ("Regulation 1348"). Under Regulation 1348, the Government applied a different coal pricing philosophy to mine mouth coal supplies depending on the coal calorific value of the coal being supplied:
- Coal with a calorific value of less than 3,000 kCal/Kg GAR must be sold at production cost plus a prescribed 25% margin.
- Where the calorific value of the coal was 3,000 kCal GAR or higher, the coal sales price can be sold at a price lower than the coal benchmark price (HPB) if approved by the Director General of Mineral and Coal ("DGMC").
With the issuance of Regulation 10, the framework has been simplified such that the Coal Sale Price is based on Coal Base Price and is subject to escalation, and there is no differentiation between coal of different calorific values. The selling point is set at the mine mouth power plant's stockpile.
The Coal Base Price is simply production cost plus a 25% margin.
A coal mining company can only submit a Coal Sale Price offer to a mine mouth IPP after it has obtained approval of its Coal Base Price from the DGMC. Accordingly, it appears likely that for future mine mouth bids, PLN requires this DGMC approval as part of the bid submission. What the detailed requirements are from the DGMC before giving such approval are not yet known - hence there does exist potential for bid delays if mine owners are not able to secure this approval within PLN's bid timeframe.
Production cost
Regulation 10 calls for the DGMC to stipulate from time to time the production costs of mining, and the Coal Base Price of the relevant mine would appear to be calculated based on these stipulated production costs. DGMC determines the production cost by considering development in technical conditions for mining and other factors that affect the average national production cost, among other things:
▪ overburden removal;
▪ coal mining/extraction;
▪ coal transportation from pit to processing site;
▪ coal processing;
▪ environmental monitoring and management;
▪ reclamation and post-mining activities;
▪ occupational safety and health;
▪ community development and empowerment;
▪ land acquisition/relinquishment;
▪ overhead;
▪ amortization and depreciation; and
▪ dead rent and/or exploitation contribution/royalty
Pursuant to the Decision of DGMC No 479K/30/DJB/2014 dated 30 May 2014, the production costs for 2014 have been stipulated as follows:
| Production Cost type | Unit | Cost |
| Overburden removal #1 | USD/BCM/km | 2.41 |
| Coal mining/extraction | USD/tonne | 1.70 |
| Coal transportation from pit to processing site #2 | USD/tonne/km | 0.28 |
| Coal processing | USD/tonne | 1.98 |
| Amortisation and depreciation | USD/tonne | 1.17 |
| Environmental monitoring and management, reclamation and post-mining activities | USD/tonne | 0.27 |
| Occupational safety and health | USD/tonne | 0.07 |
| Community development and empowerment | USD/tonne | 0.21 |
| Land acquisition/relinquishment | USD/tonne | 1.99 |
| Overheads | USD/tonne | 2.07 |
| Deadrents | USD/tonne | 0.11 |
| Exploitation contribution/royalty | USD/tonne | 16.9% of total of items above |
| Margin | USD/tonne | 25% of all items above |
| #1 The overburden removal cost is a reference cost (USD/BCM/km) that must first be adjusted to the distance of the overburden transportation, and then to be multiplied by a strip ratio. The adjustment of the overburden removal reference cost to the distance of the overburden transportation is shown in this formula: 2.41 + ((JOB - 1) x 0.7985). Where JOB = the average overburden transportation distance during mine planning. | ||
| #2 Coal transportation cost from pit to processing site is a reference cost (USD/tonne/km) and is to be multiplied by the distance of the coal transportation. | ||
It is not entirely clear how this cost stipulation by the DGMC relates to the process of the DGMC approving the Base Coal Price of a particular mining operation supplying coal to a mine mouth power plant. Clearly this annual stipulation does not take into account all of the vast array of factors that make the cost of mining at one mine more or less expensive than the cost of mining at another mining operation. For example, strip ratios, inclines for trucking coal out of pits, land compensation costs varying across different areas.
Our understanding is that this annual stipulation of production costs is used only as a reference point for the DGMC determining what Base Coal Price of a particular mine to approve. We would expect that a particular mine would be entitled to make its case for why its production costs are higher (or lower) than that set by the DGMC, and the DGMC would approve a Base Coal Price for the mine based on its actual production costs. What is not entirely clear however is whether, in putting forward d its costs, the DGMC will approve a different base production cost for each year of the term of the proposed PPA (e.g. to take into account future mine expansion costs etc), or whether a single levelised base production cost will be used for each year of the proposed PPA (subject to the escalation factors mentioned below). Based on our discussions with DGMC officials to-date, it appear s that DGMC will require a single base production cost to apply throughout the PPA term.
Whilst the annually stipulated production cost is, in our view, only a reference point for the calculation of the Base Coal Price of a particular mine, it does have a more direct importance in the calculation of the coal royalties (as discussed further below).
It should be noted that Regulation 10 clearly excludes transportation costs from pit to stockpile facilities of the mine mouth power plants - i.e. as Regulation 10 assumes the configuration of the power project is truly mine mouth (i.e. a power plant adjacent to the mine), no allowance is given for the mine owner to incur any costs in delivering coal to the power plant. This is consistent with the criteria set out for mine mouth power plant under Regulation of the Director General of Electricity No. 553-12/20/600.3/2012 dated 9 March 2012.
Escalation
Regulation 10 stipulates that the Coal Sale Price is subject to escalation due to:
▪ Rupiah exchange rate;
▪ diesel fuel price;
▪ consumer price index; and
▪ regional minimum wage.
The escalation of the Coal Sales Price occurs annually based on an agreement between the coal mining company and the IPP. Accordingly, the coal supplier and IPP are free to agree mutually acceptable weightings to be applied to each of these escalation factors (e.g. 50% weighting for fuel price, 30% weighting for Rupiah/USD movements etc), however typically PLN in its bid documentation for the development of the IPP will prescribe maximum weightings.
Commencement of the escalation of the coal price will commence on the date of PPA signing for mine mouth IPPs selling to PLN. For mine mouth IPPs which are integrated generation and distribution projects (i.e. the owner of the power plant has a business area designation to sell power directly to customers), the escalation will commence at the time the coal supply agreement is signed.
Coal Supplier Requirements
Coal mining companies that supply coal for mine mouth power plants can be COW or the holders of mining business licences (IUPs)/special mining business licences (IUPKs) for operation and production. The effect of this is to provide that non-mine owning companies (e.g. coal traders) cannot be coal suppliers to mine mouth IPPs.
Coal suppliers must meet these requirements:
▪ hold a 'clean and clear' certificate (only applicable to IUP holders);
▪ have the required coal reserves and quality for the mine mouth power plants;
▪ have obtained Coal Base Price approval from the DGMC; and
▪ must be a member of a consortium that develops the mine mouth IPP. Regulation 10 also determines that a mine mouth coal supplier must have a minimum of 10% shares in the mine mouth IPP (held through its affiliate). The requirement for the shareholding in the IPP to be held through an affiliate is consistent with the DGMC's long-standing policy of requiring that mining companies themselves limit their activities to only the mine operation (i.e. the mining company should not directly hold shares in the IPP).
There is no definition of an "affiliate" under Regulation 10, accordingly it is not clear that percentage common ownership/control threshold is required to meet the requirements of an affiliate (noting that under some mining regulations, a 20% control is sufficient to trigger the affiliate relationship).
Mine Mouth IPPs to bear the royalties payable by Coal Suppliers
As mentioned above, royalties payable by coal mining companies are included as a production cost component. This suggests that mine mouth IPPs absorb the royalties. This approach has been reflected in recent on-going mine mouth projects such as Sumsel 9 and 10.
However, for the purpose of calculation of the production royalties, Article 13 (1) of Regulation 10 determines that the royalty for coal produced in any year will be based on the higher of (i) the Coal Base Price approved by DGMC for the relevant year, and (ii) the production cost plus margin stipulated by the DGMC for the relevant year (i.e. in the case of 2014, the price determined by DGMC Decision No 479K/30/DJB/2014).
If the DGMC's annual production cost plus margin stipulation is higher in any year than the Coal Sale Price for the relevant year (meaning that the coal mine owner is paying royalties on a higher coal price than it is in fact being paid by the IPP), then for mine mouth IPP projects, the additional royalty loss of the mine owner is borne equally by the mine owner and the IPP. If the relevant project involves sale of coal to PLN for a PLN project, then the additional royalty cost is passed on entirely to PLN.
How does Regulation 10 affect existing mine mouth coal supply arrangements?
Regulation 10 will have an impact on PLN, coal mining companies and anyone currently participating or planning to participate in a bid or direct appointment for a mine mouth power project, including for an expansion of capacity of an existing mine mouth IPP. Any project falling within one of these categories must comply with the new mine mouth pricing requirements under Regulation 10.
However the new regulation grandfathers:
a. any coal sale price to mine mouth IPPs that was approved by MEMR before the issuance of Regulation 10; and
b. the result of a bid or direct appointment that was determined in a PPA before the issuance of Regulation 10.
It is not entirely clear at what point a result of a bid or direct appointment was "determined in a PPA". One clear consequence is that for a PPA that has been signed, Regulation 10 cannot be used. However the position is not clear for projects which have progressed to the stage of final bids having been submitted (and envelopes opened), but in respect of which no PPA has been signed. It is going to be difficult for PLN to require the bidders to follow the requirements of Regulation 10 in these circumstances.
Questions remain
A number of areas remain unclear or unregulated by Regulation 10:
▪ Whilst the mine mouth pricing regime is open to PLN as the holder of an integrated IUPTL, there is no present application to other non-State-owned holders of integrated IUPTLs (e.g. the developer of a mine mouth power plant who intends to distribute electricity to its own distribution area).
▪ There appears to be little flexibility for the Coal Sale Price to be adjusted to reflect changing circumstances beyond the control of the mine owner, such as changes in Governmental regulations (e.g. increased environmental or health and safety requirements, increased taxes, duties or royalties).
▪ Whilst Regulation 10 now gives PLN the freedom to structure its IPP procurement program using mine mouth IPP projects without any limitation on the calorific value of coal to be used in the project, it is yet to be seen how PLN will implement this freedom. There are strong concerns from industry that if PLN undertakes procurement programs in which (say) 3,000 kcal coal mines are competing directly with (say) 4,200 kcal mines to win the projects, due to the higher capital costs of low rank coal boilers and lower thermal efficiencies and larger mining costs due to the need to mine a larger quantity of coal to achieve the same heating value, any IPP project relying on the 3,000 kcal mine will simply not be able to compete.
Conclusion
The issuing of Regulation 10 does provide greater scope for coal mines to more easily participate in mine mouth power generation projects (through the removal of the 3,000 kcal limitation), and provides much needed further detail as to how mine mouth coal pricing is to be arrived at.
The most immediate application of Regulation 10 is going to be to the current ongoing Sumsel 9 and 10 mine mouth IPP procurement programs. In particular, the immediate focus will be on PLN to see if it amends its bid requirements to allow coal mines with coal higher than 3,000 kcal to participate in the projects, and if so, what effect this has on the consortia competing to win these high profile projects.
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fanny.kurniawan@bakernet.com
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