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Legal Updates | New Indonesian Mine Mouth Coal Pricing Regulation Introduces Pricing Flexibility

On 4th April 2016, the Minister of Energy and Mineral Resources ("MEMR") issued a new regulation on coal pricing for mine mouth power projects, Regulation No. 9 of 2016 on the Procedures for the Supply and Determination of Coal Price for Mine Mouth Power Plants ("Reg 9"). Reg 9 replaces the previous MEMR regulation No. 10 of 2014 on the same matter ("Reg 10").

As with Reg 10, the new Reg 9 provides for the pricing of coal from mines to a mine mouth power plant to be on a cost-plus basis, but the key change introduced under Reg 9 is to allow the "plus" to be set within the rate of 15% to 25%, instead of the previously fixed margin of 25%. Several news media have quoted that the main driving factor for this latest change in the mine mouth coal pricing regulation was the views expressed by both Perusahaan Listrik Negara (PLN) and private Independent Power Producer (IPP) developers that a fixed 25% margin over the mining costs was too high, given the declining trend in coal price and the reducing margins being faced by coal suppliers selling coal into the seaborne market.

The "cost plus 25% margin" concept was first introduced in December 2011 by a regulation of the Director General of Mineral and Coal ("DGMC"). It was applied only to mine mouth power projects using coal lower than 3,000 kcal/kg (gross as received or GAR) to attract coal mining companies to develop and utilise low-rank coal for domestic use and to meet demand of power supply in Indonesia amidst the high demand of coal from the global market.

However, the downturn of the global coal market since 2011 has changed the dynamics of coal mining in Indonesia such that the number of coal mining companies that are interested in developing mine mouth power projects has continued to grow in recent years. For example, a list issued by PLN in September 2015 indicates that there are 34 companies (including consortiums of companies) that are interested in developing mine mouth power projects, but in December 2015 the number had increased to 47 and in March 2016, the number had increased to 50. Please see the link here for the recent list issued by PLN.

Despite the growing interest of coal mining companies to develop mine mouth power projects, the number of mine mouth projects offered by PLN is limited. In addition, before the issuance of Reg 9, the media reported that PLN plans to revise its existing business plan (RUPTL) to reduce the number of capacity of coal-fired power projects by approximately 8,000 MW as it seeks to prioritise clean sources of energy, which may affect the number of mine mouth projects available to be offered by PLN.

What has changed?

Most of the provisions of Reg 9 remain the same as Reg 10. However, Reg 9 features these key changes:


Basic criteria for a mine mouth power plant coal supply arrangement

Reg 9 provides four basic criteria for a mine mouth power coal supply arrangement:

  • The coal to be used is economically more feasible to be utilised for a mine mouth power project;
  • The availability of coal supply is guaranteed by the coal mining company throughout the operation of a plant;
  • The location of the power plant is a maximum 20 kilometers away from the location of the coal mine; and
  • The coal price does not include transportation costs, except transportation costs from the mine location to the power plant's stockpile.

Reg 9 is not clear on whether an inspection will be conducted to verify the satisfaction of the principles upon each application for a Coal Base Price approval and whether DGMC has the authority to decide whether or not a project meets the above basic principles, (i.e., whether a project should be a mine mouth project or non-mine mouth project).

Margin by range

Under Reg 10, the margin on the allowed costs of production is fixed at 25% and coal mining companies can only make an offer to sell coal to mine mouth IPPs after obtaining approval of the Coal Base Price. As such, a coal mining company can only offer coal sales price to Mine Mouth IPPs after the coal mining company's Coal Base Price is approved by the DGMC (on behalf of the MEMR).

Reg 9 introduces a new concept where the margin is based on agreement with the mine mouth IPP (being the offtaker) within a range from 15% to 25%. If no agreement is reached within 60 days after the date of issuance of Reg 9 or the start of the negotiation, the DGMC decides the margin on the basis of, among other things, transparency, fairness and national/regional interests.

However, Reg 9 is silent on the procedure (application process) and time frame for the issuance of the decision. Reg 9 is also not clear on the approach or methodology that DGMC will use in determining the appropriate margin for the coal mining companies. Our discussions with the officials of the DGMC seem to suggest that the DGMC may invite the disagreeing parties for a hearing and analyze the empirical data before making any decision and the decision will also take into account, among other things, benefits to the community.

Nevertheless, the new concept introduced by Reg 9 may offer flexibility to coal mining companies and mine mouth IPPs to agree to a margin based on a formula as long as it is still within the range. For example, this may open the possibility for the parties to agree to a higher margin for the first several years to enable the coal mining company to pay back loans to its lenders, and then after the loan is fully repaid the margin level declines gradually to compensate for the higher margin upfront. The new concept also opens up competition among coal mining companies before a mine mouth power project is offered to the public by PLN (e.g., during a partner selection process) as mine mouth IPP developers will seek out potential coal mine partners who are willing to accept a margin lower than 25% in order to make the bid to PLN look financially more attractive.

Escalation starts on plant COD

Under Reg 9, escalation of the agreed coal price starts on the commercial operation date ("COD") of the plant. Accordingly, the risk of inflationary increases from when the Coal Base Price is approved until the power plant COD is borne by the coal supplier, which therefore, it must be factored into the discussions at the time the Coal Base Price (and the margin on top of production costs) is negotiated between the coal supplier and the IPP.

Treatment of existing projects

Like Reg 10, Reg 9 grandfathers:

  • any coal sale price to mine mouth IPPs that was approved by the MEMR before the issuance of Reg 9; and
  • the result of a bid or direct appointment that was determined in a PPA before the issuance of Reg 10.

It is not entirely clear at what point a result of a bid or direct appointment was "determined in a PPA". However, one clear consequence is that Reg 9 cannot be used for a PPA that has been signed.

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, are likely to be affected by Reg 9, and PLN may require the bidders to follow the requirements of Reg 9 in these circumstances.


One of the fundamental issues holding back the development of mine mouth power plants has been, in view of the steep decline in global coal prices, PLN's reluctance to accept IPPs where the coal supply cost was based on a fixed 25% margin above the production costs. When seaborne coal is trading at US$100/tonne, the economic rationale of PLN purchasing at production cost +25% is justifiable. However when seaborne coal is trading at half that price and coal exporters are having to bear reduced margins, PLN has found it difficult to just pay the cost +25% to a mine mouth coal supplier.

It is hoped that the pricing flexibility introduced under Reg 9, and in particular the discretion given to mine owners to accept a margin lower than 25%, will restart a number of the planned mine mouth power projects which are embedded in PLN's 10-year generation plan (known by its Indonesian acronym RUPTL).

Hadiputranto, Hadinoto & Partners, Member of Baker & McKenzie International - 25th May 2016

icone share

Indonesia Energy Snapshot

Contribution to GDP: 3.44% (2016) Oil & Gas Imports: $1.22 billion USD (Jan 2016)
Proven Oil Reserves: 3.69 billion barrels (2016)
Proven Gas Reserves: 2.85 trillion cubic metre (2016)
Proven Coal Reserves: 28 billion tonnes total reserves (2015)
Proven Potential in Geothermal Energy: 27 GW
Proven Potential in Hydropower: 75 GW
Other Energy Sources: Coal Bed Methane, Biomass, Waste, Ocean Current, Solar, Wind.
Current Energy Mix: Petroleum 41%, Coal 30%, Natural Gas 23%, Renewables 6% (2014).