The state government has been presented with five options to resolve the imbroglio threatening WA’s coal supplies.
When politicians talk about energy, they love to talk about the transition to renewables and the bright future for Western Australia in that space.
Yet, the messy reality they currently confront in WA is that coal continues to provide about one-third of the state’s electricity; and coal supplies are fragile.
This is not a new problem and it’s arguably getting worse.
WA’s two coal miners – foreign-owned Premier Coal and Griffin Coal – have been losing money for years, with Griffin placed in the hands of receivers last September.
Some of their customers have been forced to import coal because they couldn’t buy enough locally and have privately expressed concern about a likely repeat of that situation.
The government has hired multiple advisers to help it resolve the issues but so far has little to show for its efforts.
Its decision to shut all state-owned coal-fired power stations – and the shifting timeline for those closures – has added to the uncertainty.
That recently prompted the Australian Energy Market Operator (AEMO), which manages WA’s energy market, to take drastic steps to ensure system stability.
The difficulties facing the industry have wide ramifications. For starters, there are about 600 staff and contractors directly employed by Premier and Griffin at their neighbouring mines at Collie.
Any disruption to their operations would flow rapidly through the state.
Listed mining company South32 is also a big buyer of coal for its Worsley Alumina operation.
Other customers include miners Iluka Resources and Tronox.
They are among the few miners in WA that value-add to raw materials, and their products include the critical minerals that are a key factor in the energy transition.
But to do this, they need coal.
Iluka, for instance, uses coal as a reductant in the production of value-added synthetic rutile and says there are no commercially or technically viable options.
Premier is the state’s largest coal miner, with sales revenue last year of $190 million. Griffin is smaller but still a major business, with sales last year of $117 million.
The pressures facing the sector are most acute for Griffin; it is heavily indebted, in receivership and at a commercial impasse with its main customer.
Bluewaters Power buys about 1.6 million tonnes of coal each year from Griffin, nearly two thirds of the miner’s annual output.
Griffin’s only other customer is Worsley Alumina, which uses coal in its five steam boilers.
It has started converting the boilers to natural gas in a move that is a microcosm of what is happening across the energy sector.
Worsley has highlighted the environmental benefits of this change but also acknowledged it “mitigates the impact of local coal supply challenges”.
While this change makes perfect sense for Worsley, it illustrates the mounting and inter-linked problems facing the energy market.
“If Worsley demands less coal, the problem for the remaining users gets worse,” one executive told Business News.
“This is a death spiral.”
The loss of sales make life harder for the coal miners and adds to pressure on domestic gas prices as demand increases at a time of tight supply.
The state government has long hoped Griffin and its customers would achieve a commercial resolution to get the mining operation onto a stable footing.
Local advisory firm Sternship Advisers, led by veteran company director and former Western Power chair Neil Hamilton, was hired to expedite that process, but to no avail.
In its place, the government has hired Sydney firm Ad Astra Corporate Advisory.
Other advisers hired by the state government include KPMG, Preston Consulting and most recently law firm Ashurst (see table).
Opposition energy spokesperson Steve Thomas said the bill for advisers was still growing.
“It is a total of $1.36 million for advice that has to date delivered nothing but more uncertainty,” he said.
“The government has no idea what it is going to do.”
Business News understands Ad Astra has outlined five policy options.
The government has refused to comment on these options, but industry insiders say they capture all of the plausible choices.
The first has been dubbed ‘rapid replacement’ and proposes an accelerated rollout of alternative energy sources, such as gas and renewables, so the state has less reliance on coal.
That is superficially appealing but ignores the significant pressures facing the energy market.
The state government has actually moved in the opposite direction, with Energy Minister Bill Johnston announcing in August a deferral of the planned closure of one of its coal-fired power generators.
That was after AEMO forecast a big shortfall in energy supplies in WA within three years.
A second, radical option is headlined ‘buy it all’.
Under this proposal, the government would buy both Griffin Coal and Premier Coal and integrate their operations.
It has long been accepted that mining at Collie would be more efficient if the adjacent open-pit mines were combined, to achieve more economies of scale and gain access to high-grade deposits.
However, this would be a radical and financially very risky move for any government.
A third option is ‘let it fall over’; let Griffin collapse and put the assets on the market.
This would force Griffin’s lenders, led by India’s ICICI Bank, to crystallise an estimated $1.5 billion of debts.
But with Griffin’s track record of big losses (about $60 million a year) and uncertainty over the sector’s future, it is unclear who would want to buy the assets.
A fourth option has been dubbed ‘limp along’.
This would be a continuation of the current approach, with taxpayers propping up Griffin Coal with regular cash injections.
During the past 12 months, the state government has advanced $30.5 million to Griffin’s receivers and managers, led by Deloitte partner Matt Donnelly.
He told Business News this had allowed Griffin to invest in equipment and staff and led to major improvements in the business.
The workforce has increased by 15 per cent over the last year, with Griffin employing 320 staff and contractors.
Production totalled 2.3 million tonnes over the past year and was on track for a 20 per cent increase year-on-year.
The coal stockpile for Bluewaters is currently 215,000 tonnes, the highest it has been in five years.
Mr Donnelly said September and October deliveries to Bluewaters were 150,000t per month, which was a record level since his appointment in September last year.
It remains to be seen whether these improvements are sufficient to address a long period of underinvestment and decline in the business, evidenced by last year’s coal imports.
And they come at a direct cost to the taxpayer, which is politically unpalatable.
The fifth and final option for the government is the long-hoped-for commercial outcome.
This points the finger at Bluewaters, which is Griffin’s largest customer.
Bluewaters is owned by Japanese companies Kansai Electric and Sumitomo, but they have written off their investment in the business after incurring big losses.
It is effectively controlled by hedge funds, notably Oaktree Capital and Elliott Management, which bought the company’s debts at knockdown prices.
If Bluewaters was to pay more for its coal, it would need to reprice the electricity sales contracts it has with its customers, which include Synergy, the Water Corporation and WA’s largest goldmine: Newmont’s Boddington gold operation.
In other words, it would flow through to higher electricity prices for households and businesses.
Again, an unpalatable option for government.
Steve Thomas says money spent by government so far has delivered more uncertainty. Photo: David Henry
However, before anyone can talk meaningfully about a ‘commercial’ outcome, they would need answers to some bigger questions.
“How long will the state need coal for base load power?” one adviser asked rhetorically.
“How much coal will we need per year and for how long?
“The answer to those questions affects your commercial outcome.”
The state government’s announced plan is for Synergy to close down all coal-fired power stations by 2030.
But as the government announced in August, that timetable has started to shift, with the closure of one of the units at Muja deferred.
And many observers believe more changes will be needed.
The task facing the state is to implement sufficient alternative energy sources to offset the loss of base load coal, and that means a huge and rapid investment in renewables, battery storage and potentially gas.
AEMO has highlighted the enormity of the task.
A report released in August concluded there was an “urgent need” for investment in WA’s electricity system to meet forecast demand.
After factoring in existing and committed capacity supply, it forecast a shortfall of 945 megawatts in 2025-26 and about 4,000MW by 2032-33.
That compares to total capacity currently of about 6,000MW.
One contributor to AEMO’s worrying outlook was the closure of the state-owned coal power stations, which will take 932MW of generating capacity out of the state.
AEMO also assumed Bluewaters would be shut by 2030, taking a further 434MW of capacity out of the system.
It based this assumption on recent challenges in coal supply, mounting economic pressures posed by alternative energy sources, escalating fuel and operating costs, and increasing demand for sustainable energy.
The independent market operator also factored in increased demand from industry, particularly for the electrification of the state’s four alumina refineries.
Another new factor was increased demand from lithium refineries – with three currently under construction in the South West – and planned hydrogen projects.
A second key finding in AEMO’s report has highlighted the gravity of the situation.
It has increased its so-called reserve margin, or contingency, by between 568MW and 648MW across the next few years. This was based on the dramatic assumption that three of the largest electricity generating units in the state could be out of service simultaneously at a time of peak demand.
It has forced AEMO to take two remedial steps.
It is procuring additional capacity of 326MW through its supplementary reserve capacity mechanism.
This means paying extra for electricity supplies or, more likely, paying industrial customers to cut their demand for electricity at times of peak demand.
It has done this only twice before, and on each occasion for much smaller volumes:174MW in 2022 and 120MW in 2009.
AEMO has also launched an expression of interest campaign to procure a further 354MW of capacity, starting from October 2025, to ensure the energy system stays reliable.
AEMO’s application to do this highlighted three factors, including strong demand growth across the forecast period and the anticipated exit of coal-fired power generation capacity.
It also referred to “fuel supply challenges and prolonged unplanned facility outages, which have led to the unavailability of coal and gas capacity.”
The extra capacity is expected to cost the market in the order of $160 million, far more than the subsidy doled out to Griffin so far.
Amidst these big macro themes, there have been some intriguing corporate manoeuvres surrounding the state’s coal miners.
These include the appointment last month of administrators to take charge of a company called Oceania Resources.
A subsidiary of Indian conglomerate Sindhu Trade Links, Oceania had a curious role in Griffin’s recent history.
In March 2015, Oceania signed a mine service agreement with Griffin, for which it was paid $US3 million per year.
It has never been clear what services Oceania provided to Griffin, which runs its own mining operations through subsidiary WR Carpenter.
Five months after signing the contract, Oceania loaned $US60 million to Griffin.
At that point in time, Griffin was about $1 billion in debt, with the main lender being India’s ICICI Bank.
Curiously, Oceania borrowed the $US60 million from ICICI before lending it to Griffin.
It was ICICI that funded the purchase of Griffin by Lanco Infratech in 2011.
The Indian group bought Griffin out of receivership after previous owner Ric Stowe took on big debts to build the Bluewaters power station.
That was after Griffin lost coal supply contracts with Synergy, having been undercut by Premier.
Lanco borrowed $750 million to buy Griffin and, at the time, outlined an ambitious growth agenda.
It intended to increase production four-fold to about 15mt, with plans to build a railway to Bunbury and commence coal exports.
Lanco’s strategy was misguided and the price it paid extravagant.
That became clear one year later, in 2011, when China’s Yancoal bought Premier for $296 million: less than half the amount Lanco paid for a similar business.
Another intriguing recent development was the appointment of new liquidators to Griffin.
Cor Cordis held the role for a year before being replaced by Sydney firm WLP Restructuring.
That has spurred speculation WLP could seek to disclaim or renounce the contract Griffin holds with Bluewaters and demand a better price.
More detail on that could come to light next year when Bluewaters proceeds with an examination of Griffin’s receivers, Deloitte, in the Federal Court.
Stepping back from these corporate manoeuvres, Mr Thomas says the best thing the government could do is halt the planned closure of its coal power stations and focus instead on securing energy supplies, including new gas power.
Only then, he says, should it consider closing the coal power plants.