As President Donald Trump sets the energy policies for his administration, policy uncertainty is rife for the utility industry. The new administration is inheriting a power sector in a profound, market-driven transition, but whether it will choose to harness or hamper the clean energy transition remains unclear.

But for power sector insiders looking for answers, Australia’s recent experience could provide some constructive lessons.

From 2007 to 2013, federal support for renewables in Australia allowed wind and solar to significantly cut into the power mix down under. That growth stalled after 2013, when the election of a conservative government undercut federal support for utility-scale solar and wind. Even so, policies and market supports from the nation’s six states allowed distributed energy resources (DER) to reach transformative penetrations on Australia’s grid.

“Australia does not have all the answers, but it shows states should be enabled to lean in and make sure the market continues to develop even if federal support drops off,” said Tanuj Deora, chief strategy officer at the Smart Electric Power Alliance (SEPA), a nonprofit that encourages collaboration between utilities and clean energy companies.

Australia's distribution system operators have been “pushed by unique policy and economic factors and have shown how using new technologies and new policy designs can be workable,” Deora told Utility Dive after a recent fact-finding tour of the world’s biggest island nation.

Though polls show a majority of Australians believe in human-caused climate change, power prices averaging as high as $0.30/kWh gave traction to arguments from conservative Abbott and Turnbull governments, like those made by President Donald Trump, for coal and natural gas consumption.

“Coal is a very important part, a very large part, the largest single part of the global energy mix and likely to remain that way for a very long time,” current Prime Minister Malcom Turnbull said shortly after being elected. “Coal is a very important part of the energy agenda.”

By the end of 2015, Australia’s resource mix was nearly 15% renewables, but Turnbull’s administration continues to lower incentives put in place by previous governments for utility-scale wind and solar. Discouraged developers have left or are thinking of leaving the country.

But the high rates, along with tariff reforms, drove DER penetrations to new highs. Advocates say new ways of more accurately valuing DER, like valuation concepts being developed in the U.S., will open the door to still more opportunity.

A “first wave” of tariff reforms enabled a highly decentralized system that incorporated DERs through a more efficient, fair, and resilient “universal pricing framework,” said John Bradley, CEO of Energy Networks Australia (ENA), a trade group for Australian utilities.

On that system, a “second wave” of incentives and innovation will create transactive energy and peer to peer trading “without creating unfair cost transfers between customers,” he added.

Why DER boomed in Australia

Though the origins of the Australian and American distributed energy transitions differ, they evolved almost in parallel.

Issues with grid reliability, including a 2007 blackout of 200,000 homes in the state of Victoria, drove a demand for grid modernization and more DER, Deora said. Reforms led by national regulators were put in place.

A major government investment in a smarter, more reliable grid was approved to meet anticipated rising Chinese demand for Australian commodities, he said. It was justified by significant expected growth in Australia’s gross domestic product (GDP) and the resulting increased load on the transmission and distribution systems.

In the global financial crisis, however, China’s GDP growth dropped, and the electricity load impacts on Australia’s system did not materialize, Deora said.

Around the same time, Australia’s states began pushes to take advantage of their enormous solar and wind energy resources with aggressive feed-in tariffs (FITs).

“The states seemed to be competing to see which could offer the highest [FIT],” Deora said.

That initiated a growth cycle for renewable and distributed generation (DG) in Australia. With volume, manufacturers – including the Chinese global giants – were developing economies of scale that drove hardware costs down.

The grid modernization and unexpectedly flat loads forced regulators to grant Australia’s network operators, analogous to U.S. distribution utilities, rate increases. Higher electricity bills and attractive FITs, some as high as $0.40/kWh, according to Deora, raised interest in distributed generation among customers. Increased volume drove installation and customer acquisition costs further down, and demand for rooftop solar skyrocketed.

States also introduced aggressive energy efficiency programs that met with particularly enthusiastic customer response from DG owners. With more efficient homes and businesses, rooftop solar customers could export power at the high FIT rate.

The 2016 penetration on solar accessible roofs in New South Wales, Australia’s biggest state, and Victoria, its second biggest state, was nearly 15%, according to the Australian Photovoltaic Institute. The penetration in Queensland, its third biggest state, was nearly 30%. Its fourth biggest state, Western Australia, was at about 23%. And South Australia, its fifth biggest state, was at over 29%.

These large portions of the addressable market are not driving grid defection, Deora said. “Australians want to stay connected to the grid so they can take advantage of the FITs. But there is load defection, as both DG owners and other customers seek to minimize their utility bills with efficient technologies and smart practices.”

Opportunities in the Australian DER boom

With a thriving distributed solar sector in place, the FITs have served their purpose and, Deora said. And like net energy metering policies in the U.S, states are beginning to withdraw them.

In the absence of these policies, solar owners’ exported generation is now often credited at utilities’ avoided cost for fossil generated power, which can be as low as $0.04/kWh to $0.06/kWh.

With retail electricity as high as $0.30/kWh, solar owners see the greatest value from their generation from “energy arbitrage,” Deora said. With the costs of distributed solar and behind the meter (BTM) battery energy storage already at all-time lows and still falling, “the electricity they generate with their solar and store in the batteries is cheaper than the electricity they can buy from the grid,” he said.

Electricity rates almost doubled from 2008 to 2014, said Chris Vlahoplus, sustainability practice lead at energy consultant ScottMadden, who was also on the SEPA fact-finding tour.

“Even though the FIT has now been stepped down, higher electricity rates continue to make DER attractive,” he said.

With the last FIT scheduled to be phased out by the end of this year, the BTM battery energy storage market is growing as fast as solar did, Deora said. Installed battery storage capacity is estimated to have reached 44 MW in 2016 and is expected to be 132 MW in 2020, according to GTM Research. 2013’s $8 million market is expected to reach $448 million by 2020.

The world’s biggest battery players, including Tesla, Sonnen, and LG Chem, are attacking the market aggressively.

Australia’s power sector has, to date, not followed the lead of U.S. utilities and blamed DER for rising power prices, Deora said. They recognize that rates were driven up by the flat load, by infrastructure costs for grid modernization and by FITs that Australians supported. And they are moving to benefit from the modern grid and the rising DER penetration.

Australia’s restructured power system has four separate market players, Deora said. “There are generators, transmission companies, network operators, and retailers.”

ENA’s Bradley said Australia’s restructured power sector gives it “advantages in the coming transformation.” Without the “converging supply chain” of a vertically integrated market, a distribution system operator is likely to see a “vibrant range of new and existing market actors which will be innovative in their service offerings to customers,” he said.

Deora said the transmission companies and network operators have been allowed to recover their grid modernization costs and neither seems intent on getting a piece of the DER action. “Even with current flat loads,” he added, “they see their responsibility fulfilled in providing the service and getting rate recovery.”

Though this has increased rates, the aggressive deployment of energy efficiency has, until very recently, prevented noticeably higher bills. In conjunction with fewer outages and Australia’s strong economy, customers are not widely revolting or blaming DER owners.

It may be more clearly recognized by Australian customers that a range of factors impact their bills, Deora said. According to analysis from NERA Economic Consulting, South Australia solar PV owners impose a $120 yearly cost on non-solar PV customers. But that’s dwarfed by other technologies, like the $700 yearly cost-shift imposed by air conditioning owners in Victoria.

While they have pushed for FIT reductions, Australian utilities also see opportunities in the DER market. AGL Energy, Origin Energy, and EnergyAustralia, three of the country’s biggest retail electricity providers, recently announced they are moving into solar.

The market is so far dominated by local solar installers and the retailers see opportunity if they can leverage the customer data and marketing power they have in customer acquisition, Deora said.

“There is a move toward giving the REPs the opportunity to compete in new areas associated with DER,” ScottMadden’s Vlahoplus concurred. Giving them more freedom in what they can bring to market will likely allow them to be more creative, he said.

Small installers also face competition from fossil generators looking to use their deep balance sheets to diversify. Many major power providers are “thinking about how to offer solar, demand response, other DER to get more market share,” he added.

Horizon Power acts as the regional electricity provider to the population center in Perth and the rest of the West. Using distributed solar and energy storage, Horizon, a traditional vertically integrated utility, is already “pioneering innovative business models for microgrids,” ENA’s Bradley said.

Because much of Australia, especially in the west, remains rural and sparsely populated, there are an estimated 27,000 grid-connected farms that could be more efficiently served by using DER, according to ENA’s Electricity Network Transformation Roadmap.

Almost $700 million could be saved across the entire customer base by supplying these connections, usually farms, with a microgrid-like standalone power system, Bradley added.

Australia's lessons for the U.S.

Like the work being done now in the U.S., most notably in New York and California, Australia is planning on more cost-effective dispatch of DER through new tariffs and a transformed power sector led by distribution system operators, Deora said.

ENA’s detailed analysis found that moving away from volumetric rates to “demand-based rates” will be necessary to avoid bigger “cross-subsidies between customer segments,” Bradley said. They will also more adequately “reward efficient energy use” and not “distort investment decision making” as volumetric rates do, he added.

By 2026, demand-based rates can save customers over 10% per year on their bills and deliver $1.8 billion to Australia in economic benefits, according to the analysis.

Rates and incentives with price signals that drive investment in new technologies will be vital as Australia goes from today’s 15% distributed solar penetration to over 65% by mid-century, Bradley said.

“Second wave incentives” will be “voluntary, location-specific in the network, and dynamic in time,” Bradley said. Customers will be remunerated for providing DER “in the ‘right place at the right time’ – such as behind the meter storage, demand response from aggregator platforms or programs offered by networks.”

This kind of “orchestration” of DER deployment can avoid $16 billion in infrastructure investment by 2050, Bradley said. DER owners would, through new rates and incentives, earn over $1.1 billion per year for grid support services by 2027 and over $2.5 billion per year by 2050.

In the U.S., these kinds of rate reforms are being planned in New York, Rhode Island, New Hampshire, Massachusetts, Minnesota, Oregon, California, and Hawaii. As they prove workable, other states are likely to follow, Deora said.

There seems to be an emerging bias toward competitive practices and the idea that “if a product or service can be competitive, it should be,” ScottMadden’s Vlahoplus observed. “Australia shows what the power sector looks like when it is more customer-centric and when rates are driving customers to the DG and not just incentives.”

A business-oriented Trump administration could appreciate more accurate price signals that benefit customers and the electricity delivery system. But whether it does or not, Deora pointed out, the action will at the state level and somewhat independent of federal regulation.

Australia’s investment of billions in a robust grid modernization and support for network operators made its transformation possible, he added. But it is proving dispatch of DER by a distribution system operator is workable, adding credence to U.S. efforts to do the same.

For U.S. utilities to take this on, they will need to know policymakers will support recovery of their investment in the same way Australia’s transmission system and network operators could, Deora said. There are precedents in the U.S. for that.

In the landmark settlement creating a 50% renewables mandate in Oregon, it was pivotal that utilities were allowed to depreciate coal plant holdings before switching to renewables, he noted. In its settlement with Colorado’s solar advocates, it was crucial to Xcel Energy that it be allowed to invest, with recovery, in the grid modernization it will need to cost-effectively integrate DER.

Utilities who understand DER will see opportunities in smart meter deployment, in collating and using customer data in marketing, and/or in doing the detailed analysis to reveal where DER will best reduce costs on their systems, Deora said.

Pedernales Electric Cooperative in Texas, Colorado’s Fort Collins Municipal Utilities, and PSEG in New Jersey are working revenue opportunities in DER financing. Sacramento Municipal Utility District is leveraging its customer relationships as a trusted energy advisor. Georgia Power is developing an affiliate business in DER installation, Deora added. “Utility leaders should consider all these options.”