It’s truly a case of the last being first.

Hawaii is the youngest state in the nation — added nearly 60 years ago in 1959. But that latest addition to the U.S. is also the first state to do something nearly as significant as stitching another star on the American flag — committing to end the use of fossil fuels for electricity generation.

The state wrote its place in the history books last year when Gov. David Ige (D) signed into law a 100% renewable energy mandate that the state must meet by 2045.

The ambitious move makes sense for Hawaii — the state is historically reliant on petroleum for fuel generation, and has long suffered from the highest electricity prices in the nation. It was already dealing with nation-leading penetrations of rooftop solar — above 30% of single family homes have it, according to a Hawaiian Electric official — and residents are clamoring for more renewable energy, stretching solar interconnection queues into the thousands.

But no sooner did the ink dry on the new 100% renewable portfolio standard (RPS) than energy stakeholders began to contemplate how they would achieve this first-of-its-kind goal. No electricity system of significant size has ever operated without at least some fossil fuel generation, and Hawaii’s lack of connection to any mainland grid means there are no out-of-state generators to turn to for reliability assurance. No man may be an island, but Hawaii surely is.

That conundrum — how to get to 100% renewables — was the main focus of the Maui Energy Conference, held on the island last week. While there were a few notable absences among Hawaii's stakeholders, the utility officials, legislators, regulators and clean energy activists in the audience were unanimous in their support for the 100% RPS. Conversations on the best way to get there, however, revealed some deep divides in the state's energy community — divides that will surely need to be bridged if Hawaii is to achieve its ambitious goal.

The road to 100%

To understand the push toward the 100% RPS, you have to go back to the oil shocks of the 1970s, Mark Glick, head of the Hawaii Energy Office, told the audience at the event.

“In 1974 and 1975, with the massive energy shocks, state energy offices were established across the United States and they began looking at a variety of solutions,” he said, “mostly a number of indigenous solutions in Hawaii — geothermal, wind, solar.”

Each year, the Hawaii State Energy Office would produce a report that looked “very much like the portfolio we have today,” Glick said, with about a quarter renewable energy generation and the rest made up of a mix of geothermal, biomass and a lot of oil. But while the reports kept coming, “nothing much happened until 2001 when we passed our first renewable portfolio standard.”

That voluntary goal was made binding in 2004, “and that really made a difference,” Glick said, pointing utility leaders and developers in the right direction. But “the real change didn’t happen until there was a stakeholder group aligned with leadership at the gubernatorial level … about codifying a stronger set of renewable portfolio standards and the 40% goal in 2009.”

That group, the Hawaii Clean Energy Initiative, included leaders from the utility, legislature, governor’s office and various civil society groups. A year after its formation in 2008, the group issued a call for a 40% renewable portfolio standard by 2030, along with a host of other energy initiatives. That laid the groundwork for the legislative initiatives that would boost the renewable energy mandate to 100%, Glick said.

“With an appropriate mix of carrots — incentives, tax credits, and regulatory pushes — we really began our transformation, and it's one that was really grounded in the notion of indigenous resources that were cost-effective,” he said.

Shifting renewables, shifting demand

Currently, the Hawaiian islands are ahead of their renewable energy goals, Glick told the conference. About 23% of electricity generation last year came from renewable resources, with more than a quarter of that coming from distributed solar.

Even if the distributed resources were taken out of the equation, the state would still be ahead of its 15% RPS goal set for 2015, showing that the clean energy mix “really came from a diversified portfolio of utility sources plus distributed energy,” he said.

But getting to higher penetrations of renewable energy — 50% and beyond — will be a challenge, stakeholders said during a panel discussion moderated by Utility Dive. Key to the removal of fossil fuels on the grid, all agreed, will be addressing the discrepancy between when renewable energy is generated and when customers consume the most power.

Currently, the Hawaiian islands receive most of their renewable energy generation during the day, when the sun is shining and the winds are blowing, allowing power providers to back off fossil fuel generation. But in the evening, when solar and wind generation tend to decline yet also when Hawaii residents consume the most energy, the utilities are forced to fire up conventional generation sources quickly. The result is a load curve that looks even more exaggerated than the “Duck Curve” that's well-known to California utilities.

Addressing this problem can mean one of two approaches: Shifting renewable energy to fit customer demand, or reshaping customer demand to better align with renewable energy generation. The state's biggest utility, Hawaiian Electric Co., is trying to do both, according to Colton Ching, vice president of energy delivery.

“The wonderful thing about distributed energy resources is that they give you opportunities in both the shifting energy produced by a distributed resource and storing it, for example, for the daytime to consume it in the evening or other peak times,” he said. “But at the same time, it enables demand response programs that allow the consumer to shift their usage as well.”

To realize the dual potential of DERs to address generation and demand challenges, Hawaiian Electric realized it needed a better understanding of which resources were connected to its distribution grid. While the utility currently has automation and control down to a certain level, it still lacks the ability to holistically view and control the more than 75,000 rooftop solar systems and other DERs on its grid.

A recent grant from the Department of Energy to explore a System to Edge-of-Network Architecture and Management System (SEAMS) aims to fix that. While the existing system sees behind-the-meter resources simply as load reduction, the SEAMS system will combine short-term forecasting and weather predictions to provide grid-responsive controls to link DERs with the larger utility system.

“One of our key focuses of the efforts here is to increase the visibility of distributed energy resources ... to understand what are the right attributes of the communication system to allow for that level of visibility and that level of control for the future,” Ching said.

Going forward, the ability to shift energy production and reshape customer demand “requires the ability to make those shifts through equipment and appliances that exist behind the customer's meters,” he said.

“It may be in the form of equipment that drives behavior for the customer, provides info for the customer to make more informed decisions, or even to guide non-electrical things, whether it's a resistance water heater ... or whether it's the old technology ice storage that could be in use one day on the residential level to do that shifting.”

“If we’re going to do a lot of it,” he said, “and we’re going to count on distributed resources to be a big component of the solution, then we need that visibility.”

Rate design and price signals

Beyond greater knowledge and control of the grid, price signals provided by the utility's rate structure will be critical in helping reshape customer demand and reduce overall usage, according to Commissioner Mike Champley, a sitting member of the Hawaii Public Utilities Commission.

“The key is price signals and my firm belief is if we get the price signals right, you can clearly see the problem,” he said. “We've heard from a lot of [stakeholders] over the past day or two: ‘Get the price signals right, identify the problem and then get out of the way and let the creative solutions come forward.’”

The idea is to reform utility rate structures so that consumers of all sizes are incentivized to consume less energy during peak hours and shift some of their consumption to periods when renewable generation is more abundant. One common example of this method is instituting time-of-use (TOU) rates, which charge different electricity prices depending on the time of day, or demand charges, which add a fee for customers based on their peak monthly usage.

After approving an aggressive TOU rate pilot program for the Kauai Island Utility Cooperative and writing TOU rates into the state’s new distributed solar incentive policy last year, Champley said the commission will continue to address rate structure issues this year.

One of the key focuses on that will go toward "unbundling and trying to figure out what are the costs and appropriate prices for grid services that are needed," he said.

While he could not get into specifics, the commissioner said the key questions facing regulators will be: “What are the technical attributes that need to be required so that whatever service is provided truly provides grid support, and secondly what is the appropriate pricing?”

HECO's Ching endorsed the move toward more responsive rate designs, but cautioned the audience that any decisions made should be customer-friendly.

“Not only do we need to give them the right pricing, but we have to make it easy for them,” he said. “We have to make it work, not just for the individual customer, but for the system.”

On that point, Champley disagreed. While individual consumers may not be able to digest more complex rate designs, that will be the job of DER providers themselves.

“I dont think it has to be customer-friendly,” he said. “What this is, is really the proper role for the new DER providers. They have the technical resources to understand this, but if they want to be successful, they have to market to customers. So I expect that we probably aren't going to see anything that's technically complicated, and we're going to rely on other people to filter out and make the customer value proposition in a very simplistic way: I'll send you X per month or I'll do this.”

Valuing distributed resources  

As state leaders move to unbundle utility rates and better compensate DERs and their owners for grid services, a sticky issue comes to the forefront once again: How to properly value distributed resources, especially rooftop solar.

While this is a mostly theoretical exercise in other parts of the nation, the question of what distributed resources are worth is a critical one for Hawaii, where some HECO distribution circuits already have more distributed solar capacity than the average daily load. Until last autumn, distributed solar owners earned bill credits at the retail electricity rate for the power their systems sent back onto the grid — a lucrative proposition for the solar sector, but one that the utility said cut into its bottom line and shifted millions of dollars of grid upkeep costs onto non-solar customers.

In response to these concerns, the Hawaii PUC ended the retail rate net metering program in October 2015, replacing it with new “self-supply” and “grid-supply” options that aim to more accurately compensate solar owners for their systems’ value. While the new incentive structures get closer to that mystical true value of solar, Ching told the audience there’s still much work to be done.

“I think [the regulators] were pretty deliberate in establishing this for a very specific point of time,” he said. “This was not an order with set rates that will be in place forever.”

The thinking is that the values and roles of the components of the electrical system, including DERs, will change over time, Ching said.

“The requirements of the system, the requirements of every component that's operating within it, including DERs, will also change,” he said. “Whether it's the operating capabilities, the functionalities, the services they provide, their value and costs will change over time as well.”

Moving forward, conversations around DER valuation will have to take into account the “range of services a distributed energy resource can provide,” according to the HECO executive, as well as its place on the grid at a given time. That will be a huge challenge, panelists agreed, since technologies and regulatory approaches to DER valuation are still at a nascent stage.

In other words, no one has been able to devise a complete solution to the problem yet. But that doesn't bother Ching.

“I'm an optimist, so I think we can get there. But I don't think that the way we get there is to get it perfectly right and have it figured out in absolute detail,” he said. “I think this is something we can do as a work in progress along the way. We can make good decisions to make meaningful, incremental changes to get there.”

While he could not address the specifics of Hawaii’s regulatory dockets, Commissioner Champley also endorsed an incremental approach.

“Let's not talk about rearranging deck chairs — in other words, reconfiguring NEM — let's talk about developing sustainable, market-based DER commitments,” he said. “I think that's what the commission did in its order [to end retail rate NEM] ... As Colton pointed out, it's a transition — it's not forever.”

While the process may be lengthy, it is crucial for the state to continue working to value DERs, Champley said.

“We're going to slowly migrate, but more importantly, whatever we do, we have to have grid value being provided,” he said. “I think it's really important that customers continue to have choice, we just have to have choice in a way that the non-participating customers are not adversely affected.”

Natural gas: a bridge to 100% renewables?

As Hawaii pushes to increase renewables on its grid, it faces a critical decision regarding the fossil fuels on its grid — should it bring in liquified natural gas (LNG) to replace at least some of the state’s fuel oil and diesel generation as it moves to 100% renewables?

For the utility community, the answer is undoubtedly yes. Both Hawaiian Electric and Hawaii Gas have plans to integrate LNG into their fuel mixes, but they have been met with political opposition. Last August, Gov. Ige announced his opposition to the importation of LNG for electricity generation, saying any buildout of infrastructure to serve the resource would be a “distraction” from the work needed to get the islands to 100% renewable energy.

“Currently, that's the state policy, that focusing on LNG in the electricity power sector is a distraction and is something that's not supported,” Glick said. “The governor has often said that he is open to seeing new data, but what Gov. Ige has said is that massive infrastructure investments that are long-term … that’s a distraction."

Ching said the governor’s concerns are misplaced and that the utility could integrate natural gas into its fuel mix with only small infrastructure investments.

“We believe that if done right, under a certain set of circumstances, we can bring LNG at a cost cheaper than where we see oil being ... and during that process the qualities of natural gas modern generating technologies ... actually help us operate the system with lots of variable generation whether it's wind or solar.”

“All of that can be done in a period of time where the infrastructure design — the concern that I understand the governor has — it can be done in a way that the infrastructure is really minimized,” Ching said.

Utility ownership and business models

Beyond resource-specific questions around natural gas and distributed solar, the state also faces more fundamental issues on who will own the state’s dominant electricity provider, and what its business model should be.

While Florida-based power company NextEra Energy has been pursuing the acquisition of Hawaiian Electric for more than a year, representatives from the company were conspicuously absent from the Maui Energy Conference — an event that just last year made the proposed merger its main focus.

The pending deal, which is still before Hawaii regulators, was barely mentioned throughout the two days of conference proceedings, and many sector analysts expect the acquisition to fall through this spring. Instead, conversations about the utility business model centered on whether Hawaiian Electric’s current vertically-integrated structure is the best model to help it achieve 100% renewables.

While the Hawaii utility still earns money through traditional cost-of-service ratemaking, regulators in other states are pushing changes to how their utilities make money, encouraging more market-based earnings and performance-based metrics. The New York REV initiative is undoubtedly the most recognizable proceeding, and it aims to convert utilities into Distribution System Platform Providers — effectively, "air traffic controllers" of the grid that exist to maintain reliability and integrate various DERs.

Asked whether a similar utility business model reform docket would fit in Hawaii, Ching said that moving to some form of performance-based regulation makes sense. But when it comes to the kind of bottom-up overhaul of the utility business model as imagined in New York, the Hawaii train may already have left the station.

“I think a big part of the ideas that led to the NY REV model is one of, how do we operate a system with many distributed resources in a fair and equitable fashion?” Ching said. “The one thing that makes me struggle with this comparison is that in New York they've spent two years trying to figure out the hypothetical of how it should be in New York in the future. The challenge we have in Hawaii is that it's already happening.”

“I think the question to ask for Hawaii is how do we create the right operations on the distribution system for how it's gone in a fair and equitable fashion to all folks ... and to do that in a way where we already have a lot of resources on the system,” he said. “I think it calls for something a little different than what's happening in NY, and if that's not a hard enough thing to do, I think you need to do it sooner rather than later because the situation can change.”

The New York model is an interesting one, Commissioner Champley said, but the California model of more incremental reforms in an environment of high renewables and DER penetration is likely a better example for Hawaii.

“I would think New York is not where we would take our cues from,” he said. “It would be California or the Southwest.”

A wholesale overhaul of the utility business model may work when high levels of DER penetration are still just a possibility, but once they are a reality, there are bigger fish to fry.

“To me, we have limited resources, whether it's the commission, the consumer advocate, the energy office, even the Hawaii Electric staff, so what are the most important challenges and issues we have here?” Champley asked. “I would say, the biggest issue we have here is how do we find and get to a sustainable market and DER market structure? How do we get a sense of what the broad roadmap is? How do we deal with the whole issue of grid modernization and renewables integration in a way that doesn't break the bank? Seems to me those are the bigger issues.”

“It's not where the real value is immediately,” he concluded. “We have queues of projects [under review at the commission]. We need to address the more immediate situations and then we can get to where we need to go.”

From the perspective of the State Energy Office, Glick said that the governor and his staff are comfortable with the current business model of Hawaii Electric, so long as it can meet its regulatory requirements and the 100% RPS.

“If both the commission and the utility are able to essentially identify the smarter investments that are much more short term in nature we may be able to skip the notion of a wholesale or fundamental change in utility business models or structure,” he said.

But that vote of confidence in the investor-owned utility also came with a warning. On April 1, Hawaiian Electric is due to file the latest version of its Power Supply Improvement Plan (PSIP), a plan of how the utility will meet its obligations, including the 100% RPS, in the coming years. Last year, regulators threw out an earlier version of the PSIP, citing “numerous, repeated failures to properly plan for an affordable, high-renewable future.”

If the next PSIP can address the regulators’ concerns, Glick said, the Hawaiian Electric business model will look a whole lot more sustainable going forward. If not, the Governor’s Office may consider pushing for alternatives.

“If they can lay out a series of things through the guidance of a clearer and more responsive Power Supply Improvement Plan, then I think we might get a better indication of whether this is a sustainable [business] plan that is going to be good for ratepayers in the long term and one that makes the utility money, or look to something else,” Glick said. “We only would look to something else if that plan can't present the confidence in the future that that could be done."