Reflecting on the presentations at the Distributed Energy Conference

From central to distributed: The inflection point still not clear

At the Distributed Energy Conference in Denver, Oct 15-17, 2018, one of the electric-power industry’s top analysts came away with the sense that the “inflection,” marking the point at which investment in distributed assets grows faster than that in centralized assets, hasn’t yet arrived. And the timing of its arrival still is not clear.

What is clear is that, like acrimonious separations with high-priced lawyers, the debate is far less about technology and engineering challenges and far more about who is going to make money and how—and how much. (Conference details can be accessed at www.distributedenergyconference.com.)

To explain this requires some recent history. In the early 1980s, after the Public Utility Regulatory Policies Act (Purpa) was passed, along with the Fuel Use Act (already in place to prevent utilities from building new gas-fired power stations), many cogeneration facilities and “Purpa plants” were built. Some were large gas-turbine-powered cogen units serving major industrial complexes; some small ones used alternative fuels like biomass, tires, and manure; some were tiny turbine and engine units (micro-cogen), and some were innovative ways to provide thermal and electric energy at industrial, commercial, and institutional facilities.

What proved difficult, though, was a scalable design and business model. In other words, there were many interesting “one-offs” but few repeatable projects. By the mid-1990s, all that changed with the convergence of (1) the lifting of regulatory restrictions on gas, (2) advanced gas-turbine technology, (3) IPP and merchant investment, and (4) growing electricity demand. Sales of gas turbines, in simple- and combined-cycle arrangements, took off, culminating in the famous installation wave of 1997-2002. Approximately two-hundred-thousand megawatts of gas-fired capacity were added to the grid during that period.

At the Distributed Energy (DE) conference, speakers presented on a variety of challenges and trends, most of which have been aired ad nausea over the last 10 or 15 years. But the range and scope of DE projects highlighted (and discussed during the breaks) were instructive.

Clearly, there’s no shortage of imagination when it comes to DE. Projects ranged from wind + solar + battery facilities; subscription 20-year wind energy purchases from a non-utility wind developer; utility-owned solar, wind, and storage; 11 MW of solar across 18 sites for a county governmental entity; a campus CHP facility recently expanded with a microgrid (and soon to add storage); a campus fuel-cell CHP unit; and others.

What was not clear was whether any of these DE schemes could be scaled and replicated in the region, state, or nationally. One presenter lauded a project with a 2.5-MW wind turbine/generator, 1.3 MW of solar PV, and a 1-MW/4-MWh storage unit, dubbed a “mid-grid solar wind hybrid.” He said there were thousands of attractive locations for this concept. However, he did not mention follow-on projects.

Perhaps it’s folly to even think in terms of the earlier advanced GT boom. After all, those were still largely centralized facilities, many with long-term power purchase agreements with a utility or electricity marketing partner. They fit into the historical capacity expansion patterns of the industry and the tendency of regulated utilities (and the banks that cater to them) to prefer a cookie-cutter, least-risk approach to investment.

When you start with each customer’s individual needs, criteria, and aspirations, however, can a cookie-cutter approach ever work? Perhaps, if the regulated distribution-oriented utility is controlling expansion. If each customer is truly in control, however, all bets on that horse are off. Consider this analogy: How a colleague has downloaded, arranged, and set the apps on his or her mobile devices are probably very different from how you’ve done it.

Several of the conference speakers insisted “the customer is in control.” Really? The industry has been hearing that for two decades. If you have a large load the utility doesn’t want to lose, it’s probably true. If you have a 12-unit rental property, a small commercial building, or a residence, perhaps not. The truth is that the utility industry and emerging DE component still considers the “customer” in the collective sense, not as an individual.

An old saying goes, “never let anyone get between you and your customer.” One speaker noted that the assumptions of the last 100 years no longer hold when it comes to the answer to the question, “Who owns my electric load?” He used the five stages of grief to explain where utilities in the aggregate are today regarding this question. On the scale of denial, anger, bargaining, depression, and acceptance, he thinks utilities are between anger and bargaining.

One of the weapons utilities used to block or stall projects in the Purpa days, and continue to use, is the interconnection (IC) request and analysis. Apparently, it is still a potent weapon. One analyst speaker noted that utilities can block projects by assuming the worst case in the IC evaluation. Even if the worst case is only two hours in the course of a year, the utility can still decline the IC request, at least for projects this speaker is involved with.

We tend to think about California when it comes to DE, mostly because it is said to be the fifth largest economy on the planet (if considered as a country). Whatever works there will, as has been shown in the past, likely be a model for the rest of the nation. But Hawaii is where the pace of the centralized-to-DE transformation is truly ground-breaking, and where the concept at scale likely will be proven first.

According to a speaker from the 50th state, one in three Hawaiian homes has rooftop solar PV. Public facilities there have to be energy net zero by 2030. The state has a mandate of 100% clean energy by 2040, despite the fact that its “grid” is actually six islanded power systems. Almost incredibly, 80% renewable by 2030 has penciled out as the “least cost” path. Keep in mind that renewables are replacing a large component of diesel-based capacity and access to natural gas isn’t a matter of collecting, pipelining, and distributing as it is on the mainland.

The one roadblock, he said, is aligning utility incentives with the DE strategy, and noted that the state is considering a new regulatory model that “breaks the links between traditional system expansion and capital investment.” “That is the key,” he said, “to making the transformation to distributed energy resource management (DERM) move faster.” Alaska is another state moving more quickly than the rest of the nation to a DE future, for many of the same reasons, based on other presentations at the conference.

For the other states benefitting from a more interconnected grid and lower-cost primary energy resources, the degree to which the utility is embracing or resisting DE will be key to the rate of transformation, and what is left of the customer base once they enter the “acceptance” phase.

It seems most of what is being debated at these conferences is not whether the technology is ready, whether the grid can “handle” massive DERM, or what customers really want, but rather who is going to “control the ball” and make the most money scaling and customizing DE resources to respond to real customer needs and desires.

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