By Heather Donaldson and Jason Abiecunas
Few things represent the dynamic and decentralized nature of the power market like DER. These advanced technologies, which generate electricity at or near their point of use, illustrate a major shift in the marketplace as ratepayers scrutinize their consumption habits and accelerate the search for affordable, resilient, and sustainable power.
DERs fall across a broad spectrum, ranging from solar PV systems, fuel cells and battery storage to combined heat and power plants, microgrids, electric vehicles (EVs) and even controllable loads such as electric water heaters and heating, ventilating and air conditioning (HVAC) systems. Some DERs are designed for residential use; others are robust and advanced enough to serve commercial and industrial needs.
No matter the use, it’s no secret that DERs are gaining adoption across the country. It’s not hard to see the lure, as DER technology continues to advance and become more cost-effective, while promising to offset the need for utility-provided power. This opens up new opportunities and challenges for the sector, and raises the question: how large of a role will utilities play — or be allowed to play — in this DER revolution?
According to Black & Veatch’s 2019 Strategic Directions: Electric Report survey, built on an annual polling of the North American power industry, the majority of respondents see utility investment in DERs as a longer-term play, with 55 percent agreeing that DERs will dominate service offerings during the next 15 years. But that’s not to say that we couldn’t see DER penetration sooner, with a quarter of respondents pointing to the next five years and 45 percent looking at the 10-year window.
The DER Opportunity
Although this California situation could paint a threatening picture, some utilities are beginning to see distributed, renewable and microgrid energy resources in a new light. A 2017 Greentech Media report found that at least 32 million metered customers in the United States had access to a DER marketplace and that 56 utilities were operating or planning a marketplace. These marketplaces — once largely limited to energy efficiency efforts by residential customers — are growing in size and scale to offer advanced technologies such as microgrids with renewable generation and storage, which can be put to use by commercial and industrial customers.
Although these markets exist, utilities haven’t exactly been welcomed with open arms. Aggressive moves by utilities into the DER arena, for the near-term at least, may be muted by regulations aimed at maintaining competition. Concerned over utilities’ traditional ability to act as a monopoly, states with active DER marketplaces, such as New York and Arizona, have either instituted or are exploring new rules that would restrict DER ownership by utilities as a mechanism to nurture innovation and encourage new, non-utility players to enter the field.
Regulatory engagement around DER penetration will remain a critical issue for utilities. In fact, survey results show that the strong majority of respondents agree that utilities will need to work with both governments and customers to enable a future where they can reliably offer alternative energy solutions.
Nearly three-quarters of respondents prioritized the need to develop regulatory models that would enable investment in both alternative energy and the traditional grid, while a little more than half stressed the need to work with customers behind-the-meter; only in this way will utilities be able to progress as they work to offer alternative energy solutions to clients.
A Tipping Point
Industry observers believe many utilities will ultimately embrace serving as more than just generators or “poles and wires” companies, rather than be mandated to do so. Strong incentives are under way: Clean energy targets are happening in California, New York, Michigan and elsewhere where legislative policy tied to sustainability goals or renewable portfolio standards are moving power providers to action.
Whether by organizational choice or government mandate, it will be critical to engage in actively planning the DER future. It may be instructive to revisit the California case study, which also concluded that DER impacts must be looked at individually and in aggregate.
For example, while the impact of solar alone can increase ramping requirements (i.e., the duck curve), the DER portfolio simulated in the SMUD study actually decreased ramping and flattened the utility’s net load profile. The study also found that savings may not offset costs under today’s policies (SMUD’s lost revenue and program costs for most DER technologies would be larger than its cost savings on the bulk system) and that changes to rates and business models would need to be considered.
The SMUD study demonstrated the need for integrated DER analysis to identify potential problems, make utility planning processes more robust and improve utility-customer relations through better policies and programs. As we head toward a new decade — and the efficiency technologies it will put in the hands of power customers big, medium and small — the need for DER planning and regulatory engagement has never been stronger.
Heather Donaldson is a director for the growth and performance offerings within Black & Veatch’s management consulting business. She is a recognized thought leader serving as a member and advisor in national forums focused on enabling technical capabilities, business model and policy changes. Donaldson’s experience spans electricity industry domains, including distributed energy resource integration, grid modernization, wholesale markets, and distribution and transmission planning.
Jason Abiecunas is associate vice president, leading the distributed energy resources business line at Black & Veatch. Abiecunas leads a team that delivers sustainable, resilient and cost-effective distributed energy solutions to address a wide range of power issues and enable our clients to capture new business opportunities.
No matter the time frame, increasing DERs will result in a more decentralized grid and change the dynamic between ratepayers and providers. For utilities to effectively deploy DERs will require a heavy dose of planning and cost considerations that examine a slew of factors, from the micro — the impact on the local distribution system, its effect on the broader regulatory ecosystem, etc. — to the micro – the cost of deployment and operating and maintenance costs.
In 2017, Black & Veatch partnered with the Smart Electric Power Alliance to develop a case study detailing the Sacramento Municipal Utility District’s (SMUD’s) efforts to create an integrated DER planning process. One of the report’s key findings was that consumers were well on their way to outspending utilities in the adoption of solar, storage, EVs and other DERs, making it essential for utilities to track and integrate these DERs into their planning processes. The planning component is critical — not only to benefit their customers and the grid, but also because the broad adoption of cost-effective DERs will factor heavily into declining load growth for utilities.
As DER penetration grows, new business models will be required to help define the cost and benefits for utilities. Would such a model include ownership and maintenance of assets? Or would it open the door to new opportunities, such as a utility partnering with a third party to leverage the utility’s existing footprint while containing costs?
There are a number of examples of utilities embracing DER’s as part of their resource strategy going forward. For example, SMUD is pursuing a strategy of distributed storage to support high levels of renewable energy production by incentivizing home battery energy storage systems and deploying utility owned battery energy storage systems through its system. Another example is Portland General Electric’s (PGE) Dispatchable Standby Generation program, which consists of adding paralleling switchgear and a controls interface to customer owned back-up generators over 500 kWs. The program now includes over 115 MW of generation that PGE is able to bring on-line to support operation of the system.
Today, DERs are a bit like the Wild West, subject to a mix of local, state and federal policies and tied to vastly different regulatory models: Some regulators are mandating utility investment in DERs, while others enforce rules designed to limit their role. How do utilities move confidently into the DER future without a regulatory model reflective of new technologies and customer demand?
This question is clearly in play when it comes to the health of the utility business model. Nearly half of respondents (46 percent) say that without updated regulatory constructs, behind-the-meter energy supply options by customers or third parties will threaten the traditional utility model. Another 43 percent said the threat is real if utilities fail to implement their own solutions.