Fully embraced by the Hawaiian Electric Companies and Green Mountain Power

Across the country, many utilities are in the midst of transitioning to the utility business model of the future. That emerging business model embraces the transition away from firm, fuel-fired central station generation—sited, owned, and operated by the few—to renewable distributed energy resources (DERs)—sited, owned, and operated by the many. 

Regulatory policy in several states (California and New York immediately come to mind) governs the transitioning of a number of these utilities. On the other hand, several utilities are taking the bull by the horns (an apt metaphor given the enormity and ornery nature of this transformation) to systematically transition to the utility of the future on their own terms.

I use the term “future” loosely because, for a number of utilities, the future is already here. Two such utilities bookend the country: the Hawaiian Electric Companies—the largest investor-owned utility (IOU) in Hawai‘i—and Green Mountain Power—the largest IOU in Vermont. 

Over the past several years, I have been fortunate to work with both utilities, witnessing first-hand their struggles and successes in their transition to the utility of the future. In addition, I have held an integral role in their most recent integrated resource plans (IRPs), which outline their plans for opening their doors fully to DER penetration on their power grids to pursue their goal of 100 percent renewable generation.

The Hawaiian Electric Companies.Hawai‘i was the first state to mandate a 100 percent Renewable Portfolio Standard (RPS). In their December 2016 integrated resource plan (entitled a Power Supply Improvement Plan by commission edict), the Hawaiian Electric Companies outlined their plan for achieving their 100 percent RPS goal five years ahead of the 2045 deadline.

As stated in their resource plan’s Executive Summary: “Under multiple longer-term scenarios, our RPS can be at least 72 percent by 2030 and reach at least 100 percent by 2040, ahead of the 2045 deadline. In the aggregate, our action plans estimate achieving a 52 percent RPS by 2021 by adding 326 megawatts (MW) of rooftop solar, 31 MW of Feed-In Tariff (FIT) solar generation, 115 MW of demand response (DR), 360 MW of grid-scale solar, and 157 MW of grid-scale wind resources across all five islands we serve.” The 326 MW DER represents the maximum projected amount by 2021.

Their plan also includes enabling the island of Moloka‘i to be 100 percent renewable by 2020, maximizing demand response, modernizing their grid, and preserving flexibility to accommodate  emerging technologies (such as hydrokinetic energy), innovation, and changing circumstances. In other words, embracing the foundational principles incumbent to the utility of the future.

Green Mountain Power.The story of their 2018 IRP (filed in December 2018) is one of  the innovation and change that is a hallmark of the utility of the future:

Change from the old energy system of centralized, fossil fuel-based generation transmitted through traditional poles and wires to customers far away, toward lower carbon, renewable, distributed generation with new, complex local and regional grid management opportunities.

Change from one-way electricity flowing from a central plant to a customer toward two-way energy information, storage, and delivery between customers and to the benefit of everyone.

Change from steady and increasing loads toward flat and declining loads, as customers choose self-generation plus energy storage and utilize beneficial energy efficiency programs.

Change from separate fuels for and treatment of thermal, lighting, and transportation energy toward convergence through the strategic electrification of resources.

It wasn’t until 2015 that Vermont passed their Renewable Energy Standard (RES) that mandated renewable energy goals. Divided into three Tiers, RES requires a total of 75 percent of retail sales by 2032 to be derived from a combination of grid-scale renewable resources and DERs. The state’s 2016 Comprehensive Energy Plancalled for attaining 90 percent of its energy from renewable resources by 2050.

Fortunately, Green Mountain Power had already embraced the utility of the future business model and was well on its way toward meeting these mandated goals. The utility also enables customers to connect storage systems to the power grid, either through their program that offered 2,000 Tesla PowerWall 2.0 batteries at a reduced price as well as any other privately-purchased BESS. Both are first-of-their-kind programs. It’s no surprise that the utility is guided by the “customer as North Star” principle.

Both utilities have thrived within the utility of the future business model. Other utilities can benefit from their lead. 

—Rich Maggiani

The utility had a clear problem: how to develop their current integrated resource plan (IRP). The size and scope of the problem seemed to expand daily.
The state’s public service commission had issued an order prescribing in detail the methodology and requirements necessary to be addressed in their IRP. The utility was used to creating their own IRP, with their own methodology, employing a tried-and-true process for attaining the goal of everyone’s IRP: reliable power at the lowest cost.

But this current commission order turned all of that on its head. 

Crossroad. What was being ordered looked more like an IRP that simply ticked off the commission’s boxes, and less like a strategic plan for delivering low-cost, reliable power. In fact, that traditional goal seemed to be secondary to the commission’s goal. Being one of the state’s largest and most visible utilities, its core executives realized that everyone was watching—and closely assessing—how they executed the commission’s directives. Thus, the executives were at a crossroad. They had to decide to develop their IRP by: 

Scrupulously following commission guidelines (which on closer inspection, clearly had process-oriented holes) to satisfy regulatory requirements and other statutory goals.

Diligently relying on their tried-and-true methodology to satisfy their clear mission-oriented need to best serve their wide array of customer needs.

Far-reaching implications. They realized that their decision would have far reaching ramifications, some of which were most likely unknown, but certainly would be unearthed.

These utility executives were not delusional by any stretch. They were fully aware of the transformation that had been occurring in the electric power industry over the past several years. They fully understood that the familiar ground upon which the industry was based for the past one hundred or so years was completely in flux. They clearly understood how the inexorable influx of renewable generation, especially from distributed energy resources (DERs), coupled with drivers to reduce carbon emissions from greenhouse gases (GHGs), fundamentally changed their landscape. 

And they embraced the fact that the planning process for developing their IRP had expanded in scope, incorporating both traditional and emerging factors: increasing numbers of inputs and assumptions; forecasting volatility; wider array of generation options; distribution planning; grid modernization; renewable generation targets (mostly through renewable portfolio standards—RPS—legislation); judicious thermal generation retirements; myriad financial considerations (capital expenditures, operation and maintenance expenses, and rate design being key); transportation electrification; emerging technologies; energy storage systems, both large-scale and distributed; and customer empowerment. 

Even with all these additional consideration, the executives felt certain that their planning methodology could incorporate these factors and create a preferred portfolio of generation and distribution that satisfied their overarching need for reliable power at a low cost while still maintaining a level of adaptability to adjust to future known and unknown circumstances. 

Ultimately, their collective eyes were open.

To come to grips with their basic IRP problem, they assembled a planning committee that included representatives and executives from resource planning, transmission and distribution, finance, operations, legal, regulatory, and corporate communication. 

Paths for an IRP. The planning committee quickly honed in on their purpose: to choose a path that best served their customers. They assimilated all the information they had, considered what other utilities were planning and had actually done, considered their past experiences, considered their apparent place in the state’s utility mix, and projected the implications of their decision, then pinpointed three potential paths:

Adhere to the commission’s prescriptive path to the letter, essentially abdicating their contributions to developing an IRP.

Expand on their tried-and-true process to incorporate evolving changes in the energy landscape (including meeting statutory and regulatory requirements) and thus establish an updated process for developing an IRP.

Duplicate their work by developing two IRPs simultaneously: one that employed the commission’s prescriptive path; and one that traversed their own need for a strategic plan. Left unsolved for the moment, was the decision on which of these two IRPs to file.

Deciding on which path to choose is a question that many utilities are being forced to answer—an answer that has far-reaching and pivotal implications for everyone involved.

—Rich Maggiani, Resource Planning Consultant

While a number of reports and studies evaluate and record this transformation, these managers and professionals live it—every day. They experience exactly how that transformation affects their daily work lives, and how integrated resource planning has become more complex, wider reaching, and increasingly difficult. We know. We interviewed over three dozen resource planning managers, resource planning analysts, utility executives, and industry consultants from across the country to understand and report on their daily struggles. From those interviews, we wrote The Integrated Resource Planning Transformation study and report.

Through those interviews, we discovered that many disruptive catalysts converged to stimulate and energize this integrated resource planning transformation. The most prominent catalyst: the increasing influx of distributed energy resources (DERs) at the grid edge, especially from rooftop solar installations combined with their decreasing costs and statutory incentives. DERs, however, are far from the only disruption. A confluence of other catalysts undermines the integrated resource planning process:

• Large-scale variable renewable installations, mainly from solar and wind
• A bi-directional grid with distributed assets on the grid edge
• Regulatory and legislative mandates
• Customer interest and participation
• Governmental programs that create incentives for select energy technologies
• Natural gas price declines
• Affordable and productive battery energy storage systems
• Electrified transportation
• Demand-side management programs
• Adamant intervenor participation
• Decreasing demand and slowing economic growth

Interviewees told us that these catalysts continue to impact and complicate the integrated resource planning process, creating a number of planning challenges and difficulties: accurate modeling for solar and wind; larger numbers of modeling input assumptions with shorter shelf lives; long-term load and demand forecasting; load-eroding drivers such as energy efficiency, demand response, and customer choice; capacity combined with generation forecasting; expanding reserve margins; as well as many others.

Integrated resource plans (IRPs) must also include distribution planning that considers capacity as well as generation resources on a two-directional grid. Integrated resource planning now includes a wider array of utility departments and staff whose past roles previously were peripheral. In addition, stakeholder communication has become increasingly challenging because intervenors are adamant about pursuing their individual agendas and homeowners are empowered to generate power and manage their energy consumption.

These challenges result in the need for better forecasting and more robust modeling tools that accurately plan for integrating increasing DER penetration, as well as the need for an Advanced Distribution Management System (ADMS) and a Distributed Energy Resource Management System (DERMS) to better manage that integration.

All combine to create volatile IRPs with shorter planning horizons that can be confidently relied upon.

Many utilities are already immersed in creating IRPs that consider distributed energy resources; many others will soon face the challenge of responding to the distributed energy future. The purpose of our report, The Integrated Resource Planning Transformation, is to help you with your transition.

One outcome from this transformation is strikingly clear: utilities alone no longer determine the grid’s destiny.

Download The Integrated Resource Planning Transformation report. We trust that you will benefit from reading our report.

—Rich Maggiani, Resource Planning Consultant

Events in Nevada over the past three years shone a bright light on how net energy metering (NEM) has affected the evolution of distributed energy resources (DERs). Or would it be more accurate to call it the DER revolution?

Nevada: an insightful perspective. In December 2015, the Public Utilities Commission of Nevada (PUCN) cut NEM compensation by about one-third and instituted a monthly fixed charge. This new policy applied to both new and existing NEM installations, virtually all of which were rooftop solar photovoltaic (PV) panels.

This decision significantly decreased NEM compensation while it also extended the payback period for a rooftop system. The consequences were quick and monumental. Immediately, the top three solar installers in the state announced their intention of moving to more “business friendly” states. It came as no surprise when rooftop solar installations dropped 92% in first quarter 2016. Nevada, once a darling in the solar sector, became a virtual wasteland.

Until the PUCN reversed itself.

Late in 2016, the Nevada governor appointed two new commissioners to the three-person PUCN. That new commission reinstated the original NEM rules. Then last year, the Nevada Legislature passed bill AB 405 that reinstated NEM compensation for residential solar projects at 95% of the retail electricity rate. The bill also contains numerous other consumer protections, ensuring the bill’s reach for at least 20 years. At its essence, though, AB 405 guarantees consumers the right to self-generate electricity. The bill’s passage not only resuscitated the state’s moribund solar industry, but also created a boon for potential energy storage system (ESS) installations.

So, let’s summarize. NEM active; rooftop solar DERs soar. NEM revoked; DERs grounded. NEM reinstated; DERs take off again. And this doesn’t even account for the state and Federal tax credit incentives. As a policy tool, NEM has wielded enormous power since its first passage in 1983. As a result, DERs are experiencing an annual, unabated 20% growth rate.

What hath NEM wrought? Over the past 35 years, NEM and the influx of DERs have caused a tremendous upheaval in the energy industry. Here are just a few.

Integrated Resource Planning. It used to be that resource planning focused on central station firm generation sited to facilitate a one-way transmission and distribution system. High capacity factors better ensured reliable energy delivery. Contemporary resource planning, however, is undergoing a wholesale transformation influenced by a number of aspects:

• Integration of variable, large-scale and distributed renewable generation with its decreased reliability, lower capacity factors, and uncontrollable “fuel”.
• Inadequate modeling tools.
• Expensive battery energy storage.
• Grid modernization considerations.
• Two-way transmission and distribution (T&D) systems.
• Load-eroding drivers.
• Legislative and regulatory mandates.
• Communication and transparency challenges.

Cost and benefits of rooftop solar. This is a controversial topic, to say the least. Utilities assert that NEM customers use the T&D network and require energy when their panels aren’t generating power, yet are not paying for it, all while receiving retail rates for their power. This unfairly shifts costs to non-NEM customers. Solar advocates contend that a number of factors (utility incentives, RPS policies, reduced T&D costs, fossil fuel price hedge) actually make this cost-shifting argument moot. Indeed, a 2014 report conducted by PUCN concluded that NEM actually benefited non-NEM customers. It’s no surprise that actual costs and benefits vary widely, and depend on numerous factors.

Utility of the Future. The proliferation of DERs has challenged the basic utility business model. Must the utility business model of the future align with public policy goals and customer electricity needs?

At its core, the challenge focuses around the potential for unbundling the energy services that utilities provide. More and more, some of these services are being provided at the “grid edge” where customers manage and use energy—such as self-generation. As energy storage prices fall while their capabilities rise, DERs will continue to grow as will the prospect for grid defection.

A transition to the utility of the future model is already underway. For example, the two largest utilities in New York, Con Edison and PSEG (both essentially “wires” companies), instituted a Utility of the Future department three years ago. Why? Put simply, to better align with the state’s Reforming the Energy Vision (REV) goals of a 40% reduction in greenhouse gas emissions, half the state’s generation from renewable resources, and a 23% reduction in energy consumption—all by 2030.

One thing appears certain: DERs are here to stay. How the utility of the future evolves remains to be seen.

—Rich Maggiani

The Hawaiian Electric Companies have a plan. Their resource plan, filed in December 2016, outlines the near-term actions for attaining 100 percent renewable generation in their service area by the state’s mandated goal of 2045; the most ambitious—and only—such plan in the country.

In July 2017, the Hawai‘i Public Utilities Commission (HPUC) formally accepted this December-filed resource plan—their Power Supply Improvement Plan (PSIP), which was updated from a previous PSIP filed in April 2016.

Broad, inclusive participation. Both PSIPs were created in an open, collaborative process that included multiple participants and intervenors admitted into the docket. These participants were directed to “propose questions and suggest alternative modeling inputs, assumptions, methods, and analytical approaches” that Company planners must consider to incorporate into the resource planning process.

Selecting generation resources. Company planners ran production simulations using optimized candidate resource plans that incorporated distributed energy resources (DER), demand response programs, and other resources; then analyzed system security requirements to ensure system reliability. From the final results, they developed near-term (2017–2021) action plans that encompass renewable acquisitions, grid modernization, DER policies, environmental compliance, and system security improvements.

In the aggregate, these action plans add enough rooftop and feed-in tariff solar generation combined with large-scale solar and wind to attain a 52% RPS by 2021.

Communication challenge. In Hawai‘i, actions taken by the Hawaiian Electric Companies are fodder for front page news. The December PSIP results, garnered through this collaborative process, were eagerly awaited not only by participants, but also by the media and general public. Having worked on both PSIPs filed in 2016 (as well as two previous Hawaiian Electric resource plans), I was keenly aware that the written report had to be easy to read by a wide audience.

For the December PSIP’s Executive Summary, I worked closely with Corporate Communication to design the flow of information and the messages needed to clearly communicate the enormity of the plan’s results—the first resource plan in the nation to achieve 100% renewable generation. To highlight the thoughtful planning effort, a sidebar explained seven foundational Renewable Energy Planning Principles:

1. Renewable energy is the first option.
2. The energy transformation must include everyone.
3. Today’s decisions must not crowd out tomorrow’s breakthroughs.
4. The power grid needs modernization.
5. The lights have to stay on.
6. Our plans must address climate change.
7. There’s no perfect choice.

The power grid needs modernization. About six months after completing the December PSIP, the Companies filed their proposal for modernizing their grid. The proposal described in detail a strategy for utilizing advanced technologies to develop its grid as a platform that enables increasing amounts of renewable generation, improves reliability and resiliency, and creates more customer choice. This modernization transforms the grid into a two-way power flow that opens the way for tripling the number of rooftop solar installations (including those with complementary energy storage systems) over the nearly 80,000 such systems already installed.

Integrated grid planning process. Modernizing the grid requires an ongoing integrated grid planning process conducted every two years, each with a five to ten year horizon. They call this planning process C³GP, for Comprehensive, Customer-focused, and Cooperative Grid Planning. Integral to this process is resource planning, transmission planning, and long-term distribution planning, especially to incorporate DER and customer-related services.

The proposed grid planning process incorporates customer input, updated assumptions, and latest advancements in technology, thus broadening grid planning as an integrated energy network Customer input is important given the significant increase in networked customer resources and flexibility in how they manage their energy use, especially through a wider array of demand response programs. This unprecedented integrated grid planning process pushes Hawai‘i even further ahead as the industry leader for attaining a modernized, renewable energy grid.

The need for greater communication. More renewable generation on the grid parallels the growth of privately-owned rooftop solar and energy storage systems, which results in customers becoming more actively engaged in the generation and management of energy. Coupled with that growing interest is the need for clear communication to better enable a successful grid transformation.

—Rich Maggiani

Creating an Integrated Resource Plan is a formidable challenge. I know; I’ve helped create and write several IRPs during the past decade that each followed a process developed 25 years ago. This is why the process currently being proposed by the California Public Utilities Commission (CPUC) staggers me.

Typically, IRPs created by a utility or a load serving entity (LSE) focus on providing reliable, affordable power for their service area and customers. While these IRPs comprise a wide range of generation, costs, transmission and distribution, and service, they are isolated plans.

The CPUC proposes to elevate all that. Its proposal involves an iterative process to compile individual IRPs into one statewide resource plan—in other words, a resource plan using the state as its service area. This process seeks to balance the individual loads, generation resources, planning perspectives, power grids, and other aspects of each LSE—large and small, public and private—into one cohesive direction that focuses energy generation in the state.

Senate Bill 350, which initiated the CPUC proposal, requires an IRP development process that meets California’s greenhouse gas (GHG) emission reduction targets. The upshot, however, requires a modernized grid to transmit increasing amounts of renewable energy. Among many other goals, SB 350 calls for 50% renewable generation by 2030, essentially doubling current output. The pending SB 100 ups the ante by requiring 60% renewable generation by 2030 and a non-mandatory 100% by 2045.

This proposed energy resource planning initiative requires coordination among the CPUC and multiple state agencies: California Energy Commission (CEC), California Air Resources Board (CARB), and California Independent System Operators (CAISO). The proposal, which has garnered the input from LSEs and other stakeholders, still requires approval by the five state Commissioners.

The initiative is nothing if not daunting. It assimilates each LSE’s IRP process into a hierarchical five-step iterative process (shown here, taken from the CPUC proposal document).

Five iterative steps essentially involve two IRP cycles. For the process to be effective, all LSEs must develop their individual IRPs from similar positions. Starting with SB 350’s GHG goals (1), the CPUC defines foundational inputs and assumptions, a Reference System Portfolio (generation resources that meet policy goals), and filing requirements for each LSE (2).

LSEs create individual IRPs with one or more portfolios, at least one of which must be created from Reference System Portfolio elements. The IRPs must maintain reliability, minimize costs (and thus bills), and comply with GHG goals, with priority given to disadvantaged communities. The filed IRPs conclude with one preferred portfolio, a short-term action plan, and any procurement requests (3).

After all IRPs are filed, the CPUC first reviews them individually to ensure compliance with policy goals and the process, then as an aggregate to create one statewide portfolio that meets policy and reliability goals. If all goes well, the CPUC approves and certifies the individual IRPs, then creates a preferred system-wide portfolio (replacing the Reference System Portfolio) and a set of short-term actions for implementing the preferred portfolio (4). Finally, the CPUC takes the steps necessary to procure new resources, fund programs, change tariffs, and initiate anything else needed to implement the preferred portfolio (5). This two-year process then begins anew.

A 20,000 foot perspective of the process and its communication. Let’s try to get our arms around this. The proposed process involves several state agencies and numerous LSEs: a half dozen investor-owned utilities (IOUs), dozens of publicly-owned utilities (POUs), about two dozen electric service providers, and a handful of rural electric cooperatives and community choice aggregators. The largest LSEs will file a “Standard LSE Plan” (these plans are to be assimilated in step 4 and represent about 75% of statewide load); sixteen POUs will file an IRP as outlined by the CEC; and the remaining will file an “Alternative LSE Plan”.

If approved, this process will be carried out for the first time over the next two years—in a state whose economy is larger than all but five countries.

How well these numerous IRPs are created and written will have a profound effect on the effectiveness and efficiency of steps 4 and 5. In addition, the clarity of the IRPs and of the overall process in general, both in its written and spoken communication, will directly affect how the myriad stakeholders, media, and customers perceive the process.

Renewable generation is visible. As renewables increase on the power grid, so too will public participation and the need for clear communication—a critical aspect of the initiative’s success.

—Rich Maggiani

Regulatory officials in California are raising the bar on integrated resource planning, taking it to a more efficient and effective level.

The California Public Utilities Commission (CPUC), together with the California Energy Commission (CEC), is guiding a process that helps each load-serving entity (LSE) collectively meet statewide energy, social, and environmental goals.

CPUC staff have issued a proposal for implementing integrated resource planning across the state. This proposal, created with input from the LSEs, outlines a structured process for LSEs to develop IRPs and for the CPUC to review these IRPs. The CEC has also drafted IRP submission and review guidelines specifically for publicly owned utilities. These proposals must first by adopted by the Commissioners before taking effect.

How is the California IRP process different? From its very foundation, the IRP process being developed in California lays a stronger foundation than those employed by virtually any other state. Here are eight such building blocks:

1. The IRP process uses greenhouse gas (GHG) emission reductions, cost, and reliability as drivers for deriving the amount of renewable energy in the resultant generation mix.

1. Plans are resolved to optimize the attainment of state policy goals, in addition to those of individual LSEs.
2. The CPUC is developing base plans, inputs, and assumptions that LSEs must use to develop their IRPs.
3. The planning process is being guided by several guiding principles that were created by the CPUC with input from the LSEs.
4. The minimization of air pollutants affected by the resultant IRPs must show early priority on disadvantaged communities across the state.
5. Resultant IRPs must identify an optimal mix of supply-side and demand-side resources for achieving GHG targets.
6. The process is being created in coordination with several state agencies.

The ultimate goal is “to identify optimal solutions that might not otherwise be found, and to guide resource investment decisions across all types of LSEs and resource programs.”

Senate Bill 350, the Clean Energy and Pollution Reduction Act of 2015, establishes new clean energy, clean air, and GHG reduction goals for 2030. The bill also introduces IRP planning as a statewide initiative. (Before SB 350, California did not require IRPs.)

Essentially, SB 350 requires resource planning to be based on attaining clean energy and clear air goals—a clear distinction from resource planning is most other states.SB 350 sets several targets for integrated resource planning to attain:

• Raises the RPS target from 33% to 50% by the end of 2030 (with interim targets for 2020, 2024 and 2027). The RPS must be attained through renewable energy procurement.
• Doubles energy efficiency (to 50%) by 2030 for buildings and retail end-uses.
• Sets emission targets for the electricity sector and LSEs for achieving the state’s 2030 GHG goal.
• Requires all LSEs to develop and file IRPs with the CPUC. These LSEs include all independently owned utilities (IOUs), community choice aggregators (CCAs), electric service providers (ESPs), and electricity cooperatives. Publicly owned utilities (POUs) whose three-year average of electricity demand exceeds 700 gigawatt hours must file IRPs with the CEC.
• Designates the CEC to set and monitor the IRP process for the POUs, and the CPUC to set and monitor the process for all LSEs.

Both the CEC and CPUC, through a number of workshops, solicited input from their respective LSEs into the IRP process. Both Commissions have published proposals that outline, in detail, the requirements for developing and creating the IRPs.

Some perspective, please. California reaching its 50% RPS goal in about thirteen years will have an enormous, worldwide effect on global warming. Why? Because California is the world’s sixth largest economy, behind only the United States (of course), China, Japan, Germany, and the United Kingdom; and just ahead of France, India, Italy, and Brazil.

That 50% RPS goal is certainly doable; the state currently attains a 26% RPS. In addition, Senate Bill 100, which sets an RPS goal of 100% by 2045, is currently making its way through the California legislature. The bill passed a Senate vote in May 2017, and could become law before 2017 ends. The bill passed a Senate vote in May 2017, and could become law before 2017 ends. Its passage would only serve to increase the state’s effect on global warming.

Next. Our next position paper will continue discussing the California IRP process: guiding principles, disadvantaged communities, plan categories, and a reference system plan.

—Rich Maggiani

He took my arm firmly, pulling me aside for a private conversation. I had been standing in a small circle with colleagues, talking, at a business organization meeting when he accosted me.

“So,” he started. “I understand you work with electric utilities.” More of a question than a statement.

It all happened so suddenly that I just looked at him. “Have we met?” I asked, mainly to gather myself.

“No,” he said, then introduced himself. I returned the favor.

“I know who you are,” he continued. “You used to sit on an energy-related committee with my wife.”

“And she is…” I ventured.

He told me. Different last name. But now I understood the connection. They modernized older properties, and one of their initiatives is to lower the energy requirements of the buildings by integrating renewable resources and energy efficiency measures.

“Ah. Yes, I work with electric utilities.”

“Around renewable energy?”

“Mainly around integrating more renewable resources into the electric grid.”

“So you know a lot about rooftop solar photovoltaic panels?”

I nodded, and started to smile. I had a good idea where this was going.

“And net energy metering?” his questioning continued.

I nodded again. “Yeah, I’ve written a bit about NEM.”

“Well…” he began, pausing a bit and leaning in. “I’m starting to get some push back from my neighbors about my solar panels. And my electric cooperative says I can’t expand my solar array.” He named the coop. “And I don’t understand why.”

Coincidently, a few months earlier, I spoke with the President of that cooperative, so had some precise figures.

“I’m not surprised about the cooperative,” I said. “They’re already at 12% penetration.”

“What does that mean?” he asked.

“It means that 12% of their customers self-generate from rooftop solar panels.”

“Well, isn’t that good?” he asked.

“Yes,” I replied. “It’s good to increase generation from renewable resources. But, the state only required utilities to accept up to 4%, and your coop already has three times that amount. And they are beginning to have trouble managing it, and seeing more of the cost inequities.”

He looked at me for a bit. Then, leaning back, he said, “I can see I’m not going to get any sympathy from you.”

I smiled. “Is that why you pulled me aside; you wanted my sympathy? I’m just being a realist here, giving you facts.”

He harrumphed. “Then give me some more facts.”

“Okay.” I said. “Can you tell me how NEM works for you?”

“Of course. I self-generate, use what I generate, and send the extra to the grid.”

“Do you get extra generation every day?” I asked.

“Most days.” he stated.

“What happens on really cloudy days, or when it rains? Or snows?”

“Well, I generate less. But over the long term, I generate more than I use.”

“And when it rains, or snows, or is cloudy, or at night, you have electricity?”

“Of course,” he said. “I always have electricity.”

“So you are using the grid’s transmission and distribution system?”

“That’s how I send and get electricity.”

“And, you get credits on your electricity bill; credits at the rate you would normally pay for electricity; retail rates?”

“All the time.”

“You’ve had your panels, how long?”

“Oh, quite a number of years.”

“Have you paid off your original investment? From the electricity credits?”

“A little while ago,” he said.

I paused to let all that sink in. “And you don’t understand why you’re getting push back from the coop and your neighbors?”

He thought for a bit. “I didn’t know about the 12% penetration stuff, but I don’t see how that matters.”

“Okay then. Let’s look at this from a 10,000 foot view.”

“Sounds good,” he said.

“Let’s start toward the beginning. The intent of the NEM law was to increase renewable generation distributed across the state. And in many areas, it has done that. Your area, for instance. In essence, everyone who self generates is an independent power producer. A very, very small one, but nonetheless. But there is a difference between you and a large producer. You are being paid retail rates for your generation whereas a large producer is being paid wholesale rates.”

“Besides that,” I continued, “the coop must take your generation before the large scale generators, so as the penetration goes up, so does their cost of electricity. Plus, self-generators are not paying the costs for infrastructure, transmission, and distribution. That’s extra cost and lost revenue. And it’s your neighbors, those that don’t participate in NEM, that are paying for that.”

Then I paused.

“Well,” he finally said. “I kinda knew all that.”

—Rich Maggiani