FERC Allows DERs to participate in regional organized wholesale markets. I wish we had one of those in the Pacific Northwest.

FERC Opens Wholesale Markets to Distributed Resources:
Landmark Action Breaks Down Barriers to Emerging Technologies, Boosts Market Competition
The Federal Energy Regulatory Commission (FERC) today approved a historic final rule, Order 2222, enabling
distributed energy resource (DER) aggregators to compete in all regional organized wholesale electric
markets. This bold action empowers new technologies to come online and participate on a level playing
field, further enhancing competition, encouraging innovation and driving down costs for consumers.
DERs are located on the distribution system, a distribution subsystem or behind a customer meter. They
range from electric storage and intermittent generation to distributed generation, demand response, energy
efficiency, thermal storage and electric vehicles and their charging equipment.
The final rule enables these resources to participate in the regional organized wholesale capacity, energy
and ancillary services markets alongside traditional resources. Multiple DERs can aggregate to satisfy
minimum size and performance requirements that they might not meet individually.
“Today FERC broke new ground towards creating the grid of the future by knocking down barriers to entry
for emerging technologies,” FERC Chairman Neil Chatterjee said, lauding the order. “With this final rule on
DERs, we build on the significant progress already made through Order 841 and expand our ability to harness
the full potential of these flexible resources. By relying on simple market principles and unleashing the
power of innovation, this order will allow us to build a smarter, more dynamic grid that can help America
keep pace with our ever-evolving energy demands. I am honored to be at the helm of the agency as we bring
this critical rule across the finish line and continue to navigate our nation’s energy transition.”
Under the new rule, regional grid operators must revise their tariffs to establish DER aggregators as a type
of market participant, which would allow them to register their resources under one or more participation
models that accommodate the physical and operational characteristics of those resources.
The new rule builds off the DC Circuit Court’s recent ruling on Order 841, in which the court affirmed
FERC’s exclusive jurisdiction over wholesale markets and the criteria for participation in them. Order 2222
prohibits retail regulatory authorities from broadly excluding DERs from participating in regional markets.
However, the new rule prohibits regional grid operators from accepting bids from the aggregation of
customers of a small utility unless the relevant retail regulatory authority for that utility allows such
participation. The final rule also respects retail regulators’ current ability to prohibit retail customers’
demand response from being bid into regional markets by aggregators.
The final rule will be enacted 90 days after publication in the Federal Register. Within 270 days of the
effective date, grid operators must submit to FERC a compliance filing and a plan for timely implementation
of the final rule.

Why we keep building a bigger church for Easter Sunday

Utility Classroom was founded in Oregon, supposedly the most “un-churched” state in the US. But even here in Oregon it’s apparent that the two days a year when many people go to church are on Christmas and Easter Sunday. Those are the days of the year when the church has to plan for a large enough building, a big enough parking lot, and enough seats for everyone to be welcome, even though during many other Sundays of the year some of that church and those seats sit empty.

Capacity on the North American grid can be thought of in the same way. The most important implication of this is that the costs for utilities are tied up in building the church for Easter Sunday, or in this case, the expected peak of the year. Utility costs have little relation to how much electricity customers use, but instead costs relate to when customers use electricity. Let’s explain and then come back to this implication.

The millions of people and businesses in the US and North America all use electricity differently over the course of the day and over the course of the year. For example, electricity use in the middle of the night is relatively low, but many customers have their lights, TV, stove, and heat (or air-conditioning) on around dinner time. When all customers’ electricity needs are added up, that is considered the “demand” or “load” that the utility system must serve from the capacity of the power plants, transmission, and distribution systems. The time period during which there is the greatest amount of demand on the system is called the daily peak. A utility does a great deal of planning over months, weeks, days, hours, and minutes ahead of time to prepare to serve each daily peak period. Over a year period utilities refer to this as the system peak and is likely to occur during a few minutes of 1 hour, somewhere between 4PM and 7PM, depending on utility location and load types. The ratio of average load on the system to peak load is called the load factor, and averages between 50-55% according to studies from the Electric Power Research Institute (EPRI).

Depending on what part of the country you might be in, that system peak could be the highest of the year in the summer or the winter. If you are in a warmer climate, the system peak will likely be during one of the hotter summer days when air-conditioning is using the most electricity. If you’re in a cooler climate, the system peak will likely be during a cold winter day when electricity is being used for heating purposes.

Thinking about utility resource and grid planning again the utility must (that’s how they are regulated) prepare for and build for capacity on their grid (more transmission lines, more substations, larger distribution transformers, maybe more power plants…) so that they can serve all grid-tied customers during that anticipated one hour of system peak. And since most components of the grid need to last for 20+ years, they need to anticipate how high the peak may be many years in advance. So, the cost of the grid is really tied up in preparing for the capacity during that one hour of that one day of the year:  the church for Easter Sunday. The Load Factor is the ratio of average energy use to peak use, and the average load factor in the US is about 50%.

Through energy efficiency initiatives (replacing incandescent lightbulbs, installing more efficient appliances, buying more efficient electronics…) and growth in distributed generation, customers are demanding less electricity year over year from the grid. The US overall generated less electricity in 2016 than in 2015 and is on pace to generate less electricity in 2017 than in 2016. In most places electricity demand is considered flat, drifting a little down, or barely growing year over year.

But…system peaks in most places continue to grow every year. And that means that the utility has to keep building a bigger and bigger church for Easter Sunday. The peak continues to grow because, while customers are using less overall electricity during a day or a year, they have not changed their behavior about when they use electricity. Here’s that implication referred to earlier: utility costs grow along with the growth in peak, but utilities charge (most of) their customers based on how much electricity they use, not on when they use electricity.  If customers use less electricity, but utility costs go up (because the peak is growing), then energy rates for everyone must go up.

What are the alternatives? Plenty! Here is where the industry is in a great state of change, so the following are just highlights.

It doesn’t make a lot of sense to put in a costly infrastructure that isn’t used most of the time, so utilities and grid operators are building pools of demand response solutions to encourage customers and their end use technologies to use less electricity during peak demand times (Hold more services on Easter Sunday and spread church use over the entire day). Also, some utilities are beginning to deploy time-based rates or demand charges to connect customer and technology behavior to the cost of building and operating the grid to meet peak demand.  Moreover, there is a great deal of focus on integrating storage solutions, distributed generation, and other distributed energy resources so utility electric operations have more flexibility in delivering electricity versus yesterday’s “just in time” electricity operations model, further lowering the need for that larger church for Easter Sunday.

Does this analogy work for you?  Are you aware of other solutions to using the grid more efficiently?  We welcome your comments below.

-Scott Williams, Kevin Cornish, and Ken Nichols

August 2015, EQL presents at NCSL, Seattle WA


Everyone loves EV

EQL Nichols NCSL 2015 8 2 v1

Topics involved rate changes to accommodate distributed energy resources, use of demand charge, value of solar, and everyone loves EVs. EVs are “energy” efficient, lowers customer transportation costs, improves utility revenue, should lower rates, and if managed properly should not add much to utility infrastructure and integration costs. Utilities should take an active role in enabling and integrating DER.

Ken Nichols presents at Northwest Future Energy 4/16/2015

Ken Nichols presented the opportunity and capabilities of demand response and distributed energy resources in the Pacific Northwest. His presentation summarized a project to defer transmission & distribution investments and integrate renewable energy resources. He was part of a panel with Stephan Williams, SmartGrid Northwest; Peter Brown, 38Zeros; and James Mater, Quality Logic.

Staking DER measures to manage substation load