I took a look at electricity data recently from California and Hawaii and I saw a duck that was learning to fly.

Well, what I saw was that the so-called Duck Curve — the load shape some grid operators expect to contend with as increasing levels of wind and solar resources create ramping challenges for conventional generation — is evolving slower over time in these two states.

Some contend that peak demand will continue to grow as mid-day net-load drops, making an ever-steeper ramping need—hence the Duck Curve. But Hawaii and California are casting doubt on this premise. We highlight many ways to address this challenge in our publication Teaching the Duck to Fly. And some of these things are happening now.
Let’s start in California.

For a reminder, here's the classic California Independent System Operator (CAISO) duck curve. It forecasts that peak demand will grow about 10% between 2012 and 2020.

A recent blog post from the Energy Center at Haas uses some real data from CAISO. The data are not perfect (they are not weather-adjusted, and there’s a small problem with losses) but they are close enough to be instructive.

What it shows is that peak has actually been dropping over the last few years, not rising. The March peak in 2016 was down about 5% relative to 2013.

As California rolls out time-of-use (TOU) rates, I expect that commercial and residential customers will find they can forego many energy-intensive activities such as laundry or baking during high price times on weekday evenings, causing the peak to drop even more. [I don’t want to be too optimistic — a warming planet can possibly overwhelm improving cooling efficiency.]

Evaluation work from the Sacramento Municipal Utility District’s pricing pilot shows that more than 80% of customers took discrete actions to reduce loads during high cost periods, including turning off lights and electronics, deferring laundry and dishwashing, and adjusting thermostats.

Here’s the graphic of actual loads (note that the vertical axis does not start at zero, which accentuates the perception of a steep afternoon rise in usage).

The lack of weather adjustment leaves me hesitant to declare this to be dispositive, but there is no obvious increase in peak demand over this analysis period. This is no surprise — energy efficiency programs, building code improvements, and demand response efforts have continued in California. In addition, California rate designs for commercial and industrial customers provide a strong incentive to manage afternoon demand, and the inclining block rate design for residential customers provides a strong incentive to manage “tailblock” demand — usage above 130% of the customer average monthly usage — which is dominated by air conditioning loads (an afternoon-peaking load).  

The Aloha State: More dramatic reductions

In Hawaii (where there has been some other big news recently in the form of the HECO-NextEra merger denial), solar penetration has reached 16% of customers. That’s more than a third of owner-occupied single-family homes—the customers with roofs they control and access to credit.

The same trend we saw in California is happening in Hawaii, and the results are no less than stunning. The decline in total utility loads is due to a combination of solar, energy efficiency, and price response. It’s certainly difficult to separate the three causes, and I won’t try.

The graphic below is taken from the Hawaiian Electric Company (HECO) Power Supply Improvement Plan, submitted to the Hawaii Public Utilities Commission in 2015. It is very interesting.

Key here is that the peak used to be around 1 p.m. Solar has dramatically lowered that mid-day peak. Now the peak is at 7 p.m., but it is both lower than it used to be at 7 p.m. (driven by energy efficiency) and much lower than it used to be at 1 p.m. (driven by both solar and energy efficiency). Arguably, through 2012, solar was reducing the peak demand which occurred during the solar day. But, by 2014, the peak had shifted to the evening, and additional solar no longer has a direct impact lowering peak demand.

This argues for “grandfathering” solar early adopters at a more generous compensation scheme than post-2014 solar customers. Clearly, they have provided both capacity benefits for the electric system and reduced petroleum consumption, while actually making it easier for the utility to follow load through the day. No “quacking” is audible in the data through 2014. And the Hawaii PUC has done exactly that—preserved net metering for existing customers, and adopted a different and lower compensation framework for new solar customers.

What a difference 8 years makes

Let's look at how a June Tuesday in Hawaii looks in 2014 compared to 2006.

1. The "morning ramp" has been cut in half. In 2006, Hawaiian Electric had a single steep ramp of 450 MW between 6 a.m. and noon. In 2014, they had a ramp of 250 MW and then a pause for the middle part of the day due to solar PV meeting the growth in mid-day loads, then a rise of another 200 MW in the early evening. This means that the utility does not have to keep as many power plants “warm” overnight to meet the morning load growth, saving fuel for all customers.

2. The maximum peak demand has been cut from 1,200 MW in 2006 to 1,050 MW in 2014. This helps avoid the need to construct and maintain expensive generating capacity.
3. The "afternoon ramp" is now from 850 MW to 1,050 MW, a ramp of 200 MW; this means the utility has more time to gradually increase generation during the day, and some efficient power plants ramp slowly, so this is probably saving fuel.
4. They are starting to see some actual decline in net load for the dispatchable system, visible for Saturday and Sunday. So the "Duck Curve" is indeed beginning to form, with a “belly” at mid-day when all of the solar is producing. But this didn’t happen until 2014, when PV saturation reached about 13 percent of all customers. Or, about 6 times the saturation in California and other leading PV states.
5. In 2006, the peaks occurred from noon to 2 p.m.; now they are occurring at 7 p.m., consistent with the shape of the duck curve. But they are a lot lower, which is not consistent with the CAISO prediction.

The bottom line of the changing load shape is that the duck curve is evolving much slower than previously assumed. The reduction in total peak demand, and the more gradual ramping requirement both make system planning and operation easier, and reduce costs.

Customer bill impacts

But wait—there’s more! Customer bills in Hawaii are going down, as well.

In Hawaii, energy efficiency and renewable energy are bending the load curve, and also significantly reducing demand, driving bills down. Even despite increased per-kWh rates, customer bills are lower because of the significant reduction in demand.

Hawaii has a decoupling mechanism to make the utility whole for any decline in sales. Every year, there is a rate adjustment from the Revenue Balancing Account (RBA) for sales and from the Revenue Adjustment Mechanism (RAM) for changes in system costs due to improvements, including improvements to adapt to higher levels of variable renewables. Since decoupling began, overall cumulative decoupling surcharge increases have been between 4 and 7 percent. If usage had remained the same, bills would have increased. But usage has declined sharply and the bills are lower.

The data below is for the residential class from the 2016 decoupling filing in Hawaii, where the Hawaiian Electric Company (HECO on Oahu, HELCO on the Big Island, and MECO in Maui County) seeks recovery of distribution margins lost as a result of lower sales (from any cause).

First, the overall rate impacts in this year’s filing are pretty trivial—0%, 0.2%, and 0.54% (increases due to lower sales made smaller by prior-year reconciliation adjustments, and totally dwarfed by reduced fuel costs in any event, and those are not shown here). I used average revenue/kWh from 2011 as a baseline against which to measure the cumulative impact of decoupling. The cumulative impact over the five-year periods are more significant.

If we divide the total amount of the RBA (cumulative since 2010 for HELCO, 2011 for HECO, and 2012 for MECO), it's a 4% to 7% total increase across the history of decoupling. Add to that the energy efficiency surcharge, and you have total rate increases of 5% to 9%. But, importantly, this is offset by declines in per-customer usage are at least twice as large. Small rate increases, in short, are more than offset by large usage decreases.