Why 2018 remains a good year for U.S. solar and how San Diego will serve as a model for our energy future
The solar industry has been making plenty of headlines lately, but for all of the wrong reasons. Even last year the relatively young industry experienced some of its first real turbulence after a decade of uninterrupted growth. The residential solar market started 2017 off with a 31 percent year-on-year reduction from Q1 2016 along with bankruptcies from Sungevity and Heliopower, among others. And 2017 brought on the first blow in the category tantamount to solar’s ace in the hole, at least politically: American jobs. While the loss of 10,000 jobs may sound trivial, 2017 marked an inflection point for an industry that nearly tripled in size from 2010 to 2016.
But heading into 2018 it was the Section 201 petition by Suniva and Solar World that brought solar into the forefront of the media, seemingly a harbinger of another inauspicious year for the industry. Dubbed “Trump’s Tariff” in mainstream news articles, it was easy to associate the tariff against imported modules with his administration’s protectionist stance, rhetoric around “clean coal” and climate change skepticism.
The hyperbole obscured that it was the bright idea of opening a manufacturing plant in Georgia to compete with government-backed foreign imports that spurred a bankrupt (and itself foreign-owned) Suniva – not Trump – to file for the trade case to begin with. And the final tariff, 30 percent in the first year and decreasing over the next 3 years, was less than half of the amount called for in the initial petition.
Lost in the doom and gloom is the continued health of the distributed generation (DG) solar space: mid-scale projects (~$1-$10 million) with electricity procured locally by the host or through a community solar program (as opposed to wholesale to a utility). And the burgeoning storage industry, driven by cost reductions coupled with inevitable policy changes in solar-heavy markets like California, has been egregiously passed over in popular discourse. San Diego, a previously underserved region in the hottest solar market in the country, is rapidly becoming a microcosm of the potential for DG solar and storage policy to transform the renewable energy landscape.
The bright side
Solar’s unique modularity results in varying demand drivers at the residential, commercial and utility scale. While planned large-scale projects, in which modules are up to half of a project’s build price, are disproportionately impacted by the infamous tariff, the residential space has declined regardless due to SolarCity and Vivint’s exodus as well as the retraction of aggressive financing schemes that drove that consumer-oriented market.
DG solar, however, driven largely by policies at the state level, grew 22 percent in 2017 and is poised to continue that trend in 2018. Massachusetts and Minnesota have revamped their policy to feed off existing momentum from their wildly successful programs and Illinois is primed to spur a local solar boom with an imminent community solar program.
It doesn’t require an expert to determine that California has long been the true barometer of the U.S. solar industry. Through 2017, the cumulative solar capacity in California is nearly 6 times that of #2 on the list, North Carolina. In fact, looking at the list of the top 10 U.S. solar states in Figure 1, you can add up all of numbers 2 through 10 and still fall short of the bar set by California.
Cumulative Solar Capacity by State, through Q3 2017
California’s commercial and public-sector success depends largely on Net Energy Metering (NEM), a program where utilities credits solar owners for unused electricity from their systems that’s pumped onto the grid. Utilities have fought net metering tooth and nail for years, and it barely survived the January 2016 “NEM 2.0” proceedings in which utilities maintained the policy shifted infrastructure and load-balancing costs back to the utilities.
In other words, solar is generated whenever the sun shines, rather than when demand is highes. While NEM 2.0 was passed, it faces growing headwinds that it will have to contend with for an extension as it sunsets in 2019.
San Diego & the growth of storage
But as has often been the case in a volatile industry affectionately dubbed the “solar-coaster” by its pioneering members, big challenges engender big opportunity. San Diego Gas & Electric (SDG&E) is the first large utility in California to have finalized updated Time Of Use (TOU) rates, which dictate the value of credits received during different hours of the day for net-metered electricity. The TOU rates in San Diego shown below reflect solar’s grid imbalance issue: the flooding of electrons during sunny portions of the day with little to no generation to support the second spike of the day as the family comes home from school and work to crank the air conditioner or flip on the game. More importantly, the figure underscores the most basic tenet of economics: as supply decreases in the evening while demand increases, the value of that electricity – as SDG&E scurries to distribute energy to its customers – goes up.
Weekday Time Of Use Rates Energy Rates* in SDG&E (Option R Secondary tariff for solar)
This trend is propelling the storage industry. The value proposition of energy storage is simple: store the electricity generated in the afternoon and release it to the grid in the evening when it’s worth up to 250 percent more, depending on the tariff. And in parallel the price of lithium-ion storage for commercial and industrial customers to manage their energy consumption – the same type of battery found in everything from electric cars to the cellphone in your pocket – has decreased by over 80 percent over the past two years.
Let’s imagine your office in SDG&E territory has a typical load profile. While most of your consumption happens from 9 to 5, the net metering “credit” rate in that period is only around $0.20 per kilowatt-hour. Purely with solar, assume you have the load to build a 1 megawatt (MW) solar project that costs somewhere around $2 million less the 30 percent investment tax credit (ITC) (give or take depending on whether you install rooftop solar or solar carport structures in your parking lot). In the first year alone, this would offset (through NEM) more than $235,000 (nearly half of an assumed ~$500,000 annual bill) and take around 7 years to get your payback.
For the sake of round numbers, a 1.5 MWhr storage system costs about $1.2 million. While your upfront investment increases by 60 percent, now up to 1,500 kWh generated per day are sold to SDG&E at over double the rate.mUsing similar assumptions, that added $1.2 million upfront expenditure reduced the payback timeframe from around 7 years to 6 years.
Perhaps reducing the payback period by 1 year isn’t electrifying; this, however, doesn’t account for the policy benefits of both the ITC for storage (when coupled with solar) as well as the Self-Generation Incentive Program (SGIP) that provides an upfront rebate for storage. As of this writing, SDG&E is in Step two of this declining block incentive program, which (for anything larger than residential) provides a $0.29-per-watt-hour rebate for an ITC-eligible storage installation. With these incentives, payback is reduced to around 4 years for two technologies that are designed and financed to last far longer.
The solar industry’s trajectory has never been smooth: fraught with uncertain tax credit deadlines, overly publicized bankruptcies, and now import tariffs. But throughout the policy volatility the technology has improved, prices have plummeted, and Americans have innovated to grow a diverse ecosystem of jobs – including finance, maintenance, construction and manufacturing – and will continue for years despite today’s bumpy ride.