I was at Home Depot this weekend (so many tools, so little time) and they had a special on LED lights that caught my attention—a four pack of dimmable 60-watt replacement LEDs was selling for $9.88, or just under $2.50 a bulb. I’m not the type to track day-to-day pricing for much of anything, but the display caught my attention because I had just finished reading the Energy Department’s latest report on the status of the LED market—which found that the typical dimmable 60W replacement bulb in 2016 cost roughly $8 apiece.
This is important for two reasons. First, DOE assumes that LEDs are steadily going to account for an ever-larger percentage of the installed lighting stock in the United States, estimating that by 2035 86 percent of all the lighting in the country will be LEDs of one type or another and that these vastly more efficient lights will cut primary energy use by 3.7 quadrillion British thermal units (Btus)—that’s a lot of electricity that will no longer be needed, about 10 percent from the 2016 level, in fact, when roughly 37.5 quads were used to generate electricity in the U.S. (Paying attention out there in utility land?) But those DOE forecasts rely heavily on pricing assumptions, and if the current price of the most commonly used LED has already tumbled below $2.50, down roughly 70 percent from just a year ago, that means the nationwide take-up of LEDs almost certainly will be faster than DOE currently estimates.
Second, the sharply declining price of this lowly light bulb is a symbol of the massive changes under way in the energy industry, such as the steep declines in solar and windpower costs, the surge in corporate interest in cleaner energy and the plateauing of electricity demand. These changes are largely market-driven and, thankfully from my perspective, outside the reach of politicians on either side of the aisle.
Continue reading Latest DOE LED Report
In Electric Power Sector
Electric utility executives already fretting about slow/no growth in their service territories have another item to add to their growing list of worries: the prospect that many of their commercial customers could begin installing behind-the-meter storage to lower their demand charges.
A recent white paper from DOE’s National Renewable Energy Laboratory and the Clean Energy Group, a nonprofit advocacy organization, shows that it could be economic for almost 28 percent of commercial customers across the country to install batteries at their business sites to cut their electricity consumption during specific periods of the day, thereby reducing their exposure to utility-imposed demand charges. This would amount to a one-two punch for utilities: electricity sales would drop if the batteries were linked with solar and the amount of revenue collected from these charges would fall, not a pretty picture for the utility industry.
Continue reading Storage Puts Utilities
In A Big Bind
On Demand Charges
The nuclear morass that has ensnared utility executives, state regulators, and legislators in South Carolina and Georgia shows no signs of easing its grip. Southern is set to decide soon whether its Georgia Power subsidiary will seek to complete Vogtle 3 & 4 even though the total cost for the much-delayed nuclear project has now ballooned to an estimated $25 billion. How those economics can ever pencil out is beyond me, but that is not the topic for today. Across the border in South Carolina, the blame-passing game has now started in the wake of Santee Cooper’s decision to pull out of the similarly delayed and way-over-budget V.C. Summer 2 & 3 project: Legislators in the state launched a series of hearings this month on the project, and the first order of business for Kevin Marsh, chairman and CEO of SCANA Corporation (the parent of South Carolina Electric & Gas, the lead partner in the Summer project) was to remind everyone listening that the company had done everything by the book, and that state regulators had continually vouched for the prudence of the utility’s decisions. But that is for another column as well.
What caught my eye, and what nobody at either utility ever wants to talk about, was the first bullet on the first page of Marsh’s presentation (which is available here). “Why did we choose nuclear in 2008?” he asked, rhetorically, I hope. His lead answer? “Growing customer demand required the addition of new base load generation.”
And therein lies the rub. Growing demand in the early 2000s clearly played a major role in pushing both Georgia Power and SCE&G to ask regulators to approve their respective nuclear projects. But the absence of similar growth, in fact the absence of any growth at all since the 2008-2009 recession and its consequent impact on the need for the projects, has been largely ignored by both utilities, as is abundantly clear in a review of their state-mandated integrated resource plans. Let’s take a look.
Continue reading Georgia Power, SCE&G
Whistling In The Dark
On Growth And Nuclear
Last week’s headlines focused on Georgia Power’s newly signed agreement with Toshiba committing (recommitting?) the Japanese parent of bankrupt Westinghouse to pony up $3.68 billion to fund the completion of the long-delayed Vogtle 3 & 4 nuclear power plants. While that is clearly good news (at least for the moment) for Georgia ratepayers, who could otherwise have been stuck with the bill, it has obscured the real news—that no one knows how much it is going to cost or how long it is going to take to complete the two reactors.
The day before Georgia Power’s headline stealing news, staff and the independent construction monitor filed testimony at the Georgia Public Service Commission covering the latest six months of activity at the site (from July 2016-December 2016, with rollover analysis through April 2017). Their conclusion? The project has been a mess since the beginning, and there are still no signs of improvement (although admittedly couched in far more diplomatic/technical language, to which we now turn).
At the macro level, much of the problem can be traced to the absence of a credible integrated project schedule or IPS, an absolute must in a project as complex as this, William Jacobs, Jr., and Steven Roetger told the commission. Jacobs has served as the project’s independent construction monitor since 2009; Roetger is the commission’s lead analyst for the project. They have been highly critical of the Southern/Westinghouse work at Vogtle for years and have warned consistently that the stated completion dates bore no relationship to reality; see my stories here and here.
Continue reading New Analysis
Begs The Question:
Is Vogtle Project
Too Costly To Complete?
President Trump, with his fossil fuel fantasists in tow, made it official Thursday, announcing that he would pull the United States from the Paris climate change accord in order to “make America great again.” The administration’s inability, as well as that of most of the Republican Party in general, to come to grips with climate change is sad, but that will have to wait for a future post. The issue at hand is the decision’s likely negative impact on the U.S.’ already-battered nuclear and coal industries.
For years the nuclear industry has been making the case that it was vital to the country’s climate change mitigation efforts because of its emissions-free generation profile. While accounting for just 20 percent of the nation’s annual electric generation, the industry noted ad infinitum, it was responsible for 60 percent of the carbon dioxide-free emissions (see chart below). In a carbon-constrained world, that would be a valuable attribute. But the Trump administration has now made it clear that it places no value on CO2-free generation sources.
That, in turn, could be a major problem for the industry, as the effort to secure nuclear subsidies—successful so far in Illinois and New York (although now tied up in court), still pending in Ohio, Connecticut and now Pennsylvania—has relied in large part on the sector’s glowing greenhouse gas attributes. In an interesting twist, just before the administration’s head-in-the-sand announcement, Chicago-based Exelon said it would close the 837-megawatt Three Mile Island nuclear reactor in late 2019 because the facility couldn’t compete in the PJM electricity market, which sprawls across 13 states and the District of Columbia. The company largely blamed the market’s structure, including its failure to reward the plant for its emissions-free generation, for its decision to shutter the plant.
Continue reading Trump Paris About-Face Likely To Hurt, Not Help Nuclear, Coal Sectors