The “utility death spiral”: The utility as a regulatory creation

Unless you follow the electricity industry you may not be aware of the past year’s discussion of the impending “utility death spiral”, ably summarized in this Clean Energy Group post:

There have been several reports out recently predicting that solar + storage systems will soon reach cost parity with grid-purchased electricity, thus presenting the first serious challenge to the centralized utility model.  Customers, the theory goes, will soon be able to cut the cord that has bound them to traditional utilities, opting instead to self-generate using cheap PV, with batteries to regulate the intermittent output and carry them through cloudy spells.  The plummeting cost of solar panels, plus the imminent increased production and decreased cost of electric vehicle batteries that can be used in stationary applications, have combined to create a technological perfect storm. As grid power costs rise and self-generation costs fall, a tipping point will arrive – within a decade, some analysts are predicting – at which time, it will become economically advantageous for millions of Americans to generate their own power.  The “death spiral” for utilities occurs because the more people self-generate, the more utilities will be forced to seek rate increases on a shrinking rate base… thus driving even more customers off the grid.

A January 2013 analysis from the Edison Electric Institute, Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business, precipitated this conversation. Focusing on the financial market implications for regulated utilities of distributed resources (DER) and technology-enabled demand-side management (an archaic term that I dislike intensely), or DSM, the report notes that:

The financial risks created by disruptive challenges include declining utility revenues, increasing costs, and lower profitability potential, particularly over the long term. As DER and DSM programs continue to capture “market share,” for example, utility revenues will be reduced. Adding the higher costs to integrate DER, increasing subsidies for DSM and direct metering of DER will result in the potential for a squeeze on profitability and, thus, credit metrics. While the regulatory process is expected to allow for recovery of lost revenues in future rate cases, tariff structures in most states call for non-DER customers to pay for (or absorb) lost revenues. As DER penetration increases, this is a cost recovery structure that will lead to political pressure to undo these cross subsidies and may result in utility stranded cost exposure.

I think the apocalyptic “death spiral” rhetoric is overblown and exaggerated, but this is a worthwhile, and perhaps overdue, conversation to have. As it has unfolded over the past year, though, I do think that some of the more essential questions on the topic are not being asked. Over the next few weeks I’m going to explore some of those questions, as I dive into a related new research project.

The theoretical argument for the possibility of death spiral is straightforward. The vertically-integrated, regulated distribution utility is a regulatory creation, intended to enable a financially sustainable business model for providing reliable basic electricity service to the largest possible number of customers for the least feasible cost, taking account of the economies of scale and scope resulting from the electro-mechanical generation and wires technologies implemented in the early 20th century. From a theoretical/benevolent social planner perspective, the objective is, given a market demand for a specific good/service, to minimize the total cost of providing that good/service subject to a zero economic profit constraint for the firm; this will lead to highest feasible output and total surplus combination (and lowest deadweight loss) consistent with the financial sustainability of the firm.

The regulatory mechanism for implementing this model to achieve this objective is to erect a legal entry barrier into the market for that specific good/service, and to assure the regulated monopolist cost recovery, including its opportunity cost of capital, otherwise known as rate-of-return regulation. In return, the regulated monopolist commits to serve all customers reliably through its vertically-integrated generation, transmission, distribution, and retail functions. The monopolist’s costs and opportunity cost of capital determine its revenue requirement, out of which we can derive flat, averaged retail prices that forecasts suggest will enable the monopolist to earn that amount of revenue.

That’s the regulatory model + business model that has existed with little substantive evolution since the early 20th century, and it did achieve the social policy objectives of the 20th century — widespread electrification and low, stable prices, which have enabled follow-on economic growth and well-distributed increased living standards. It’s a regulatory+business model, though, that is premised on a few things:

  1. Defining a market by defining the characteristics of the product/service sold in that market, in this case electricity with a particular physical (volts, amps, hertz) definition and a particular reliability level (paraphrasing Fred Kahn …)
  2. The economies of scale (those big central generators and big wires) and economies of scope (lower total cost when producing two or more products compared to producing those products separately) that exist due to large-scale electro-mechanical technologies
  3. The architectural implications of connecting large-scale electro-mechanical technologies together in a network via a set of centralized control nodes — technology -> architecture -> market environment, and in this case large-scale electro-mechanical technologies -> distributed wires network with centralized control points rather than distributed control points throughout the network, including the edge of the network (paraphrasing Larry Lessig …)
  4. The financial implications of having invested so many resources in long-lived physical assets to create that network and its control nodes — if demand is growing at a stable rate, and regulators can assure cost recovery, then the regulated monopolist can arrange financing for investments at attractive interest rates, as long as this arrangement is likely to be stable for the 30-to-40-year life of the assets

As long as those conditions are stable, regulatory cost recovery will sustain this business model. And that’s precisely the effect of smart grid technologies, distributed generation technologies, microgrid technologies — they violate one or more of those four premises, and can make it not just feasible, but actually beneficial for customers to change their behavior in ways that reduce the regulation-supported revenue of the regulated monopolist.

Digital technologies that enable greater consumer control and more choice of products and services break down the regulatory market boundaries that are required to regulate product quality. Generation innovations, from the combined-cycle gas turbine of the 1980s to small-scale Stirling engines, reduce the economies of scale that have driven the regulation of and investment in the industry for over a century. Wires networks with centralized control built to capitalize on those large-scale technologies may have less value in an environment with smaller-scale generation and digital, automated detection, response, and control. But those generation and wires assets are long-lived, and in a cost-recovery-based business model, have to be paid for even if they become the destruction in creative destruction. We saw that happen in the restructuring that occurred in the 1990s, with the liberalization of wholesale power markets and the unbundling of generation from the vertically-integrated monopolists in those states; part of the political bargain in restructuring was to compensate them for the “stranded costs” associated with having made those investments based on a regulatory commitment that they would receive cost recovery on them.

Thus the death spiral rhetoric, and the concern that the existing utility business model will not survive. But if my framing of the situation is accurate, then what we should be examining in more detail is the regulatory model, since the utility business model is itself a regulatory creation. This relationship between digital innovation (encompassing smart grid, distributed resources, and microgrids) and regulation is what I’m exploring. How should the regulatory model and the associated utility business model change in light of digital innovation?

Building, and commercializing, a better nuclear reactor

A couple of years ago, I was transfixed by the research from Leslie Dewan and Mark Massie highlighted in their TedX video on the future of nuclear power.

 

A recent IEEE Spectrum article highlights what Dewan and Massie have been up to since then, which is founding a startup called Transatomic Power in partnership with investor Russ Wilcox. The description of the reactor from the article indicates its potential benefits:

The design they came up with is a variant on the molten salt reactors first demonstrated in the 1950s. This type of reactor uses fuel dissolved in a liquid salt at a temperature of around 650 °C instead of the solid fuel rods found in today’s conventional reactors. Improving on the 1950s design, Dewan and Massie’s reactor could run on spent nuclear fuel, thus reducing the industry’s nuclear waste problem. What’s more, Dewan says, their reactor would be “walk-away safe,” a key selling point in a post-Fukushima world. “If you don’t have electric power, or if you don’t have any operators on site, the reactor will just coast to a stop, and the salt will freeze solid in the course of a few hours,” she says.

The article goes on to discuss raising funds for lab experiments and a subsequent demonstration project, and it ends on a skeptical note, with an indication that existing industrial nuclear manufacturers in the US and Europe are unlikely to be interested in commercializing such an advanced reactor technology. Perhaps the best prospects for such a technology are in Asia.

Another thing I found striking in reading this article, and that I find in general when reading about advanced nuclear reactor technology, is how dismissive some people are of such innovation — why not go for thorium, or why even bother with this when the “real” answer is to harness solar power for nuclear fission? Such criticisms of innovations like this are misguided, and show a misunderstanding of both the economics of innovation and the process of innovation itself. One of the clear benefits of this innovation is its use of a known, proven reactor technology in a novel way and using spent fuel rod waste as fuel. This incremental “killing two birds with one stone” approach may be an economical approach to generating clean electricity, reducing waste, and filling a technology gap while more basic science research continues on other generation technologies.

Arguing that nuclear is a waste of time is the equivalent of a “swing for the fences” energy innovation strategy. Transatomic’s reactor represents a “get guys on base” energy innovation strategy. We certainly should do basic research and swing for the fences, but that’s no substitute for the incremental benefits of getting new technologies on base that create value in multiple energy and environmental dimensions.

Did ERCOT’s shift from zonal to nodal market design reduce electric power prices?

Jay Zarnikau, C.K. Woo, and Ross Baldick have examined whether the shift from a zonal to nodal market design in the ERCOT power market had a noticeable effect on electric energy prices. The resulting article, published in the Journal of Regulatory Economics, and this post may be a bit geekier than we usually get around here. I’ll try to tone it down and explain the ERCOT change and the effect on prices as clearly as I can.

The topic is important because the shift from zonal to nodal market structure was controversial, complicated, expensive, and took longer than expected. Problems had emerged shortly after launch of the initial zonal-based market and the nodal approach was offered as a solution. Some market participants had their doubts, but rather quickly ERCOT began the move to a nodal design. Note that phrasing: “rather quickly ERCOT began the move.” It took several years for ERCOT to actually complete the process.

In part the shift was promoted as a more efficient way to run the market. Zarnikau, Woo, and Baldick looked at the effect on prices as one way to assess whether or not the resulting market has worked more efficiently. They conclude energy prices are about 2 percent lower because of the nodal market design.

Don’t get hung up on the 2 percent number itself, but think of the shift as having a modest downward pressure on prices.

The result is consistent with an understanding one would gain from the study of power systems engineering as well as with what power system simulations showed. The point of the Zarnikau et al. study was to investigate whether data analysis after the fact supported expectations offered by theory and simulation. Because there is no better empirical study (so far as I am aware) and because their results are consistent with well-founded expectations, I have no reason to doubt their result. I will contest one interpretation they offer concerning the current resource adequacy debate in Texas.

Some background (which beginners should read and others can skip).

The delivery of electric energy to consumers is a joint effort between the generators that create the power and the wires that bring it to the consumer. The wires part of the system are not simple links between generators and consumers, but rather complicated network of wires in which consumers and generators are connected in multiple ways. The added flexibility that comes with networking helps the system work more reliably and at lower cost.

The network also comes with a big coordination problem, too. Power flows on the network are not individually controllable. With many generators producing power for many consumers, parts of the power grid may become overloaded. One key job of the power system operator is to watch the power flows on the electric grid and intervene as needed to prevent a transmission line from being overloaded. The intervention generally takes the form of directing a generator (or generators) contributing to the potential overload to reduce output and directing other generators to increase output. In areas outside of regional system operators, this function is done on a piecemeal basis as problems arise. A significant benefit coming from full-scale regional power markets integrated with system operations (such as ERCOT in Texas after the switch to a nodal market and in other similar ISO/RTO markets) is that such coordination can be done in advance, with more information, mostly automatically, and more efficiently than piecemeal adjustments.

Described in simpler terms, the regional power system operator helps generators and consumers coordinate use of the power grid in the effort to efficiently satisfy consumer demands for electric energy. A zonal market design, like ERCOT started with, did minimal advance coordination. The nodal market design and related changes implemented by ERCOT allowed the market to do more sophisticated and efficient coordination of grid use.

About data challenges.

In order to assess the effects on prices, the authors couldn’t simply average prices before and after the December 1, 2010 change in the market. The power system is a dynamic thing, and many other factors known to affect electric power prices changed between the two periods. Most significantly, natural gas prices were much lower on average after the market change than during the years before. Other changes include growing consumer load, higher offer caps, and increasing amounts of wind energy capacity. In addition, the prices are generated by the system has been changed, making simple before and after comparisons insufficient. For example, rather than four zonal prices produced every 15 minutes, the nodal market yields thousands of prices every 5 minutes.

One potentially significant data-related decision was a choice to omit “outliers,” prices that were substantially higher or lower than usual. The authors explain that extreme price spikes were much more frequent in 2011, after the change, but largely due to the summer of 2011 being among the hottest on record. At the same time the offer caps had been increased, so that prices spiked higher than they could have before, but not because of the zonal-to-nodal market shift. Omitting outliers reduces the impact of these otherwise confounding changes and should produce a better sense of the effect of the market change during more normal conditions.

Their conclusion and a mistaken interpretation.

Zarnikau, Woo, and Baldick conducted their price analysis on four ERCOT sub-regions separately so as to see if the change had differing impacts resulting from the changeover. The West zone stood out in the analysis, largely because that zone has seen the most significant other changes in the power system. The two main changes: continued sizable wind energy capacity additions in the zone, and more substantially, dramatic electrical load growth in the region due to the recent oil and gas drilling boom in west Texas. Because the West results were a bit flaky, they based their conclusions on results from the other three zones. Across a number of minor variations in specifications, the authors found a price suppression effect ranging from 1.3 and 3.3 percent, the load-weighted average of which is right around 2 percent.

So far, so good.

But next they offered what is surely a misinterpretation of their results. They wrote:

[T]he reduction in wholesale prices from the implementation of the nodal market might be viewed by some as a concern. In recent years, low natural gas prices and increased wind farm generation have also reduced electricity prices in ERCOT which has, in turn, impaired the economics of power plant construction. … It appears as though the nodal market’s design may have contributed to the drop in prices that the PUCT has now sought to reverse.

Strictly speaking, the goal of the Public Utility Commission of Texas hasn’t been to reverse the drop in prices, but to ensure sufficient investment in supply resources to reliably meet projected future demand. Lower prices appear to be offer smaller investment incentives than higher prices, but there is a subtle factor in play.

The real incentive to investment isn’t higher prices, it is higher profits. Remember, one of the most important reasons to make the switch from a zonal to a nodal market is that the nodal market is supposed to operate more efficiently. Zarnikau, Woo, and Baldick notice that marginal heat rates declined after the shift, evidence consistent with more efficient operations. The efficiency gain suggests generators are operating at an overall lower cost, which means even with lower prices generator profits could be higher now than they would have been. It all depends on whether the drop in cost was larger or smaller than the drop in prices.

The cost and profit changes will be somewhat different for generators depending on where they are located, what fuel they use, and how they typically operated. I’ll hazard the guess that relatively efficient natural gas plants have seen their profits increased a bit whereas less efficient gas plants, nuclear plants, and coal plants have likely seen profits fall a little.

FULL CITE: Zarnikau, J., C. K. Woo, and R. Baldick. “Did the introduction of a nodal market structure impact wholesale electricity prices in the Texas (ERCOT) market?.”Journal of Regulatory Economics 45.2 (2014): 194-208.

Here is a link to a non-gated preliminary version if you don’t have direct access to the Journal of Regulatory Economics.

AN ASIDE: One modest irony out of Texas–the multi-billion dollar CREZ transmission line expansion, mostly intended to support delivery of wind energy from West Texas into the rest of the state, has turned out to be used more to support the import of power from elsewhere in the state to meet the demands of a rapidly growing Permian Basin-based oil and gas industry.

Court says no to FERC’s negawatt payment rule

Jeremy Jacobs and Hannah Northey at Greenwire report “Appeals court throws out FERC’s demand-response order“:

A federal appeals court today threw out a high-profile Federal Energy Regulatory Commission order that provided incentives for electricity users to consume less power, a practice dubbed demand response.

In a divided ruling, the U.S. Court of Appeals for the District of Columbia Circuit struck a blow to the Obama administration’s energy efficiency efforts, vacating a 2011 FERC order requiring grid operators to pay customers and demand-response providers the market value of unused electricity.

Among environmentalists this demand-response enabled “unused electricity” is sometimes described as negawatts. FERC’s rule required FERC-regulated wholesale electric power markets to pay demand-response providers the full market price of electricity. It is, of course, economic nonsense pursued in the effort to boost demand response programs in FERC-regulated markets.

The court held that FERC significantly overstepped the commission’s authority under the Federal Power Act.

The Federal Power Act assigns most regulatory authority over retail electricity prices to the states, and the court said FERC’s demand response pricing rule interfered with state regulators’ authority.

Personally, I would have dinged FERC’s rule for economic stupidity, but maybe that isn’t the court’s job. Actually, I did ding the FERC’s rule for its economic stupidity. I was one of twenty economists joining in a amicus brief in the case arguing that the FERC pricing rule didn’t make sense. The court’s decision gave our brief a nod:

Although we need not delve now into the dispute among experts, see, e.g., Br. of Leading Economists as Amicus Curiae in Support of Pet’rs, the potential windfall  to demand response resources seems troubling, and the Commissioner’s concerns are certainly valid.  Indeed, “overcompensation cannot be just and reasonable,” Order 745-A, 2011 WL 6523756, at *38 (Moeller, dissenting), and the Commission has not adequately explained how their system results in just compensation.

But if this negawatt-market price idea survives the appeals court rejection and takes off in the energy policy area, I have the following idea: I’d really like a Tesla automobile, but the current price indicates that Teslas are in high demand so I’m going to not buy one today. Okay, now who is going to pay me $90,000 for the nega-Tesla I just made?

RELATED STORIES:

 

The case for allowing negative electricity prices – Benedettini and Stagnaro

Simona Benedettini and Carlo Stagnaro make the case for allowing negative prices in electric power markets in Europe. A few of the larger power markets in Europe allow prices to go negative, but others retain a zero price lower limit. Benedettini and Stagnaro explain both why it is reasonable, economically speaking, to allow electricity prices to go negative and the hazards of retaining a zero-price minimum in a market which is interconnected to markets allowing the more efficient negative prices.

It is all good, but I can’t resist quoting this part:

Negative prices are not just the result of some abstruse algorithm underlying the power exchange and the functioning of the power system. They are also, and more fundamentally, the way in which the market conveys the decentralized information that is distributed among all market participants, and that cannot be centralized in one single brain, as Nobel-prize winner Friederich Hayek would say. That information is translated into two major market signals, which are embodied in negative prices.

In the short run, negative prices show that there is a local condition of oversupply under which electricity is not an economic good which society is willing to pay for, but an economic bad for which consumers should be compensated. Therefore, negative prices create an economic incentive for consumers to shift their consumption patterns so as to capture the opportunity of being paid, instead of paying, to receive energy….

However, in the long run, negative prices talk to energy producers, not to energy consumers. The emergence of negative prices, although strongly conditioned by demand-side constraints, shows that the generating fleet encompasses too much “rigid” capacity (i.e. too much nuclear and coal-fuelled plants) and too little “flexible” capacity (for example CCGTs or turbo-gas power plants); or that grid interconnections are insufficient to properly exploit the spare, flexible capacity available within a market area.

So far as I know, all of the regional power markets in the United States now allow prices to go negative. The connections between wind power policy and negative prices have politicized the issue a bit in the United States. Benedettini and Stagnaro explain in a straightforward manner why, no matter what you think of renewable energy policies, you ought to favor allowing wholesale power market prices to go negative.

Texas wind power, the ERCOT power market, the Public Utility Commission

From SNL Energy, “Texas utility regulators expect to open investigation on wind ‘cost apportionment’“:

Having seen record wind output of more than 10,000 MW in March, ERCOT in the report also noted that Texas has gone well beyond its 10,000-MW capacity goal and far earlier than the 2025 target established in the state’s Public Utility Regulatory Act. …

And while wind energy continues to boom in Texas, the PUCT has been working with ERCOT on ensuring a reliable power grid amid wholesale prices that are not encouraging new fossil-fuel plant construction.

Perhaps, just perhaps, there is a connection between the “wind energy … boom” and the “wholesale prices that are not encouraging new fossil-fuel plant construction”?

The SNL Energy report noted the PUCT was beginning an investigation into cost apportionment issues surrounding wind energy and the recently completed CREZ transmission line additions.

AWEA brags about wind energy’s mediocre performance

On May 2 The Hill published a column by AWEA data spinner Michael Goggin, “Wind energy protects consumers,” in which the reader is regaled by tales of great service and low, low prices provided by the wind energy industry.

Sorting through the claims led me back to the AWEA blog, where among other things Goggin applauds the industry that pays his salary for its grand performance in trying times this past January in New York. Goggin exclaimed the New York grid operator “received very high wind output when it needed it most during the last cold snap, while other forms of generation experienced a variety [of] problems.”

Following the link provided to the NYISO press release I find the claim, “On Tuesday, the NYISO had the benefit of more than 1,000 MW of wind power throughout much of the day.” The New York grid operator reported peak demand during the day (January 7, 2014) at 25,738 MW, so wind energy’s contribution was in the 4 percent range. Another way to say that is that other forms of generation, despite experiencing a variety of problems, provided about 96 percent of the energy New York consumers received when they “needed it most.”

The AWEA website indicates that New York has an installed capacity of 1,722 MW of wind power. Doing the math reveals that about 40 percent of the wind energy industry’s generating capability failed to show when New York electric power consumers “needed it most.”

Impressive? Not really.

To more fully consider the situation, we’d have to ask just how much non-wind electric generating capacity has been driven from the New York market by subsidized wind power. It is part of the AWEA storyline that clean, low-cost wind energy “displace[s] output from the most expensive and least efficient power plants,” and obviously over time frequently displaced units are driven from the market. One may reasonably wonder how much generation capacity was driven from the market before that cold January day when New York electric power consumers “needed it most.”

In related news, the National Renewable Energy Lab just produced an exploration of the wind energy industry’s future with and without the Production Tax Credit. In brief, if the PTC is not revived once again, the industry will likely shrink by about half over the next several years, kept in business mostly by state renewable energy purchase requirements. Indirectly the study concedes that NREL doesn’t think wind power is cost competitive with alternative electric energy supplies, but under the best possible wind resource and grid access conditions.

Please note my occasional wind energy disclaimer: I am not against wind energy (a technology which can contribute real value in the right places), just against bad policy (which takes real value created by other people and shovels it in the direction of investors in wind energy assets and people who happen to own windy plots of land with good grid access).

Easy to dream big when you can spend other people’s money, and really, why else would you build solar power in Michigan?

Crain’s Detroit Business reports:

A solar power work group in Michigan is making progress discussing the possibility of expanding the current utility-sponsored solar incentive program ….

But the real question is whether DTE and Consumers will voluntarily expand their programs — as environmentalists, manufacturers and solar installers have been asking the state to require for job creation and public health reasons — before the programs expire in 2015.

Involved in the solar power work group discussion are state regulators, solar PV installers, solar PV manufacturers, environmental groups, and the state’s two large regulated utilities, DTE and Consumers Energy Co., who collect a regulator-approved renewable energy surcharge from their customers.

Not mentioned in the article are the views of retail electric power consumers, whose money is up for grabs, nor anyone thinking of federal taxpayers’ stake in the matter.

There is a respectable answer to the question “why else would you build solar energy in Michigan?” If you have strong pro-solar commitments, for ethical or other reasons, the you may well feel strongly enough about it to be willing to spend your own money on a system. Or, if you are off-grid or want to be, solar is one way to stay powered.

But the answer most prevalent in the work group, at least if the Crain’s article is a guide, is much less respectable: they are mostly people who feel strongly enough about solar power–or the money they might make from it–that they want to force their unwilling neighbors to pay.

Background on the Michigan solar power work group can be found at the pro-solar-policy Michigan Land Use Institute.

Decarbonization Now? (No, not yet.)

Paul Krugman’s recent opinion column in the New York Times ran under the headline, “Salvation Gets Cheap.” At first I though Krugman was making a snarky comment on ex-Mayor Michael Bloomberg’s claim that the ex-mayor’s work on restricting access to guns, and efforts on obesity and smoking would ensure a place in heaven. But no, Krugman is opining that technology is providing an easy way forward on climate change:

The climate change panel, in its usual deadpan prose, notes that “many RE [renewable energy] technologies have demonstrated substantial performance improvements and cost reductions” since it released its last assessment, back in 2007. The Department of Energy is willing to display a bit more open enthusiasm; it titled a report on clean energy released last year “Revolution Now.” That sounds like hyperbole, but you realize that it isn’t when you learn that the price of solar panels has fallen more than 75 percent just since 2008.

Thanks to this technological leap forward, the climate panel can talk about “decarbonizing” electricity generation as a realistic goal — and since coal-fired power plants are a very large part of the climate problem, that’s a big part of the solution right there.

It’s even possible that decarbonizing will take place without special encouragement, but we can’t and shouldn’t count on that. The point, instead, is that drastic cuts in greenhouse gas emissions are now within fairly easy reach.

The “Revolution Now” report, which was linked in Krugman’s column online, is surprisingly weak sauce. The U.S. Department of Energy report (your tax dollars at work) purports to describe “four technology revolutions that are here today” and “have achieved dramatic reductions in cost” and “a surge in consumer, industrial and commercial deployment” in the last five years. The four “revolutions” are onshore wind power, polysilicon photovoltaic modules, LED lighting, and electric vehicles.

Each “revolution” gets a two-page summary and a colorful chart showing declining costs and rising use. The summaries are footnoted, just like real research, and studded with more factoids than the front page of USA Today. Here’s a fun fact: the ratio of empirical claims to footnotes in the article’s two pages on wind power is 4-to-1.

You can get a sense of the quality of the report by considering the claims strung together on electric vehicles: First it is reported “more and more drivers are abandoning the gas pump for the affordability and convenience of in-home electric charging,” then that 50,000 EVs were purchased in 2012 and the rate of purchase doubled in early 2013. Next we are told “to maintain this momentum the most critical area for cost reduction is batteries.” A paragraph later the report said, “In many senses, EVs are already competitive with traditional cars.” In the final paragraph, however, a sober note: it will take “further progress on reducing the cost of EV batteries” to make “these benefits available to a larger audience.”

The sober note referenced a DOE battery cost target of $125/kwh by 2022, at which point the DOE expects ownership costs for a EV will be similar to a standard vehicle. A glance back at the chart suggests current battery costs nearer five times that level, leaving at least this reader wondering in which sense “EVs are already competitive with traditional cars” and part of the “technology revolutions that are here today.”

The revolution is here today! Or maybe in 2022!! Or maybe whenever “further progress” is made!!!

Overall the report is more enthusiasm than analysis, and not sufficient to justify changing beliefs on the cost of decarbonizing energy supplies.

Looking for renewable policy certainty in all the wrong places

From EnergyWire comes the headline, “In Missouri, industry wants off the ‘solar coaster’.” (link here via Midwest Energy News).

A utility rebate program authorized by voters in 2008 is making Missouri into a solar leader in the Midwest. But $175 million set aside to subsidize solar installations is [nearly] fully subscribed … and the same small businesses that scrambled to add workers last year to help meet surging demand are facing layoffs….

Heidi Schoen, executive director of the Missouri Solar Energy Industries Association, said the industry, which has generated thousands of jobs and millions of dollars in new taxes for the state, is just looking for certainty.

“We want off the solar coaster,” she said. “We don’t want to be in this boom-and-bust situation.”

It is a patently false claim.

If they wanted off of the boom-and-bust policy ‘solar coaster,’ they’d get off. They could go do unsubsidized solar installations for example, or if (when?) that proves unprofitable get work doing something else. By their actions they signal that they prefer the booms-and-busts that come with reliance on politicians for favors.