MasterResource » Electricity: ‘Smart Grid’

Smart Grid Wiseup: Google and Microsoft Quietly Exit (energy efficiency vs. the hassle factor)

rmichaels — Wed, 26 Oct 2011 06:00:55 +0000

“I have never known much good done by those who affected to trade for the public good. It is an affectation, indeed, not very common among merchants, and very few words need to be employed in dissuading them from it.”

- Adam Smith, The Wealth of Nations (1)

We all know that Google is incredibly future-oriented, and that, for all its problems, Microsoft, knows a lot about technology and markets. Why, then, did each shockthe ‘smart grid’ movement by announcing the phaseout of their home energy metering and control technologies (Microsoft’s Hohm and Google’s EnergyMeter)?

The deep meaning of this is less about technology than it is about politics.

Two PR Moments

You will learn nothing from the announcements from Google and Microsoft. Both companies’ PR departments broke the news as sanctimoniously as possible, using the language of planetary consciousness.

Google claimed that its device was really a charitable endeavor that originated in the company’s philanthropic arm. (Thank heaven for free cash.) For much of its lifetime EnergyMeter was managed by a former astronaut (honest), who said the company was “not trying to build a business model around it.”

Microsoft’s release is a contender for the record in concentrating words like sustainable, ecosystem, quality of life, climate, collaborative, etc., etc. into four fairly short paragraphs. Being Microsoft, however, it closed by touting the sustainability of its new hobby horse, the cloud, almost certain to be as insecure as Windows.

Second-hander business…. Where do-goodism reigns over bottom line discipline. Where perception is the main game. Remember Enron? Remember the wisdom of Adam Smith who saw bad results in his eighteenth-century day?

Penny-wise, Pound Foolish

There are more understandable reasons for the twin exits. Home area network (HAN) enthusiasts initially expected bill savings of 15 percent, but even the earliest and nerdiest adopters usually averaged around 3 percent (Greentech Media, June 24, 2011).

The rhetoric tells you a lot. Two years ago (June 16, 2009) GreenBiz.com heard from Google’s head of energy and climate policy:

Imagine if you walked into a grocery store, chose the food you want (no price tags), took it home and then, at the end of the month got the bill in the mail. That’s essentially what we are doing with electricity and gas right now.

The analogy works only if we assume that the only known food is oatmeal, if we disregard the fact that power rates are regulated and if we forget that most peoples’ bills are so predictable that they can easily budget for them. He noted that Google employees, not surprisingly, enjoyed beta testing their meters, saving as much as $10 a month and finding all sorts of subtle and unexpected patterns in their power use. I find the same sort of patterns when studying martinis. Problem is that a $10 saving probably won’t get you more than one quality martini in a nice bar, if that.

Worse still for the HAN folks, if you really want to save 3 percent there have long been low-tech ways to do it. A common one is to become a parent who harangues the kids when they leave lights on. Technology might not matter because companies like Opower that collaborate with utilities claim to get 3 percent use reductions for their utility clients.

Efficiency Gone Wild

One strategy is to send people power use reports and emails that nag them to conserve. Efficiency 2.0 has a similar tool that may take you back to childhood. It partners with utilities and school systems to put students in business selling CFLs instead of magazine subscriptions, and offers discount shopping coupons to households that exceed conservation quotas (Greentech Media, June 30). Consultants like Pike Research are cutting their projections of HAN penetration. And yet we keep seeing venture investment.

One headline in Greentech Media (June 20) said it all: “IControl raises $50 million more for $0 billion HAN market.” Most of what is getting ventured and invented seems to be more of the same, which people don’t seem to want very badly or whose results they can get in other ways. Our clue to an explanation comes from a “very secret startup” called

Nest Labs, Inc., which is said to get its funding from VC firms like Kleiner Perkins (Greentech Media, June 10). Nest is tied up with a shadowy residential control outfit called “Stealth Efficiency Co,” as scary a name as you can envision in this business.

Nest’s trademark filing is interesting. It claims to be creating

climate control system consisting of a digital thermostat that automatically sets climate conditions based on prior and historical patterns of climate settings selected by users; [a] climate control system consisting of a digital thermostat that can be controlled wirelessly from a remote location; software application for use on computers and hand-held devices to control climate and energy usage in businesses and homes from a remote location… (it will also have capability for) creation and transmission of messages and incentives to energy users to reduce their energy use.

This looks like the same utility-controllable appliance scheme that even California couldn’t force on people three years ago, with the added excitement of streaming propaganda and promotions that users probably can’t opt out of.

Conclusion

Outfits like Opower, Efficiency 2.0 and Nest will all live or die depending on their relations with utilities and regulators. They will make their money by partnering with regulated monopolies who can force their products on consumers, or at least force the consumers to pay for what they would rather do without.

And that’s why the same stuff keeps getting invented. The new age of electricity is going to look a lot like the old one, with the added dividend of electronic nagging.

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(1) Smith, Adam. An Inquiry Into the Nature and Causes of the Wealth of Nations. 1776. 2 vols. Edited by R. H. Campbell and A. S Skinner. Indianapolis: Liberty Fund, 1981, p. 456.

The Smart Grid and Distributed Generation: A Glimpse of a Distant Future

KHawkins — Thu, 28 Apr 2011 06:00:34 +0000

A smart grid/distributed generation combination could have a large role to play in the future of electricity systems in terms of both supply and use. But it is incorrectly being touted as the solution to our perceived electricity problems in the short term, that is for the next 10 to 20 years. Meaningful fulfillment of a “smart” grid and/or extensive Distributed Generation could be a half-century away, even more. Therefore, early, extensive, and expensive initiatives that claim to be on the “right track” are very likely to be on the wrong track later.

Is the right track (1) upgrading the grid capacity and implementing new transmission lines to facilitate the integration of utility-scale wind and solar or (2) the implementation of smart meters to match (read restrict) demand to the erratic and unreliable supply of these?

Absolutely not. Such ill-advised initiatives will require an unacceptably large investment in grid elements that will likely all too quickly become irrelevant as the needed electricity infrastructure changes are engineered and introduced in the future.

But first things first: what is meant by Distributed Generation (DG) and the smart grid?

Distributed Generation (DG)

One of the primary purposes of DG is to meet some level of local demand, not feed the grid. The imposition of mandated levels of renewable energy (RES) and Feed in Tarrifs (FIT) with premium prices to incent the deployment of wind and solar creates a “gold rush” for the latter. Industrial-scale wind and solar generation plants are like traditional generation sources in that they produce electricity to meet demand elsewhere, and in the case of wind and solar often at great distances. They are geographically distributed, and this is one element of differentiation from conventional electricity generation sources, but this is because the fuel, wind and sunlight, is dispersed widely. This is not DG.

The correct view of DG involves small-scale generation sources, for example roof-top solar and possibly micro wind turbines (better designs are possible) as well as many other non-utility scale generation means, and this list can be quite long. These will be integrated within micro-grids that contain intelligence to manage local production, storage (which is feasible even today at this level and shows considerable promise for the future) and use, as well as connection to the grid through intelligent gateways. Micro-grids can serve many types of “communities”, for example residential (especially in rural areas), combinations of commercial/industrial/residential communities, and college campuses. Such “concepts” are already being experimented with, for example at the University of California, San Diego, (USCD) including a gas turbine/combined heat and power system, and solar and fuel cell technologies described here and electric cars here. A quote from Byron Washom, the campus’ director of Strategic Energy Initiatives is appropriate.

“UCSD will become a laboratory where technologies can be tested and consumers’ behavior can be analyzed.”

Ignore the hype in the above examples, but applaud the approach as summarized by Washom. Also note the focus on consumer behavior at the same level as the technologies.

Will the “smart” meters being installed today be compatible with this yet-to-be architected and engineered smart grid? It is unlikely and represents potential high stranded costs that will encumber future generations. Today smart meters appear to have the major purpose of providing a means to raise electricity rates through aggressive time-of-day pricing to help fund the large investment needed, primarily for wind plants, and the extra transmission and generation facilities required to support them.

The Smart Grid

In a brochure by the Department of Energy (DOE), short term initiatives, as described in the second paragraph above, are labelled the “smarter” grid, supposedly on the track to the “smart” grid. Even without any knowledge of the issues involved, anyone familiar with unbelievable promises all too evident in some commercial advertising will recognize the warning signs. Here is a quote from the DOE about “smarter grid” initiatives (emphasis added):

Ensuring its reliability to degrees never before possible.
Maintaining its affordability.
Reinforcing our global competitiveness.
Fully accommodating renewable and traditional energy sources.
Potentially reducing our carbon footprint. [interesting qualification]
Introducing advancements and efficiencies yet to be envisioned.

More information on this and the warnings from The North American Electric Reliability Corporation (NERC) have previously been described here.

The reality is no one knows what the smart grid will ultimately look like. It represents a major shift in our electrical energy infrastructure, which will necessarily take a long time to effect, in part because there will be social impacts on any such major restructuring. As previously mentioned, this and a reasonable time frame for the development and extensive implementation of the many technologies involved within a properly engineered architecture is the second half of the 21^st century.

Restating this, aggressive implementation initiatives taken today are likely premature and have questionable motives. In the same way no one knows what the likes of transportation, communications, information processing, education, world government, health care, food production and urban development will look like in the same time frame. Effective changes in all of these will be an evolutionary process, not a revolutionary one. Electricity generation and distribution is as fundamental as these and the fervour being exhibited about revolutionizing it in a short time frame is simply misinformed.

An article in the April 2021 issue of Power Magazine, “The Smart Grid and Distributed Generation: Better Together” provides a good background on these issue. Amidst all the detail though, a few matters need emphasizing to properly provide a framework to make sense of this important infrastructure shift.

No one knows what the smart grid will ultimately look like, so there should be no early major investment in deploying technologies until this is better understood.
One of the primary functions of DG is to meet some level of local demand, not feed the grid.
We should not be distracted by discussions about the extensive implementations of concepts (e.g. utility-scale electricity storage, wide-spread impact of electric vehicles), which may only be realizable in the distant future.
Cyber security must be a major development initiative and this further emphasizes (1) the need to avoid overly hasty implementations and (2) the importance of the localized nature of the most likely smart grid architecture as opposed to grid-wide approaches.

[Editor’s note: For more commentary on the smart grid click on the Smart Grid sub-category under Policy Issues. The NERC report is recommended reading for a more complete understanding of the issues.]

The Smartest Grid In The Room: California Scheming Goes Awry

ttanton — Thu, 15 Jul 2010 06:00:43 +0000

Any reader lucky enough to have a new iPhone4 knows that sometimes technology just doesn’t work out the way sellers claim. Other times they do, but not in the way that consumers want or expect.

Such is the case with a major component of the so-called “smart grid”– the smart meter. There is growing agreement among federal and state policymakers, business leaders, and other key stakeholders, that a Smart Grid is not only needed but well within reach.

But it is not. Think of the Smart Grid as the 4G network for electricity. Smart meters, are a prime example of an unnecessary and expensive change that will provide little in the way of consumer benefit. They do, of course, provide utilities and energy marketers and government with a host of new tools, which is why they’re being sold in the policy arena. That plus the fact that makers just want the consumer to pay for something that isn’t (yet) cost effective explains the extracurricular (political) push. Add to all this the government’s insistence–encouraged by intermittent renewable developers lobbying efforts and billions in “stimulus” funding–and the momentum is hard to overcome.

The energy utilities want the meters to send price signals that change as generation costs change. By charging you more during high-usage “peak” times (e.g. hot days) they hope to persuade you to shift your usage to “off-peak” evenings and weekends, as many consumers now do with long-distance phone calls, when generation costs are lower. Of course, after a few days the inconvenience of getting off the couch every hour to read the new signal and turn on or off appliances, may lead people to the conclusion that the savings are not worth the effort. It might be smarter, and more effective to install additional generation capacity that can actually perform on those hot days.

Smart–Or Scary?

So far, the meters have struck fear in the hearts of consumers concerned about their privacy (not only do the meters send information to customers, they also transmit data on individual electric use back to the utility company); have already cost utility customers in California more than $2 billion; and are blamed for inexplicably higher, not lower, bills in California.

Some claim that just seeing the price information that smart meters can provide will motivate consumers to conserve – a hard argument to buy if you’ve heard the horror stories from Bakersfield, CA where consumers apparently have learned nothing from the new meters except to dread their electric bills, and to hate their utility.

Possibly the most fascinating aspect of the Smart Grid is the absence of an economic rationale. However, industry incentives being what they are (concentrated benefits, diffuse costs), many have bet on much of it being built. But guess what? People are finally starting to wonder if these smart meters are worth the trouble. Dissenters are turning up at state proceedings.

For a good sample of the issues and alternatives, look at Synapse Energy Economics’ July 8 filing at the New Jersey Board of Public Utilities, submitted on behalf of the state’s Department of the Public Advocate. Synapse is possibly the best firm in the business to represent efficiency or environmental interests, but they stand with the skeptics on smart grids.

The utilities have yet to make a case for the grids. Advanced Metering Infrastructure (AMI) by itself recovers only 50 to 80 percent of its costs if all it gets used for is automated reading, data transmission, and service turn offs. Getting a positive cost-benefit figure requires (real time) time-varying rates for small customers and ways they can either react to rate changes or give their utility the power to do it for them.

Messy Start

California is in the midst of distributing smart meters to everyone over the next few years, but it has already made certain that the necessary rate reforms and controls rate and controls won’t be there. First, the state just passed a law that prohibits any mandatory form of time-varying pricing, with bill protection, prior to 2013. Mandatory real-time pricing without bill protection has to wait until 2020. Utility-controllable thermostats (originally deemed necessary for a positive cost-benefit figure) were removed from the state’s regulatory options a year ago by public protests.

But let’s say that redesigned rates somehow become real-time pricing. Then the increase in consumer bills to pay for the meters should be counteracted by reductions due to peak shifting. The actual levels and persistence of these adjustments are far from clear. The purported evidence for responsiveness comes from controlled experiments in which self-selected consumers got all the hardware for free and were rewarded for their participation. Brattle calculates that a reasonable shaving of the peak under smart metering will save about $3 billion a year nationwide in avoided generator investment ($2.4 billion) and operation ($0.6 billion).

Relative to almost any dimension of the industry, this is a trifling figure. Edison Electric Institute says that total investment by corporate utilities amounted to $84.2 billion in 2008 not including the growing investment from independent power producers.

The smart grid’s promise only materializes after consumers get a bunch of their own equipment – flashy thermostats, premium-price appliances that can talk to the grid, controllers, assorted communications gear, etc. Those are necessary to avoid the get-up-off-the-couch-every-hour problem. Add a few hundred bucks of costs like these, multiply them over, say, 20 million homes and small commercial units, and the time lag towards full implementation becomes clear.

What Savings?

Pacific Gas & Electric is currently grappling with its ongoing smart grid rollout, hoping to eventually hook up millions of northern California consumers to smart meters. A small group of customers in Bakersfield has sued, saying that their bills skyrocketed right after their meters were installed. The plaintiff’s lawyers are trying to escalate the case by bringing in the meter maker, and the company that makes the communications chip. What’s going on? It will surely take a thorough investigation and lengthy case to find out.

PG&E, of course, said the case has “no merit” and, while it’s on the defensive, the company surely won’t help with public efforts to unravel the mystery. It’s not difficult to believe that such a new technology might have its hiccups, though.

Spying Eyes

Skyrocketing bills, off-the-charts energy usage, the complaints just keep flooding in following a CBS 5 investigation into Pacific Gas & Electric’s rollout of their new Smart Meters in the San Francisco Bay Area.

The new meter allows the utility to read your energy usage remotely, eliminating the need for meter readers. But what’s it doing for customers? Hundreds don’t like them. And now, there’s a growing rebellion from people who don’t want them. Mark Dieteman is taking a stand against PG&E’s new smart meters, putting his old meter under lock and key. “What I basically said to PG&E is: You’re not coming by to put this on my house, period.” And why? “To me it’s unconstitutional, it’s an invasion of my privacy,” he said. Because the new meters allow PG&E to remotely read a customer’s usage every hour. The company said in future, that will allow homeowners to monitor and reduce their energy use. Dieteman also said, “It permits PG&E to actually come into your home at any time during the day and know what appliances you are using. This is corporate intrusion on your life.” Patricia Young of Brentwood takes it a step further, calling it anti-American. “I am against it,” she said. “It’s an infringement on our rights and our liberties.” Overstatement? Maybe not, said attorney Lee Tien with the Electronic Frontier Foundation. “It’s really very clear, both under the Constitution, the 4th

Amendment, the privacy of the home is really the most important value,” Tien said.

And Tien said those meters could tell the government, even the police, what’s going on in your home. “Inside your home is where the government isn’t supposed to intrude without some kind of a warrant usually. And yet when this data is flowing freely outside your home, then the information gets outside that protected boundary and you start to have a problem.”

Which is why Dieteman said he won’t accept a Smart Meter. “This is where I take my stand. I do have a choice,” he said. But if you don’t want a Smart Meter, do you have to take one? Let’s go to the rule book: The Tariffs, approved by California’s Public Utilities Commission. The answer is in rule number 16: that “PG&E shall at all times have the right to enter…premises, for any purpose connected with the furnishing of electric service.”

And if you want to argue it, don’t forget rule number 11. If customers don’t comply, it said, “PG&E may terminate (their) gas and electric service.”

Letters from PG&E tell customers exactly that.

“They are threatening that if I don’t let them they are going to turn my gas and electric off regardless of the status of my bill, which is paid,” Young said.

“We haven’t seen an actual termination of service by the utility, but we have heard anecdotes,” said Matthew Freedman with consumer group TURN. And Freedman thinks it’s more than a threat. “If people tell PG&E they don’t want a Smart Meter, we expect that PG&E will try to ram it down their throats,” Freedman said. PG&E said that’s not true, that the utility wants to work with customers. The company declined to do an interview but told CBS 5 Investigates in a statement that regarding privacy, “Protecting our customers’ confidential information is a top priority” and that “The Public Utilities Commission provides very strict prohibitions on specific customer information being provided to third parties without the customer’s written consent.” But a Smart Meter at Mark Dieteman’s house? He said, “If they show up they are going to have to go through me to get at it. It will take a court order and a whole bunch of police officers. PG&E needs to be stopped in their tracks here.”

Not something that PG&E likely wants to hear. “That they have to force these meters onto people’s premises against their will, this has got to be an absolute nightmare for them,” Freedman said.

Job Stimulus?

As part of the economic recovery package passed last year, a significant amount of money was tagged for investing in the smart grid, from R&D to deployment. Overall, the ARRA has spent over $6.5 billion dollars on developing a smarter grid, with $380 million spent in California in addition to ratepayer funds.

The ARRA was supposed to be a job creator/saver, but at least with the smart meters remotely reading energy consumption, one entire class of workers—meter readers—have been put out of work, to the wrath of some unions. The Utility Workers Union of America Local 132 has sought CPUC help, charging Southern California Gas (SoCal Gas) with retaliation measures against union workers. SoCal Gas has withdrawn a proposal to create new jobs for its meter-reading workforce because of the union’s continued opposition to the utility’s advanced metering infrastructure case at the commission, the union said in a June 28 letter to CPUC President Michael Peevey.

The union opposed the utility’s application, which the commission approved in April, and sought a rehearing of that approval. In notices to its employees, SoCal Gas said it pulled its offer to create hundreds of new jobs for meter readers in a direct-assistance program because the union continued to oppose the AMI project. The union urged commissioners to look into the issue, complaining of a regulated utility threatening union workers with lost jobs in order to coerce the union to withdraw from a CPUC proceeding. Well, at least the lawyers are employed.

Separately PG&E is authorized to spend $1.7 billion of ratepayer funds on their advanced metering infrastructure. Other utilities in California are spending freely as well.

Implications

As with other aspects of California energy policy there is a vast difference between a (maybe) good idea and its implementation. California energy policy makers, and the special interests that feed on those policies, need to stay better focused on the needs and concerns of the consumer.

Rushing new technology into use for the purpose of rushing new technology to use is just that—rushing. Unnecessary costs are incurred and often good technologies get a black eye because they weren’t given the necessary time to debug. The smart meter roll out is one example of a continuing habit.

Smart Meter Chaos: Maryland PSC Gets Real (consumerism, anyone?)

rbradley — Fri, 25 Jun 2010 06:00:00 +0000

“The Proposal would not, in and of itself, enhance the electricity transmission grid or the Company’s distribution ‘backbone,’ and therefore it doesn’t justify the proposed customer surcharge by BG&E.”

- Public Service Commission of Maryland, IN THE MATTER OF THE APPLICATION BEFORE THE OF BALTIMORE GAS AND ELECTRIC COMPANY FOR AUTHORIZATION TO DEPLOY A SMART GRID INITIATIVE AND TO ESTABLISH A SURCHARGE FOR THE RECOVERY OF COST CASE NO. 9208 (June 22, 2010)

The smartest guys in the electricity room believe that a path to energy efficiency and environmental goodness is to hook up so-called smart meters for us little users. The smart machines would signal (jolt?) us to use less power in peak times when the price is high and to use power more when the price is low.

But the very concept has problems aplenty. First, time-of-use pricing for residentials (versus commercial and industrial customers) is a nice ‘green’ theory, not fact. Some states like California do not want or allow such residential pricing because of equity concerns.

Second, so-called smart meters are all about government (taxpayer) and class ratepayer subsidies, not stand-alone economics between willing buyers and sellers.

Third, there is the hassle factor (called transaction costs) of setting up appliances with time-of-day usage. Relatedly, (in)flexibility costs are incurred.

And last but not least, smart meters are intrusive. Big Environmental Brother lurks behind each smart meter to tell you what to do and when to do it. Civil libertarians take note of this government-dependent machine.

Smart meters as ENERGY POLICY appear to be penny-wise and pound foolish. But members of an eco-energy elite want to individually pay by the pound to impress the neighbors and save the world, let them be ‘early adopters’. And perhaps these special users should also pay the costs of utility manpower in setting up time-of-day pricing to leave nonusers whole. Such is life under public utility regulation.

Make no mistake: smart meters are not a ‘let-the-market decide’ proposition. If they were, utility customers could decide individually and on a stand-alone basis whether or not to buy and install the meters. This should be an individual demander-to-provider proposition without other ratepayers or taxpayers involvement.

One final point: the federal budget is in horrendous deficit. Smart-meter money earmarked for Maryland should not be redistributed by the Department of Energy to other states as planned. The monies should be axed from the budget, reducing the deficit on a dollar-for-dollar basis.

And by removing this component of the program, the broader Smart Grid investment concept, which has all the earmarks of a rate base perversity as explained by Robert Michaels, can be given a reality check as well.

From the PSCM Decision

“Although the Proposal boasts a “robust” Total Resource Cost (“TRC”) benefit-to-cost ratio of 3.2 (inclusive of DOE funding), a TRC ratio is only as useful as the assumptions on which it is based. On the projected cost side of the cost-benefit equation, the Company’s business case does not include many costs that are inherent in, or will inevitably flow from, the Proposal. It does not include the approximately $100 million in undepreciated value of existing, fully operational meters that would be retired before the end of their useful lives, for example, or the estimated $60 million it will cost the Company for the new billing system necessary to implement the R-SEP rate schedule. Nor does it include the cost of in-home display devices, which easily could exceed another $100 million dollars, or the cost of new customer appliances that the Company projects will one day be able to communicate with the proposed ‘smart meters.’ And it does not include the cost of retrofitting or replacing the emerging technology the Company proposes to install – technology that never has been tested in a full-scale deployment – in the event it becomes obsolete far earlier than its projected 10-to-15 year useful life.”

“[S]upply-side benefits … depend upon fundamental changes in residential customers’ energy use and the way most residential customers think about energy pricing, upon the operations of relatively new and difficult-to-predict energy and capacity markets, and upon the results of small-scale pilot programs that differed in important respects from the Proposal before us….. The nature and magnitude of the uncertainties underlying the Company’s business case raise serious doubts regarding whether the Proposal is, in fact, a cost-effective means of reducing consumption and peak demand of electricity in Maryland.”

“Although BGE claims that the assumptions underlying its business case are sound, the Company would have its customers bear all of the risk in the event those assumptions prove incorrect. We strongly support the overall goals of BGE’s Proposal, which are consistent with many of the energy efficiency, conservation, and demand response initiatives that we have approved previously, but we conclude that BGE ratepayers should not exclusively shoulder the burden in the event that costs associated with the Proposal are greater than expected, or that anticipated benefits do not materialize.”

“We … invite BGE to submit an alternative proposal that:

(1) foregoes any expectation of recovery by way of a tracker surcharge mechanism;

(2) provides a detailed business case that addresses the costs and benefits of proceeding without mandatory TOU pricing;

(3) includes a concrete and detailed plan for how BGE intends to educate its customers regarding its new proposed rate structure; and

(4) provides a workable methodology by which BGE will mitigate and more fairly allocate between the Company and its customers the risk that the proposal will not provide the benefits underlying BGE’s business case, or that it will cost significantly more than BGE currently projects.”

Appendix: Peter Behr, “Md.’s Veto of Advanced Meter Deployment Stuns Smart Grid Advocates,” E&E News, June 23, 2010.

A utility proposal to install smart meters throughout Maryland has been rejected by the state’s Public Service Commission, jeopardizing if not ending what had been one of the Obama administration’s leading investment commitments to smart grid technologies and consumer energy conservation.

The decision by Maryland’s PSC late Monday is a sharp rebuff to Baltimore Gas & Electric Co., the state’s largest utility and part of the Constellation Energy Group, in a state where politicians and power companies have feuded for years.

Officials of BG&E expressed shock at the decision by the Public Service Commission. They have sponsored one of the leading pilot programs incentivizing customers to conserve electricity by reducing appliance usage in peak demand periods, according to smart grid advocates.

BG&E’s current $835 million plan to install 1.36 million new “smart” electric meters and 730,000 advanced gas meters, with communication ties between customers and the utility, appears dead, BG&E said. The Energy Department pledged $200 million toward the BG&E program, most of which was ticketed for advanced meter installation. It was one of the top six state awards announced by DOE’s Smart Grid stimulus grant program last year.

“Quite frankly, we are very disappointed and quite surprised,” said Mark Case, BG&E’s senior vice president for strategy and regulatory affairs. “At this point, we are still trying to digest the commission’s order and make sense of [it].”

He added, “We actually do not see any clear path to move forward.”

The Energy Department and smart grid advocates expressed dismay at the decision. The National Association of Regulatory Utility Commissioners, through a spokesman, backed the Maryland commission’s action.

Regulators ‘frozen in time’?

Ahmad Faruqui, a consultant who has been a major contributor to federal government analyses of demand response programs, said the Maryland action — the first such state commission rejection of a smart grid project — reflects a pattern that seriously undermines smart grid and demand response goals.

While some state utility commissions are willing to back smart meter deployment, they are reluctant to approve new “dynamic” electricity rate plans that allow prices to rise during the day when power demand peaks and fall when demand is slack. Such real-time pricing plans are essential to prompt customers to shift energy usage to slack times and reduce overall consumption, he said.

“There is no doubt in my mind that without state commissions approving the business cases for advanced meters and the smart grid, this is not going anywhere. They control the dollars; they set the rates for the customers,” said Faruqui, an economist and principal with the Brattle Group. Faruqui testified before the Maryland commission in support of the BG&E plan and declined to comment on the commission’s decision in that case.

But he said that around the county, commissions are heeding warnings from state consumer advocates and retiree organizations about possible cost impacts on customers if electricity rates are linked to actual generation costs, hour by hour.

“Most of the state commissions are frozen in time. They are being subjected to these very, very pessimistic, worst-case arguments,” he said.

The Maryland commission’s ruling noted predictions by an AARP witness that up to 40 percent of low-income customers would see higher summer energy bills and up to 15 percent would see higher annual energy bills. Faruqui said Brattle’s research shows that around the country, lower-income customers would be affected least, because they typically do not have large central air conditioning systems and other high-demand appliances.

The Maryland commission said it would not approve an advanced meter plan that includes mandatory dynamic or “time of use” electricity rates.

A need for more outreach

“BG&E’s project was one of the more solid examples of how to quantify the consumer benefits of smart grid,” said Katherine Hamilton, president of the GridWise Alliance, an advocacy group supporting smart meter and smart grid strategies. “I think this means we have some work to do in outreach to the consumer and the state commissions,” she said. “Whatever gets approved [around the country] will have to be pretty simple. And you need to give low-income and fixed-income consumers the same opportunities to save power that tech-savvy people will have.”

BG&E proposed to replace 1.36 million electric meters and 730,000 gas meters for customers over three to five years, installing new advanced digital meters and a new communications network connecting the meters to the company’s control center. The estimated cost of the meter deployment was to be $486 million, $136 million of which was to be paid from DOE’s Smart Grid grants. The company said it anticipated $2.6 billion in benefits over 15 years, from conservation, lower prices, reduced capital expenditures for new power sources and other sources.

The utility proposed to create a customer Web portal that would allow customers to review hourly electricity usage from the previous day over the Internet. The commission criticized BG&E for not including in-home displays to alert people that power prices were rising.

To achieve savings, BG&E proposed to offer residential customers a “peak time rebate” from 2 p.m. to 7 p.m. on “critical” days declared by the company during heat waves when power supplies are stressed, and other emergencies called by the region’s grid operator. Customers would be notified the evening before and then could earn a rebate, initially $1.25 per kilowatt-hour, if they reduce their power consumption below a predetermined base case amount.

The utility also proposed to charge higher power prices between 2 p.m. and 7 p.m. during the summer months, and lower rates at all other times.

BG&E sought to recover the costs of the meter rollout as they are incurred through a “tracker” surcharge added to customers’ bills, rather than waiting to recover the costs in a traditional rate case proceeding.

AARP lobbies successfully in opposition

Although the staff of the PSC supported BG&E’s proposal with modifications, as did the Maryland Energy Administration, the commission sided with the Office of the People’s Counsel, a state consumer advocacy agency, and with AARP in challenging the case for smart meters and demand conservation by consumers.

BG&E asks ratepayers “to take significant financial and technological risks and adapt to categorical changes in rate designs, all in exchange for savings that are largely indirect, highly contingent and a long way off,” the commissioners said Monday. The commission singled out BG&E’s proposal to recover advance costs of the smart meter deployment through a surcharge on customers, calling it a “no-lose” proposition by the company.

“BG&E has provided no persuasive reason why its customers should subsidize this program in that manner.”

The commission noted BG&E’s testimony that the surcharge would raise the average electricity customer’s monthly rate by 38 cents beginning in 2010, rising to $3.78 in 2013.

James Connaughton, executive vice president of BG&E’s parent, Constellation, said that the Maryland commission’s stance may deter Constellation’s energy investment in the state. “I think the main and ongoing concern is a consistent pattern of wanting the utility to do really good work in Maryland, but making it very difficult to do so, including on economic grounds.

“There’s a suggestion that what was already a proposed bare-bones rate of return should be further diminished. We were prepared to put in $280 million of our shareholders’ money into advanced meter introduction. If we can’t earn a reasonable return, it forces of us to look for other, more productive ways to invest that money in clean energy, probably in other states.”

DOE may move funds to other states

DOE said that it was prepared to move on, too. “We are disappointed by the Maryland public utility commission’s decision. Smart grid programs hold the potential to give customers more choice, reduce operating costs, increase network reliability and improve the safety and security of the electrical grid,” said Matt Rogers, senior adviser to the secretary of Energy for Recovery Act implementation.

DOE’s preference is to work with BG&E and Maryland to try to get past this impasse, he said. “However, the Smart Grid program was significantly oversubscribed with great projects. If the Maryland public utility commission decision prevents BG&E from meeting their cost share requirements and implementing on time and on budget, we will have no choice but to explore moving the funds to other projects which have the backing of the state regulators.”

But DOE may have to contend with other state commissions unwilling to approve new consumer rate plans that allow rates to move up or down based on changing wholesale electricity prices during the day.

The Maryland commission took a fists-up stance toward its powers and prerogatives to rule on utility rates. “For one hundred years, since this Commission was created by the General Assembly in 1910, one of our primary functions has been to establish the rates that public service companies can charge their customers,” the commission said. Currently, it faces a growing trend by regulated companies to cover costs in advance through surcharges rather than subjecting costs to review after they have been incurred.

While it has approved such surcharges in some limited cases, it drew the line on BG&E’s current proposal, it said. “Surcharges guarantee dollar-for-dollar recovery of specific costs, diminish the Company’s incentive to control those costs,” and put those costs outside the commission’s reach, the commission said.

The Maryland commission’s decision was supported yesterday by Rob Thormeyer, communications director for NARUC. “If the agency believes the proposal is not in the best interest of their ratepayers, they will reject it or ask them to reconsider. From my reading of the order, that is exactly what Maryland did. They determined that BG&E’s proposal is clearly flawed, and they asked them to resubmit their plan to address their concerns. … BG&E and others in the smart-grid community should not be slamming the PSC; they should improve upon their proposal so it will not be, as the commission determined, detrimental to the state’s ratepayers.”

The Federal 'Green' Super Highway: 3,000 Miles to Nowhere? (Part II: Obama's power grab and high cost)

rpeltier — Wed, 23 Sep 2009 06:00:50 +0000

[Yesterday's post discussed how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and examined a case study about why it failed. Part II looks at Obama’s “green power” superhighway, the recent work by regional transmission planning organizations to bring renewable energy to market, and the extremely high costs to do so.]

Public policy has long supported the ability to construct new transmission lines that relieve congestion and reduce the cost of energy to consumers. However, it is another question entirely to construct a new “green” coast-to-coast transmission corridor given the mess our transmission system is in today and its prohibitive cost. Critics have complaint that it is throwing good (transmission) money at bad (renewable) generation money.

Slowly, regional system operators are resolving transmission bottlenecks and improving the smooth flow of energy in their service territories. The good news is that virtually all of the most important regional projects are likely to be in-service well before our Washington representatives will complete their transmission siting authority “power grab” (not that it will change their game plan). Also, regional transmission planning organizations are actively promoting and siting transmission lines. The regional system is working and they don’t need FERC or congress to help to fix it.

The local siting processes are working (regardless of how you feel about siting renewables-only transmission lines) but the costs for constructing this transmission is extremely expensive per unit of energy generated given the periodicity of the output from wind and solar power plants. Costs of constructing new transmission for renewable projects can easily equal a quarter of the cost of building the power plant alone. In ERCOT, the price is over $2 million per mile to bring renewable energy into the existing grid and will add at least 5 cents/kWh for the transmission portion of the cost of renewable electricity alone—more than double the cost of electricity from our existing fleet of nuclear power plants and 60% more than the cost of coal-fired electricity at the busbar. The Western Interconnect planning process is currently identifying likely renewable sites and looking at transmission line corridors.

FERC: Try, Try Again

In Part I we discussed how federal siting authority of new transmission lines was granted under the Energy Policy Act of 2005 (EPAct) yet FERC’s implementation of that authority failed judicial scrutiny. In addition, the case study presented concerning adding an interconnection between Southern California and Arizona clearly shows that there are many other issues that must be considered when establishing the need for FERC to intercede on behalf of one state or another. In my mind, the most significant issue, and the Arizona Corporation Commission agrees, is that a state must completely exercise their ability to construct local power generation facilities before attempting to cross connect to an adjacent state. Merely needing the power is no reason for the federal government to exercise its eminent domain powers when there is an unwillingness to construct new plants.

Today, we now hear the next stanza to this same tired tune. We continue to be told that a complete overhaul of the U.S. power delivery system is required but now the grid updates must also accommodate the higher levels of renewable energy expected to be generated over the next decade. Senator Harry Reid (D-NV) gave us a look at our future when, at a conference in February hosted by the Center for American Progress Action Fund, a group organized by John Podesta, proclaimed, “My legislation (referring to another round of legislation he promised to introduce that will speed approvals of transmission lines) will require the president to designate renewable energy zones with significant clean energy-generating potential.” Reid went on to explain that the federal government should be given the authority, through FERC, to overrule state and local governments that slow the development of Obama’s promised 3,000 miles of new interstate transmission lines.

The proposed legislation would also provide FERC the power of eminent domain should states be unwilling to yield to the inevitable pressure from Washington to approve the plans. “We cannot let 231 state regulators hold up progress,” Reid said. “They should be given every opportunity to see if we can work this out through the state regulators. If that can’t be done I think there are very few alternatives for the American people,” other than eminent domain. But any delays or obstacles would be quickly settled, Reid said. “Whatever we pass at the federal level trumps all that,” he said.

John Podesta, president of the Center for American Progress, said a stronger federal siting authority is needed, given that the 4th U.S. Circuit Court of Appeals ruled that FERC’s interpretation of its backstop siting authority under the 2005 energy bill was too expansive.

“It’s time to get back to the table and find a way so that states and regions can plan for the transmission that they need but that the federal government has a role to play to make sure that gets done,” Podesta said.

Reid has yet to provide any details of his proposed bill but a legislative aid said the bill would contain four main components: an interregional planning component, federal siting authority, a national cost allocation plan and a requirement that any generation that connects to the grid meet “green” standards. The four parts appear very similar to a plan produced by the Energy Future Coalition and the Center for American Progress.

Thankfully, Reid’s proposed legislation has yet to see the light of day given the extraordinary costs involved with constructing new national interstate transmission lines. For example, grid operators in the eastern half of the U.S. earlier released in August a study estimating that more than $80 billion in new transmission infrastructure would be needed to get 20% percent of the region’s electricity from wind generation by 2024.

Does Siting need Fixing?

The Federal Energy Regulatory Commission (FERC) recognizes the challenges posed by bringing electrons from new and disparately located renewable energy sources to population centers. In late May, FERC announced a series of transmission planning meetings that will focus on “wider integration of regional energy resources into the nation’s power grid.” In essence, renewable energy generation, principally wind energy, is located where the transmission infrastructure does not exist, and other distributed energy resources are located in transmission-constrained regions.

According to FERC Chairman Jon Wellinghoff, “Planning is one of the three legs on the transmission policy stool—the others are siting and cost allocation—and all are crucial to meeting the goals of assimilating demand resources, renewable energy and distributed generation into the grid for the benefit of consumers.” Here we go again.

From Market Pull to Product Push

Historically, electric utilities dictated when, where, and how much new generation would be added. Their integrated resource plans (IRP) determined the timing of plant additions, the fuel sources, and the location of the new generation resources. Transmission planners followed the lead of utilities to route the necessary transmission capacity while also seeking to lessen area congestion, if necessary. Traditionally, new power generation resources—and, by extension, new transmission—responded to a market pull: predicted load demand. The role of the state and local governments was oversight, providing access to transmission, and setting rates.

In contrast, renewable mandates have upended the traditional approach to developing an IRP. Rather than anticipated customer demand driving generation and transmission decisions, government mandates are now in the driver’s seat. Twenty-nine states and the District of Columbia have a renewable portfolio standard that requires utilities in those states to supply some percentage of renewable electricity by a date certain.

For instance, the California Public Utility Commission requires that 33% of that state’s power originate from renewable energy sources by 2020. In order to achieve this extraordinary goal, all new power generation procured by the state’s utilities must come from renewable energy sources. In this new world, the “pull” of market demand has been supplanted by a government-mandated “technology push” that determines which renewable developers pushing new power into the system in response to state-mandated levels of renewable power have access to limited transmission infrastructure.

One of the other challenges to building new transmission capacity to move renewable energy long distances that was discussed by Wellinghoff is identifying acceptable siting locations for renewable energy facilities. In spite of FERC’s interest is being part of that decision process, much progress has been made at the local level that makes FERC irrelevant in siting transmission lines in practice.

Transmission Planning Out West

One important initiative toward this goal in the Western Interconnection is the Western Governor’s Association’s (WGA) Western Renewable Energy Zones (WREZ) study. In the WREZ study—which covers 11 western states, two Canadian provinces, and areas of Mexico that are part of the Western Interconnection—as many as 50 zones with substantial renewable resources are in the process of being identified so that renewable projects can be expedited and transmission projects can be planned in advance.

The ultimate goal of the WGA is to “develop 30,000 MW of clean and diversified energy by 2015.” The approach used by WGA is to first identify regions with high potential for generating renewable energy—solar, wind, geothermal, etc by involving all the relevant stakeholders. The results of these studies in turn drive transmission planning.

The most recent draft map from the Western Governor’s Association illustrates Qualified Resource Areas as those areas with a high density of developable renewable energy resources after screening for known technical and environmental limitations for which data are available. These data will be used to determine Western Renewable Energy Zones (WREZ) in the Western Interconnection.

The state with the largest installed wind power capacity has already identified Competitive Renewable Energy Zones (CREZ) within the ERCOT Interconnection. In March, the Texas PUC assigned approximately $5 billion of transmission projects to be constructed in these CREZ that will eventually transmit 18,456 MW of wind power over more than 2,300 miles of new transmission lines from power-heavy West Texas and the Panhandle to highly populated metropolitan areas of the state. To put the magnitude of these numbers into perspective, the cost of transmission is over $2,000,000 per mile or over $270/kW of installed capacity.

The regulatory body expects that the new lines will be in service within four or five years. The Texas PUC took about three years to select the most productive wind zones in the state, designate them as CREZ, and devise a transmission plan to move power generated from those zones to various populated areas in the state. Many of these new transmission projects will begin construction later this year.

As an aside, T. Boone Pickens’ investment in his now delayed plan to build 1,000 MW of wind power in the Texas panhandle is in jeopardy. The ERCOT transmission plans do not extend the wires far enough into the Panhandle to reach Pickens’ projects. Pickens now has 687 wind turbines available that cost him a cool $2 billion that he hopes to recycle on a number of smaller projects in the U.S. and Canada. That’s a lot of wind turbines.

The Cost of New Transmission Is Substantial

More insidious are unpredictable transmission costs. Power sellers, buyers, and investors adamantly want price certainty in the total delivered cost. However, congestion charges can make the delivered price vary, especially in locational marginal pricing.

Everyone wants to know the answer to the question: What is the added premium to deliver renewable energy? Many transmission networks have both fossil fuel and renewable generators sharing the same network. Certainly, intermittent renewable sources have higher system-integration costs. Load balancing is more involved as well.

A recent Lawrence Berkeley National Laboratory study may provide an early answer to the cost question. Lawrence Berkeley National Laboratory (LBNL) recently issued a research report that examines the expected costs for new transmission infrastructure that would be needed to support an accelerated program for renewable energy projects, particularly wind energy. The report, “The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies” was released in February 2009. (A copy of the report can be downloaded at http://eetd.lbl.gov/ea/ems/reports/lbnl-1471e.pdf.)

The authors’ objectives in preparing this report were threefold: to define the transmission costs for a rapidly growing wind power industry, to discuss different transmission planning approaches, and to examine the models used to estimate future wind deployment. Our interest is this article is to focus on the transmission cost estimates prepared by LBNL.

The cost estimates are based on a review of 40 transmission planning studies completed between 2001 and 2008 by various developers, independent system operators/regional transmission operators, state agencies, and individual utilities. There is a wide range in transmission costs, although the costs are generally less than $500/kW. The cost of the median study scenario was $300/kW, or about 15% to 23% of the typical installed cost of a wind turbine plant. These numbers are quite consistent with the $270/kW from ERCOT discussed above.

The authors also concluded that variation in the study methodologies used in these 40 transmission siting studies and the characteristics of the specific grid may affect transmission installation costs (see table). Depending on the original purpose of the transmission line under study (whether it was congestion or deliverability focused), the authors concluded that the purpose affected the costs of adding wind energy to the mix.

Estimated Installed Cost of Wind Transmission Based on Three Higher-Level Studies of Wind Transmission. Source: LBNL

Study

Wind Capacity

Unit Cost of Transmission for Wind Power

10% Wind Energy by 2030: AEP 765 kV Overlay Study

200-400 GW

$150-$300/kW

20% Wind Energy by 2030: Wind Deployment System

290 GW

$207/kW

Annual Energy Outlook 2008 Projections for 2030: National Energy Modeling System

40 GW

$450/kW consisting of $316/kW for transmission and $133/kW for “long-term” multipliers

The study also reviewed three high-level wind transmission–only studies, as shown in the table above. These costs are generally consistent with the median cost identified in the original study sample of $500/kW, or about 25% of the $2,000/kW cost of constructing a new wind project.

The study also concluded that the historic cost of transmission was in the range of $35/MWh to $79/MWh with an average of $45/MWh. Using reasonable economic assumptions on the ERCOT transmission projects and a 33% capacity factor, the transmission lines add about $50/MWh to the price of power generated by the wind projects. For perspective, existing nuclear plants as an industry deliver power to the grid at less than $20/MWh and coal plants are in the range of $30 MWh.

Another Approach: Requiring Backup Power

Nevertheless, renewables do add additional costs to the whole system. For instance, speedy ramp-up of backup power is essential when a wind farm goes down with as little as one-hour warning. Reliability issues kick in as well.

For example, an ERCOT report concluded that only 8.7% of historic wind generation was produced during peak power hours limiting its effectiveness in trimming system peak demand.

Someplace in the delivery chain this intermittency of energy production versus load demand must be smoothed out. Utilities traditionally have taken on this burden themselves. Typically, a utility backfills wind/solar gaps with gas-fired plants to make up for any shortfall in energy production based on a number of factors, including the season, weather, and the region’s operating experience. Using the same approach with very remote wind and solar farms isn’t as straightforward. To do so would make the entire long-distance energy delivery chain, in effect, run intermittently—if the remediating, balancing measures are not applied.

A more recent procurement practice is for the electric utility to insist that the renewable producer directly supply steady, baseload-style power. In particular the utility expects the renewable power producer to have its own storage or natural gas backups. An example would be Xcel Energy’s April 2009 request for proposal for 600 MW of solar thermal that is “fortified” in this way.

Conclusion

Central planning based on temporary political majorities–or, dare one say, ‘political whim’–is not a viable long-term electricity policy. Free-market incentives to expand and build are preferable, and do not expect a 3,000-mile ‘green’ superhighway as a result.

— Also contributing to this article was Sonal Patel, POWER senior writer, and Martin Piszczalski (Ph.D), an industry analyst with Sextant Research

The Federal “Green” Superhighway: 3,000 Miles to Nowhere? (Part II: Obama’s power grab, high cost)

rpeltier — Wed, 23 Sep 2009 06:00:50 +0000

[Yesterday's post discussed how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and examined a case study about why it failed. Part II looks at Obama’s “green power” superhighway, the recent work by regional transmission planning organizations to bring renewable energy to market, and the extremely high costs to do so.]

The local siting processes are working (regardless of how you feel about siting renewables-only transmission lines) but the costs for constructing this transmission is extremely expensive per unit of energy generated given the periodicity of the output from wind and solar power installations. Costs of constructing new transmission for renewable projects can easily equal a quarter of the cost of building the generation alone. In ERCOT, the price is over $2 million per mile to bring renewable energy into the existing grid and will add at least 5 cents/kWh for the transmission portion of the cost of renewable electricity alone—more than double the cost of electricity from our existing fleet of nuclear power plants and 60% more than the cost of coal-fired electricity at the busbar. The Western Interconnect planning process is currently identifying likely renewable sites and looking at transmission line corridors.

FERC: Try, Try Again

Does Siting need Fixing?

From Market Pull to Product Push

Transmission Planning Out West

The Cost of New Transmission Is Substantial

Estimated Installed Cost of Wind Transmission Based on Three Higher-Level Studies of Wind Transmission. Source: LBNL

Study

Wind Capacity; Unit Cost of Transmission for Wind Power; 10% Wind Energy by 2030 (AEP 765 kV Overlay Study)

200-400 GW @ $150-$300/kW

20% Wind Energy by 2030: Wind Deployment System

290 GW @ $207/kW

Annual Energy Outlook 2008 Projections for 2030: National Energy Modeling System

40 GW @ $450/kW consisting of $316/kW for transmission and $133/kW for “long-term” multipliers

Another Approach: Requiring Backup Power

For example, an ERCOT report concluded that only 8.7% of historic wind generation was produced during peak power hours limiting its effectiveness in trimming system peak demand.

Conclusion

— Also contributing to this article was Sonal Patel, POWER senior writer, and Martin Piszczalski (Ph.D), an industry analyst with Sextant Research

The Federal 'Green' Superhighway: 3,000 Miles to Nowhere? (Part I: siting politics and state wealth transfers)

rpeltier — Tue, 22 Sep 2009 06:00:13 +0000

Investment in interstate transmission has not kept pace with the need for more electricity capacity, despite wakeup calls such as the widespread Northeast and Midwest blackout in August 2003. Transmission siting authority has become the mantra for those who claim that the “not in my backyard” (NIMBY) syndrome is driving U.S. energy policy. FERC was given the opportunity to flex their national siting authority muscle with passage of the Energy Policy Act of 2005 (EPAct), but their game plan failed to pass court scrutiny. Today, siting new transmission remains a state’s rights issue as it has always been.

Transmission siting controversies are increasing given the growing number of renewable energy projects that want to interconnect with scarce transmission capacity. Now, another layer of complexity is in play due to the potential of a national renewable portfolio standard that portends hundreds if not thousands of new renewable projects that will all seek priority for grid access.

There are new renewable projects in development today that are already in the queue waiting for transmission capacity on existing lines or the construction of new lines because of the prohibitive costs of transmission upgrades. Other projects are so remote that only a purpose-built transmission line can bring the energy to market.

Adding uncertainty to uncertainty, Congressional leaders have proposed constructing new transmission lines dedicated to moving only renewable energy coast-to-coast whereby state’s rights will be of secondary importance. Regardless, ratepayers will end up paying the tens of billions of dollars for these new lines and further driving up the cost of electricity.

Below, we discuss how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and provide a case study on the reasons for failure. Part II (tomorrow) will look at the latest rendition of the siting authority power grab: Obama’s promise of a 3,000 mile coast-to-coast “green power” superhighway. We’ll also discuss the recent work by regional transmission planning organizations to bring renewable energy to market and the costs to do so. It won’t come as a surprise that the costs are extremely high.

New Transmission Sites May Take Years

Siting new transmission lines is an exercise in patience and endurance. The industry has plenty of war stories about state, county or local authorities being unable or unwilling to approve new transmission projects, especially projects that merely transit through a state to get energy to an out-of-state market. One of the long running and always contentious debates is the resistance of Connecticut residents to allow transmission of electricity generated upstate to pass that power through to New York City.

One of the most egregious examples of how a project can become a career in my memory is AEP’s Wyoming-Jackson Ferry line completed in 2006—16 years after the project’s launch, 14 of which were spent wrangling over siting.

Another example; a plan hatched in the late 1980s to move surplus power from coal power-rich West Virginia to power-short New Jersey and New York crashed in the early 1990s due to the opposition of Pennsylvania. Delegates from the Keystone State asked, appropriately, “What’s in it for us?” The answer: “Not much.” Pennsylvania responded, “No thanks.” End of project, after nearly a decade of contention.

Congress has made numerous attempts to reduce these delays and shorten the time required to add new transmission capacity where it is most needed. And each time the new laws have failed miserably.

The most recent attempt was provisions in EPAct that gave FERC the authority to override state and local opposition to the construction of interstate transmission lines if the agency determines that they will reduce system congestion. In April 2007, the Department of Energy designated two regions that qualify for such treatment as “national interest electric transmission corridors.” One covers a broad territory stretching from Maryland to New York and as far west as Ohio. The other includes a large chunk of southern California, southern Nevada (including Las Vegas), and parts of Arizona all the way to Phoenix.

In announcing FERC’s plan at the time, then-Energy Secretary Samuel Bodman said, “The parochial interests that shaped energy policy in the 20th century will no longer work.” Maybe so, but instead of serving the “national interest,” the proposed corridors look a lot like a lot of poaching routes to me. Their result was said to enable regions that have resisted building generation locally—in hopes of buying cheaper power from other regions—to avoid paying the full costs of “their” power. The problem with this plan is that it saddles out-of-state generating regions with the environmental and lost-resources costs and consequences.

California Dreamin’

The Sunrise Powerlink is certainly the most ambitious project developed by San Diego Gas & Electric (SDG&E) in many years. The recently approved project is running a new 150-mile transmission line east from San Diego into the deserts. SDG&E claims the link will spur development of renewables (geothermal and solar), lower transmission system congestion costs, and “reduce subsidies paid to local, aging power plants that are more expensive to operate.”

The second and third justifications are closely related and often given short shrift by the media. In the report backing its national corridor designations, the DOE states that one of the biggest reasons it considers the southern California grid “troubled” is the high cost of running those old plants in California—typically gas-fired units in urban areas. No surprise: SDG&E hasn’t built a new power plant in its service territory in more than 30 years.

In the interest of full disclosure, I worked on the design and construction of SDG&E’s last major power plant project Encina Unit 5 when it was constructed in 1976-78. I was also present when then-CEO Tom Page announced in 1978 that SDG&E was not going to construct any more plants but would become a “wires” company and in the future import energy from other sources rather than construct any new plants. To do so was a pure business decision made at the time given the resistance of local governments and citizens to building any more power plants. This business plan was a conscious decision to avoid building local generation and rely solely on imported energy to cover load growth. To their credit, the plan has worked for over 30 years, but now Arizona has the surplus power capacity and a growing population and is unwilling to share their electricity resources. This is a game changer for Southern California.

Buddy, Can You Spare a Megawatt?

I recently drove my 4WD truck to the top of a small mountain just south of the Palo Verde Nuclear Generating Station in Arizona, about 100 miles from the California border. The power park view warms a power engineer’s heart: The three-unit 3,739-MW nuke lies to the north, and to the south sit Sempra’s 1,250-MW Mesquite Generating Station, Pinnacle West Energy’s 1,136-MW Redhawk Power Plant, and LS Power’s 713-MW Arlington Valley Energy Facility. Travel over the next hill and south a few miles and you’ll find the 2,400-MW Panda Gila River Project. All but Palo Verde are gas-fired combined-cycle plants.

I’d venture that a big chunk of the more than 9,200 MW is just aching to find a path into Southern California. Why? The average retail electricity price is almost 50% higher there than in Arizona: 15 cents/kWh vs. 8.5 cents/kWh. Finding new customers willing to pay more for the same commodity would be a business coup for the plants’ owners. The only hurdle would be permitting the new lines needed to deliver it. But the Arizona Corporation Commission (ACC) has a different vision of how that power will be used—generate it in Arizona, use it in Arizona.

To its credit, the ACC saw through the “master plan” scheme and unanimously voted down a Southern California Edison (SCE) proposal to build a 231-mile transmission line to connect the power park to a substation near Palm Springs (and ultimately to the Sunrise Powerlink and points west). SCE execs argued that the link would “increase the state’s ability to transmit energy.” What they really meant was the ability to transmit energy to Southern California. Bill Mundell, an Arizona energy commissioner, explained the rejection succinctly at the time: “I don’t want Arizona to be the energy farm for California.” Commissioner Kris Mayes added, “You [SCE] are trying to drop a giant extension cord into Arizona.”

The final meeting on the project turned a bit testy when commissioners quizzed Dian Grueneich of the California Public Utilities Commission about her state’s recent lack of progress building new power plants and transmission lines. Mundell asked, “Why should Arizona put its natural resources, environment, and future energy supply on the line while California does relatively little?”

That’s indeed what California is asking Arizona to do, in an updated version of Aesop’s fable of the grasshopper and the ant. And that’s precisely why the entire national interest corridors program will face challenges from power “donor states.” In California’s case, taxing that nasty coal-fired power coming into the state up north and strong-arming its neighbor to the east for a bigger slice of existing gas-fired capacity is an energy plan doomed to failure. Nevada, keep an eye on these guys.

New Developments

Unable to convince Arizona’s utility commissioners to approve the new power line, the California utilities did just as was expected: ask FERC to step in and exercise some of that authority vested in them by EPAct to make Arizona plug in their extension line. FERC tried to mediate the disagreement with no success and subsequently developed an order forcing Arizona to agree to the interconnection. The inevitable federal court case resulted.

In February 2009, a federal appeals court slapped FERC’s hand for overreaching the authority granted to the agency by EPAct when it took an “expansive interpretation” of the law in asserting its power to override state decisions.

The U.S. Fourth Circuit Court of Appeals in Richmond, Va., issued its decision in a case brought against the regulatory commission by the Piedmont Environmental Council and multiple states and parties—including the New York Public Service Commission (PSC) and the Minnesota Public Utilities Commission (PUC).

At the heart of the matter was the authority granted by EPAct, which allowed the commission to approve interstate power lines after the affected state had “withheld approval for more than a year.” But in an issuance of a final November 2006 rule, FERC substantively interpreted the phrase, “withheld approval for more than one year” to include a state’s denial of a permit within the one-year statutory timeframe.

The petitioners had filed requests for rehearing on FERC’s final rule, arguing that the agency had erred in its interpretation. The parties also asked the court to review several rulemaking decisions FERC had made with the application of that interpretation.

“FERC’s interpretation is contrary to the plain meaning of the statute,” wrote Judge Blane Michael for the majority. “Simply put, the statute does not give FERC permitting authority when a state has affirmatively denied a permit application within a one-year deadline.”

Michael said that FERC’s standing interpretation would mean that state commissions would lose jurisdiction unless they approved every permit application in a national interest corridor. “Under such a reading it would be futile for a state commission to deny a permit based on traditional considerations like cost and benefit, land use and environmental impacts, and health and safety. It would be futile, in other words, for a commission to do its normal work,” he wrote.

The court’s decision now sets hurdles for FERC-approved projects whose public commissions have issued denials but that hasn’t slowed down the pressure to overhaul (again) the provision of the EPAct failed to pass judicial scrutiny.

In essence, FERC powers granted under EPAct were neutralized by the appeals court’s decision and Arizona’s rejection of the construction of a new transmission line stands.

But, this court decision doesn’t bring an end to the push for federalizing transmission siting authority. Far from it. The next page of the game plan uses the supposed need for a “green” coast-to-coast transmission superhighway as cover for nationalizing all future transmission siting decisions.

— Also contributing to this article was Sonal Patel, POWER senior writer

Smart Grid or Strong Grid? Comment on Ken Maize

rmichaels — Wed, 08 Jul 2009 06:00:02 +0000

Ken Maize’s recent post arguing for a strong grid instead of a smart one made an important point: the Smart Grid is largely an assortment of tweaks and minor fixes that lets America’s utilities get by with the transmission status quo to cope with the growing demand and integration of intermittent renewables.

Policy should instead aim at a strong grid. Redundancies and “excess” capacity could better maintain reliability and lower delivered power costs in a world of monopoly utilities. It would also facilitate market transactions if competitive retail and wholesale power markets prevail.

Maize has well-founded concerns about how utilities in a smart-grid world will

1) administer their new gizmo-heavy systems;

2) justify the benefits that small consumers will get in return for higher bills, and

3) make up for the prospect for increased vulnerability to innocent or serious hacking.

Rate Base Aplenty

Unfortunately, the Smart Grid has one great upside for utilities. If politics force them to invest less in generation (what they should be doing), they will need to plug a hole in their rate bases, i.e. the assets on which they can earn regulated returns with near-certainty. The Smart Grid does just this; its sheer size will require lots of costly meters, communications hardware and software, equipment to process the information produced, and still more investments to dispatch generation and manage demand on the basis of that information. The full cost also includes stuff on the consumers side of the meter, some of which utilities are also likely to supply.

The best part for utilities is that there is no logical ceiling on what they can spend. Build enough capacity to reliably meet load growth and you have no reason to build any more. But with the smart grid, there’s always something you can buy or someone you can hire to squeeze just a little more savings out of the system.

The Smart Grid story is akin to the nuclear delays and overruns of the 1980s. The politics were similar, stemming from overblown concerns about fossil- fuel exhaustion and the environmental effects of combustion, supplemented by a mix of legitimate environmental concerns and fraudulent posturing.

Then it was nuclear, and now it’s renewables that promise clean and soon-to-be-inexpensive power. Both the past and present crises would mobilize the public to conservation, with what power people still needed would come from the new technologies.

Just imagine: Turning the lights off when you leave the room will morph into fiddling with a computer display of hourly power prices and the kwh your appliances are currently expending. In case your life lacks meaning, the California Public Utilities Commission has already announced that it wants energy efficiency to become “a way of life.”

Nuclear Redux?

Like nuclear power at launch, a “successful” Smart Grid will require investment in untested technologies on a massive scale. The GridWise alliance of smart suppliers and utilities echoes the early standardized “turnkey” nuclear plants. They were loss leaders for General Electric and Westinghouse that produced a mass of commitments from utilities that insisted on customizing their plants and handling their own construction. Customization, incompetence and random events drove nuclear costs to unheard-of levels, but utilities had little to fear as long as the politics were with them. Only after Three Mile Island changed the public’s risk perceptions would some state commissions begin assessing penalties for cost overruns in nuclear construction that had little to do with safety.

In contrast to the case of nuclear power, however, there is no obvious event that will trigger a change in the regulatory climate to one of distrusting the Smart Grid—short of a major blackout that can be so linked. But should regulatory conditions change, Smart Grid hardware just might become the next generation of “stranded costs” to be picked up by ratepayers.

Does the "Smart Grid" Have a Smartest-Guys-in-the-Room Problem?

kmaize — Fri, 19 Jun 2009 06:00:52 +0000

[Editor note: Ken Maize, a long-time energy analyst, joins MasterResource for the first time (see his bio at the end of this post). A MR previous post by Robert Michaels has questioned 'smart metering,' part of the 'smart grid' concept]

However politically incorrect my conclusion, I’m convinced that the “smart grid” is not smart and even dumb. It diverts attention from what is a more important objective–a strong grid. And it politicizes in the very area where we need more consumer-driven, free-market incentives.

Following the Northeast grid collapse of 2003, the Electric Power Research Institute (EPRI) popped out the smart grid concept, largely the brainchild of then EPRI’s CEO Kurt Yeager. The blueprint was for an interconnected intelligent network reaching from the generating station to your toaster, able to talk up-and-down the line, matching supply and demand seamlessly.

Sounds cool, but doesn’t stand up to analysis in my judgment.

Where Did ‘Smart Grid’ Come From?

The idea of a smart grid has been laying around in bits and pieces for many years. I recall visiting Southern California Edison (SEC) in the 1980s where a group of us energy reporters visited the utility’s “smart house.” It kinda reminded me of the Betty Furness advertisements for Westinghouse kitchens when I grew up in Pittsburgh in the 1950s and 1960s. SCE assured us that the smart house, connected to the utility over phone lines (this was pre-World Wide Web) and through radio signals, would dominate home construction in the coming years. (Enron would have a ‘smart house’ a decade later to awe visitors to 1400 Smith Street in Houston, but that’s another story.)

Didn’t happen, for lots of reasons, most of them good. It didn’t make economic sense for consumers (although it did for the utility — remember all-electric “gold medallion” homes?). It was way too technologically optimistic, assuming communications protocols that really didn’t exist, and appliances that weren’t remotely ready to talk to each other and the utility. Heck, this was largely before cell phones were making a big impact in the market.

Fast forward to the 21st Century. The grid has shown that it is in trouble. The Internet has demonstrated the utility of Vint Cerf’s IP communications protocol. EPRI is facing an existential moment (what the heck is our role here?). Presto! The smart grid. It controls power flows, adjusts supply demand on the fly, instantly corrects for frequency and power imbalances. It slices, it dices, it’s the latest, biggest, best Ronco product of all time. We can get Billy Mays (no relation, he spells it differently) to peddle it on late-night cable.

Rescuing Dumb Renewables

The concept of the smart grid (if not the reality) also fits into the allegedly new paradigm of renewables. We want lots of power from the wind and the sun (water doesn’t count). But the places where the winds blows a lot and the sun shines a lot are a long way away from where there are a lot of people.

Hence proposals to build a transcontinental, high-voltage (AC and DC) backbone grid on top of the existing transmission and distribution network (which former energy secretary Bill Richardson famously and erroneously called a “third world” grid following the 2003 grid collapse). What’s a trillion dollars or so to bring unreliable power to market?

So here is the Big Green Grid Dream: tie renewables to consumers, with a smart grid to govern (Big Brother?) usage. We could imbue the entire grid — high-voltage transmission and lower-voltage distribution with smarts, from the generator to the substation to the refrigerator. It’s the Big Rock Candy Mountain–or Dream Green Machine.

Another Problem: Cybersecurity

Another problem with the concept of a smart grid (which most advocates assume will use IP/TCP communications protocols) is cybersecurity. It’s hard to bring down a dumb but strong grid in a cyber attack. The smarter it is, the more vulnerable it becomes. There was a report in the Wall Street Journal not long ago that hackers from China and Russia had successfully penetrated the U.S.”grid,” which was undefined in the article.

I don’t believe it, and no other mainstream media outlet backed up the story. But the “smarter” the grid becomes, the more likely such hacking becomes. That’s a real problem.

The Legacy Problem

The U.S. transmission grid (and I’m talking about the big pipes — 365 kV and above) has clear weaknesses. We don’t have a U.S. grid, but loosely-interconnected regional grids. East and West don’t meet very easily. Texas is an island unto itself. Florida is aspiring to the same. Without strong physical interconnections, it’s impossible to dispatch and control a national grid. So a lot of “smart grid” is putting the cart before the horse.

Color Me Skeptical

I don’t buy any part of it, and it ain’t going to happen. It’s what I have described elsewhere as lemon-meringue pie-in-the-sky. Among other problems, the costs are simply unknown, and who will bear them is also unknown. Most of what I’ve seen implicitly suggests that taxpayers will get the check, since customers would revolt if the costs showed up on their monthly bills.

I’ve tuned into recent FERC discussions about grid issues, and heard what I think is a lot of nonsense about smart grids. I’d rather our regulators and policy makers were focusing on muscle, not brains. It’s heavy lifting we need, not heavy thinking.

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Ken Maize is executive editor of MANAGING POWER magazine and editor of POWER Blog. He was the founder and editor of Electricity Daily (1993-2006) and a reporter and editor at The Energy Daily for a dozen years, starting on March 28, 1979, the date of the Three Mile Island problem. Contact address: kmaize@hughes.net.

Smart Grid: Can 'Smart Metering' Overcome the Hassle Factor? (transaction costs matter too)

rmichaels — Fri, 29 May 2009 06:00:51 +0000

When asked for conjectures about the Smart Grid, economists’ imaginations become almost indecently fertile. Writing in her blog, market-friendly Lynne Kiesling sees astounding dividends from real-time pricing and smart grid technology, preferably with competitive retail service.

Say, for example, you are on the train to work, and you get a SMS [ text message] notification that due to unexpected weather, there will be a higher-than-normal electricity price in the 9:00-10:00 hour. You may have already programmed your devices to respond to price signals, but what if the price is high enough that you want to change your settings? You can log in to your HAN [Home Area Network] from your mobile device, or from your computer at work, and change the device settings in the home through the web portal. … [i]f the home has e.g. solar PV panels the customer can program the network to reduce electricity use once the home’s consumption reaches the generation capacity of the solar resource.

But what is wrong with this picture?

Start with a seemingly unrelated question: why do department stores have sales? It’s not overstocking – this gets handled by price markdowns in the ordinary course of business. Instead think of how sales are actually staged. The January white sale discounts every bedsheet and towel in the store. Another week everything Tommy Hilfiger makes is discounted. This Saturday only, customers get 5 percent off everything in the store. Sales are a form of price discrimination. They follow the usual rule – give the discount to customers with more elastic (price sensitive) demands. You show your sensitivity by informing yourself about the upcoming sale and postponing your purchases until then. The store benefits because it makes a smaller margin over cost but from people who might not otherwise have purchased there. People who are less price-sensitive don’t look for ads in the papers and are more likely to shop on non-sale days. Much price discrimination involves small hoops like these that elastic demanders will jump through and inelastic demanders won’t. Grocery coupons provide a similar example.

That brings us back to Kiesling scenario. Say she pays $200 a month for electricity. With 700-odd hours in a month, when she is out of the house it consumes, say, 40 cents of power in an hour. In the usual morning blizzard of texts, emails, blogs, broadcast information, phone calls and newspapers she learns that unless she acts quickly she will have to pay 80 cents for power from 9 to 10 AM. (Remember this is not a recurring, programmable event.) Remotely changing the home settings involves an opportunity cost (other potentially lucrative communications or perhaps relaxation) in return for which she saves all of 40 cents. At least she is fortunate enough to be on a train – imagine doing this in your car.

No problem if she thinks the saved 40 cents is worth it. We’ve all read Free to Choose. Inelastic demanders prefer doing things other than tweaking their systems and tracking prices to save what they view as small amounts. Elastic demanders key in the new commands and benefit by their individual standards, but getting the benefit requires jumping through the hoop of becoming skillful programmers and watching for real-time price contingencies that they haven’t programmed for. (How much of your DVD recorder manual have you actually taken to heart?) Everyone faces the same real-time prices, but only those willing to take the trouble get a discount. The utility can make larger dollar profits, even if its rate of return is regulated.

This story helps to explain utilities’ infatuation with Smart Grid investments. Environmental policy and the continuing growth of non-utility power production both mean that they won’t be building as many powerplants as before. The Smart Grid hardware it installs on both sides of the meter is an alternative to rate-base generation and maintains the company’s economic and political presence. Discrimination also helps explain the seemingly inconsistent endorsement of interoperability standards by monopoly utilities. Utilities will own much of the basic hardware and earn returns on it. Customers who purchase their own gizmos to better track and adjust consumption facilitate finer price discrimination with no impact on the utility’s relationship with its other customers. This reasoning is also consistent with utilities’ tolerating and crediting home solar production, which generally occurs during peak hours.

Price discrimination also predicts that one thing will definitely not happen. Utilities will find it more than ever in their interests to keep competitive suppliers out of the retail market. Competitive sellers who offer rate plans that fluctuate less than real-time prices will attract utilities’ cash cow customers who don’t adjust to high prices, leaving them with elastic demanders who give them lower margins on low prices. Kiesling has correctly noted that a Smart Grid without retail competition creates a lot less value than one with it. The question to address is whether a large scale Smart Grid is worth having at all if that competition is absent.