Utility revenue decoupling is often seen as an enabling policy supporting “demand side management” (DSM) programs. DSM is a catch-all term for the things you can do behind the meter that reduce the amount of energy (kWh) a utility needs to produce or the amount of capacity (kW) it needs to have available. DSM includes investments improving the energy efficiency of buildings and their heating and cooling systems, lighting, and appliances. It can also include “demand response” (DR) which is a dispatchable decline in energy consumption — like the ability of a utility to ask every Walmart in New England to turn down their lights or air conditioning at the same time on a moment’s notice — in order to avoid needing to build seldom used peaking power plants.
For reasons that will be obvious if you’ve read our previous posts on revenue decoupling, getting utilities to invest in these kinds of measures can be challenging, so long as their revenues are directly tied to the amount of electricity they sell. Revenue decoupling can fix that problem. However, reducing customer demand for energy on a larger scale, especially during times of peak demand, can seriously detract from the utility’s ability to deploy capital (on which they earn a return) for the construction of additional generating capacity. That conflict of interests is harder to address.
But it’s worth working on, because as we’ll see below, DSM is cheap and very low risk — it’s great for rate payers, and it’s great for the economy as a whole. It can reduce our economic sensitivity to volatile fuel prices, and often shifts investment away from low-value environmentally damaging commodities like natural gas and coal, toward skilled labor and high performance building systems and industrial components.
The rest of this post is based on the testimony that Clean Energy Action prepared for Xcel Energy’s 14AL-0660E rate case proceeding, before revenue decoupling was split off. Much of it applies specifically to Xcel in Colorado. However, the overall issues addressed are applicable in many traditional regulated, vertically integrated monopoly utility settings.
Why can’t we scale up DSM?
There are several barriers to Xcel profitably and cost-effectively scaling up their current DSM programs. Removing these impediments is necessary if DSM is to realize its full potential for reducing GHG emissions from Colorado’s electricity sector. Revenue decoupling can address some, but not all of them.
There are the lost revenues from energy saved, which impacts the utility’s fixed cost recovery. If the incentive payment that they earn by meeting DSM targets is too small to compensate for those lost revenues, then the net financial impact of investing in DSM is still negative — i.e. the utility will see investing in DSM as a losing proposition. Xcel currently gets a “disincentive offset” to make up for lost revenues, but they say that this doesn’t entirely offset their lost revenues.
Even if the performance incentive is big enough to make DSM an attractive investment, the PUC currently caps the incentive at $30M per year (including the $5M “disincentive offset”), meaning that even if there’s a larger pool of cost-effective energy efficiency measures to invest in, the utility has no reason to go above and beyond and save more energy once they’ve maxed out the incentive.
If this cap were removed, the utility would still have a finite approved DSM budget. With an unlimited performance incentive and a finite DSM budget, the utility would have an incentive to buy as much efficiency as possible, within their approved budget, which would encourage cost-effectiveness, but wouldn’t necessarily mean all the available cost-effective DSM was being acquired.
Given that the utility has an annual obligation under the current DSM legislation to save a particular amount of energy (400 GWh), they have an incentive to “bank” some opportunities, and save them for later, lest they make it more difficult for themselves to satisfy their regulatory mandate in later years by buying all the easy stuff up front.
It is of course the possible that beyond a certain point there simply aren’t any more scalable, cost-effective efficiency investments to be made.
Finally and most seriously, declining electricity demand would pose a threat to the “used and useful” status of existing generation assets and to the utility’s future capital investment program, which is how they make basically all of their money right now.
Revenue decoupling can play an important role in overcoming some, but not all, of these limitations. With decoupling in place, we’d expect that the utility would be willing and able to earn the entire $30M performance incentive (which they have yet to do in any year) so long as it didn’t make regulatory compliance in future years more challenging by prematurely exhausting some of the easy DSM opportunities.
One of the main reasons utilities fight distributed generation like rooftop solar is that it erodes demand for their centrally generated electricity. Reduced demand is annoying for any business, but it’s especially bad for traditional monopoly utilities. It’s especially bad because much — even most — of the cost of producing a kWh of electricity doesn’t go away if you don’t produce that kWh of electricity. These so-called “fixed” or “non-production” costs come from multi-decade financial commitments to big pieces of infrastructure — the power plants, transmission lines, and distribution systems.
So when you put solar panels on your roof and reduce the amount of electricity you need to buy from the utility, there’s a little bit of fuel that doesn’t get burned, and a little bit of money saved on the utility side (but as we’ve pointed out before, they don’t actually benefit from that cost savings), but a lot of the money that the utility spent to be able to provide you with electricity if you needed it is already spent. This is problematic because most electricity rates are designed to recover utility costs in proportion to the amount of electricity you buy (this type of rate is known as a “volumetric rate”). So utilities have an incentive (known as the throughput incentive) to ensure that their electricity sales increase, or at the very least don’t decline.
If lots of people start buying much less electricity, this reduces utility spending on things like fuel, but it doesn’t have any effect (in the short term) on the fixed or non-production costs. To stay solvent, the utilities then go back to their regulators and say “Hey, we’re not getting enough revenue to cover our costs. Give us a rate hike!” and if the regulators agree, allowing the utilities to recover the same fixed costs from fewer overall kWh of electricity sold, this just makes it even more financially sensible for people to put solar panels on their roof, to avoid buying the more expensive electricity. (And in our fantasy world, one could also imagine savvy regulators taking measures to decrease fixed costs, by forcing early retirement of risky, uneconomic fossil generation…)
This is the essence of the Utility Death Spiral that’s gotten so much attention over the last year or two (including a speakeasy we hosted), and which Dave Roberts did a great job of exploring in his Utilities for Dummies series over at Grist. From the Utility’s point of view the Death Spiral can be short-circuited with revenue decoupling… up to a point. With decoupling, they don’t have to go to regulators and ask for a rate hike — they can recover the fixed costs in a formulaic way, and so decoupled utilities are able to invest in energy efficiency without worrying about lost revenues. They’re also likely to be less opposed to modest amounts of distributed generation.
In fact, it’s hard to imagine a climate-aware utility of the future that isn’t decoupled. We need to get away from utilities treating electricity (and energy more generally) as a commodity, with profits tied to the quantity of product they sell. Instead, we need to move toward treating energy as a service — Amory Lovins’ famous hot showers and cold beer — with an incentive to provide high quality service using the least possible amount of underlying energy.
Decoupling is a Good Thing™
However, if you care about climate, then you always have to ask not just Is this a good thing? but Is this good enough? It’s an old cliché that “better is the enemy of good enough,” — i.e. spending time and money and effort on improvement beyond what’s good enough can be wasteful. But in the context of climate, we have the opposite problem. Moving things in the right direction can still mean abject failure. Plenty of things that are better than the status quo — like decoupling utility revenues, or burning natural gas instead of coal — come nowhere close to being good enough to keep us from seeing more than 2°C of warming.
To have a chance of stabilizing the climate, the utility business model can’t just be tinkered with. It needs to be radically transformed. The good news is that radical transformation is probably on the table whether the utilities want to talk about it or not. Our task is to make it happen as quickly and smoothly as possible.
Until very recently anybody afraid of the death spiral dynamic might have seemed a little paranoid. DG was still pretty expensive, and often dependent on utility rebate programs, tax credits, and other incentives that were often controlled by regulators and utilities. As the price of distributed solar has fallen, rebates have dwindled to nothing, and new financing mechanisms and business models have emerged. Utilities and regulators have lost some of their ability to moderate deployment, and they’re poised to lose much more.
Mosaic has created a peer-to-peer lending platform that lets individuals invest in diversified portfolios of smaller distributed solar projects, earning around a 5% return on their investments. They’ve done about $10M worth of financing this way. Now they’re getting into solar loans with backing from a large international re-insurer, adding another $100M in capital.
Sungage just raised $100M in funding from a large northeastern US credit union to use as a revolving solar loan fund.
SolarCity has started issuing solar bonds with a similar yield directly to the public on a much larger scale. They’ve raised more than $100M so far, without going through the traditional finance industry.
Big time sprawling suburban home builder Lennar is now installing rooftop PV systems by default in some markets, including around Denver. They’re offering home buyers a power purchase agreement (PPA) in which they get a 20% discount off of retail electricity rates for 20 years.
From the consumer’s point of view what this means is that in an increasing number of markets, rooftop solar can now be had at a discount to utility power, with no up front costs. This is new and different and scary for utilities, because it means rooftop solar can go big. Fast. Additionally, Elon Musk (who heads both electric car maker Tesla Motors and SolarCity…) is investing $5 billion (with a B) in a massive lithium ion battery factory in Nevada, hoping to drive costs down through economies of scale.
Suddenly, a good chunk of the traditional utility customer base starts to look a little sketchy.
Net Metering Required (For Now)
Many of these disruptive businesses depend on net metering policies and so utilities, including Xcel, have coordinated with the climate-denying corporate octopus that is the American Legislative Exchange Council to try and repeal it. So far net metering has been pretty durable. The policy is easy to understand and seems fair to most of the public, so it’s popular. Net metering also now has its own relatively well funded corporate advocates in the form of Big Solar — the very same companies raising hundreds of millions of dollars, listed above, being represented by The Alliance for Solar Choice (TASC) — one of the intervenors in 14AL-0660E (which is the PUC’s catchy name for this whole rate case thing we’ve been involved in).
In Colorado (and elsewhere) these dynamics have brought us to a regulatory stalemate. For once the status quo — net metering — favors distributed renewable electricity. It’s the policy that Big Solar has bet the farm on. But if we try and use it to scale up cheap rooftop PV dramatically, it may destabilize the utilities.
Straight net metering also won’t result in a particularly optimal deployment of distributed energy resources, because all it accounts for is energy production, and there are many more subtle qualities that are important to a well functioning electricity grid. If we can integrate those other qualities — temporal, geographic, environmental, price stabilization, etc. — into our electricity pricing we’ll get a much better overall outcome. As the Rocky Mountain Institute has put it: the debate over net metering misses the point.
Be that as it may, right now there are two 800lb gorillas (or maybe, an 800lb gorilla and a 300lb gorilla) locked in mortal combat — the utilities on one side and Big Solar on the other. One side is trying to get rid of net metering altogether, and the other is willing to fight to the death to preserve it. When people bring up other ways of valuing distributed renewable energy like Minnesota’s proposed Value of Solar or Feed in Tariffs they tend to either be ignored or attacked, sometimes by both sides of the fight! For example, The Alliance for Solar Choice wasted no time in setting up a campaign to stop what they glibly re-termed Feed in Taxes and Value of Solar Taxes as soon as Minnesota made it clear they were considering Value of Solar seriously.
Headed for Strange Country
As with so many aspects of climate and energy policy, change here is inevitable. Regardless of which side prevails in the fight over net metering, as the cost of distributed solar and energy storage continue to decline, we are headed for strange territory.
If the utilities prevail and repeal net metering, they’ll probably slow the spread of distributed generation, since customers would only be able to benefit economically from satisfying their electricity demand on-site in real time, rather than banking electricity production annually. But in the longer term, given ongoing PV system cost declines and the potential for cost-effective electricity storage, the utilities will still face a decline in electricity demand regardless of whether a policy like NEM remains in place. At one extreme we could end up in a situation (well described by RMI), where defection from the grid is economically sensible for a significant number of people.
On the other hand if Big Solar prevails then we get to the same place, maybe a little quicker, since they’re already operating with a net metering based business model at significant scale. If the Feds don’t renew the Investment Tax Credit in 2016 that will push the economics out a little, but there’s little reason to think the overall price trend is going to reverse. Ever.
Does that sound ridiculous? Then note that PV in 2014 is already 59% cheaper than NREL predicted it would be back in 2010, and Deutsche Bank is forecasting that solar will reach grid parity nationwide by the end of 2016. On the wholesale side the New York Times reports that without subsidies wind on the high plains has come in as low as ¢3.7/kWh (the same as just the production costs of Xcel’s Colorado fossil fleet in 2013).
Some folks think widespread grid defection sounds like utopian energy independence. In practice it would be far less equitable, more expensive, and operationally much less robust than a well designed network that integrates a lot of distributed energy. It’s also physically impossible in cities, which consume most of our electricity, because no matter how cheap solar and storage become, cities use more energy within their boundaries than is available from renewable sources in those same boundaries. This is despite the fact that cities have much lower per capita energy use than rural and suburban places of comparable wealth. Cities are great for the climate, but they will always need to import energy, and that means we will still need transmission and distribution systems.
Um, okay. But, decoupling?
In the near term, revenue decoupling would insulate Xcel against the sales they’re going to lose to rooftop solar and other distributed energy. Rather than seeing revenues decline as more electricity sales are displaced, they’d be empowered to adjust rates in a formulaic way to compensate for the losses, and ensure that the fixed costs of the grid continue to be paid for (along with their profits). In theory, this ought to remove or at least reduce their opposition to net metering.
In the long term, if grid defection becomes attractive, additional fixed-cost recovery mechanisms like revenue decoupling aren’t going to be much help to the utility.
Our task is to open up the discussion about creating an intelligent grid with electricity prices that reflect the more subtle attributes of distributed generation. Revenue decoupling is one potential avenue into that discussion — at least the early part of it. How so?
In the short term, the utilities are fighting for the status quo, minus net metering, and they seem to be losing. If the only two positions available are the status quo with vs. without net metering, the choice for renewable energy and climate advocates is clear — we have to side with Big Solar. But if utilities were actually up for creating a different — and much more scalable — renewable energy policy, then the decision of who to work with becomes more challenging.
With revenue decoupling in place, utilities like Xcel could have more room to consider policies that support distributed generation, without seeing them as an axiomatic threat to their revenues. But to do so, they’d have to be willing to talk about unwinding their existing investments in fossil generation — otherwise, no renewable or distributed generation policy can scale up far enough to be “good enough” for the climate. That vital discussion about unwinding fossil plants is not yet happening out in the open. At least, not in the US. We’ll take a much closer look at it in a post very soon!
So, it’s been quite a while since our last long policy post, focusing on utility revenue decoupling in connection with Xcel’s current rate case (14AL-0660E) before the Colorado PUC. That’s because we’ve been busy actually intervening in the case!
A Climate Intervention
We filed our motion to intervene in early August. As you might already know, in order to be granted leave to intervene, you have to demonstrate that your interests aren’t already adequately represented by the other parties in the case. Incredibly, CEA’s main interest — ensuring that Colorado’s electricity system is consistent with stabilizing the Earth’s climate — was not explicitly mentioned by any of the other parties!
In our petition we highlighted our mission:
…to educate the public and support a shift in public policy toward a zero carbon economy. CEA brings a unique perspective on the economics of utility regulation and business models related to mitigating the large and growing risks associated with anthropogenic climate change. In addition, CEA has an interest in transitioning away from fuel-based electric generation in order to mitigate the purely economic risk associated with inherently unpredictable future fuel costs.
…and we were granted intervention. So far as we know, this is the first time that concern over climate change has been used as the primary interest justifying intervention at the PUC in Colorado. In and of itself, this is a win.
A Long and Winding Road
Throughout the late summer, we spent many hours poring over the thousands of pages of direct testimony. Especially Xcel’s decoupling proposal, but also (with the help of some awesome interns), the details of the company’s as-of-yet undepreciated generation facilities — trying to figure out how much the system might be worth, and so how much it might cost to just buy it out and shut it down (were we, as a society, so inclined).
Early on in the process, the PUC asked all the parties to submit briefs explaining why we thought it was appropriate to consider decoupling in the rate case, whether it represented a collateral attack on decisions that had already been made in the DSM strategic issues docket, and how it would interact with the existing DSM programs. We pulled together a response, as did the other intervening parties, and kept working on our answer testimony — a much longer response to Xcel’s overall proposal. The general consensus among the parties that filed briefs, including CEA, SWEEP, WRA, and The Alliance for Solar Choice (TASC, a solar industry group representing big installers like Solar City) was that decoupling was not an attempt to roll back previous PUC decisions related to DSM — and that addressing it in a rate case was appropriate. Only the Colorado Healthcare Electric Coordinating Council (CHECC, a coalition of large healthcare facilities and energy consumers) told the PUC that decoupling ought to be considered an attack on previous DSM policies.
The PUC staff unfortunately came back with a reply brief that disagreed and suggested, among other things, that maybe it would be better if we just went with a straight fixed/variable rate design to address utility fixed cost recovery. Never mind the fact that this kind of rate would destroy most of the incentives customers have to use energy efficiently.
And then we waited.
With baited breath each Wednesday morning we tuned in to the Commissioners’ Weekly Meeting, streaming live over the interwebs from the Windowless Room in Denver. We watched regardless of whether anything related to our dear little 14AL-0660E was on their agenda. Just in case they tried to sneak it by. Weeks passed. And then a month. The deadline for submitting our answer testimony approached.
Finally on October 29th, six weeks after submitting our brief, the commissioners finally brought up the issue of decoupling at their weekly meeting and in a couple of minutes, indicated that they’d be severing it from the proceeding, with little explanation as to why. However, because there were no details, and the order isn’t official until it’s issued in writing… we continued working on our answer testimony. The final order came out on November 5th, and prohibited submission of testimony related to decoupling. Answer testimony was due on November 7th.
Where to From Here?
Xcel might come back to the PUC with another decoupling proposal before the next Electric Resource Plan (in fall of 2015) . Or they might not. This means that a good chunk of the work that we’ve been doing since this summer will have to come to light in a different way. So for the next few posts, we’re going to explore some of the issues that came up in the preparation of our answer testimony, including:
Decoupling and Distributed Energy: How would decoupling interact with distributed energy resources like rooftop solar? What are the implications for utilities as the costs of those resources continue their precipitous decline?
Decoupling and Demand Side Management: How would revenue decoupling interact with demand side management programs in general — both utility and privately or locally funded — and what particular issues with Xcel’s DSM programs could decoupling address? What issues can’t it help address?
Can Revenue Decoupling Scale?
Why doesn’t revenue decoupling as a policy really scale up to the point of taking existing generation facilities offline, or preventing new facilities from being built?
Decoupling as a First Step:
Even if it can’t scale, why might decoupling still serve as a useful starting point for the decarbonization process? Can it give us a little bit of breathing room while we start the real negotiation? Or is it just another layer of financial protection for utilities who want to delay change as long as possible?
Realism and Equity in Carbon Budgets for Colorado:
What is the true scope of the decarbonization challenge, in the context of the carbon budgets recently published by the IPCC in their Fifth Assessment Report (AR5), but localized to Colorado so we can actually wrap our heads around it. Why is this conversation so hard?
Last month, Xcel Energy subsidiary Public Service Company of Colorado (PSCo) filed a rate case at the Colorado Public Utilities Commission (Docket: 14AL-0660E). A lot of the case — the part that’s gotten most of the press — is about PSCo recovering the costs of retiring and retrofitting coal plants as agreed to under the Clean Air Clean Jobs Act (CACJA) of 2010. However, there’s a piece of the case that could have much wider implications. Way down deep in the last piece of direct testimony, PSCo witness Scott B. Brockett:
…provides support and recommendations regarding the initiation of a decoupling mechanism for residential and small commercial customers.
This recommendation has captivated all of us here at CEA because it could open the door to Xcel adopting a radically different business model, and becoming much more of an energy services utility (PDF), fit for the 21st century.
To explain why, we’re going to have to delve a ways into the weeds of the energy wonkosphere.
Risk isn’t free; it’s a traded commodity with a price. Most prudent financial entities with a lot of exposure to the prices of natural resources try to manage unpredictable fluctuations in those prices by trading in risk. Producers worry about prices being too low; consumers need to protect against prices being too high. Risk trading (hedging) allows the two types of parties to share these risks, and so create a more stable market overall. Stable prices are good for business. You can plan around them in the long term, even if they end up being a bit higher on average.
In regulated electricity markets like we have in Colorado, fuel price risk often ends up being borne primarily by the rate payers rather than by the utility companies. In theory, state regulators ought act on behalf of the public (energy consumers) to accurately represent their tolerance of or aversion to risk in the resource planning process. Historically, the implicit assumption has been that the rate paying public is fairly risk tolerant, i.e. very little has been done from a regulatory point of view to avoid the potential detrimental effects of future fuel price volatility. This is a historical accident. Until recently, we didn’t have much choice in the matter. Of all the major sources of power available a century ago when we began electrifying society, only hydroelectric is similar in terms of its capital and operating structure to distributed renewables like wind and solar. All three have relatively large up front capital costs, and low ongoing operating and maintenance expenses. But for most of the time we’ve had electricity, most of that electricity has necessarily been dependent on fossil fuels, and so the question of whether or not customers wanted to take on the risk of future fuel cost fluctuations was immaterial. Fuel was the only option for expanding our electricity supply once we’d tapped the easily accessible hydro — if you wanted lots of power, it simply came with fuel price risks. This is no longer the case. Today, we have options that trade off between cost and risk, but so far as I can tell we haven’t done a good job of talking about the entire spectrum of possibilities. Broadly they seem to fall into four categories:
Traditional fossil fuel-based power, that exposes rate payers to the full range of future price fluctuations.
Capital intensive, fuel-free power like wind, solar, enhanced geothermal and hydro which have a range of prices, that are very predictable over the 20+ year lifetime of the capital investment.
Fossil fuel-based power that is aggressively hedged, in order to protect rate-payers against future fuel price fluctuations.
Fuel-free power with predictable future costs, combined with someone else’s fuel cost risks, which rate-payers would be paid to take on.
The first two options are the most commonly discussed. The third — hedged fossil fuels — is becoming somewhat more common, with some public utility commissions requiring the utilities they regulate to dampen fuel cost fluctuations. However, they generally do not require the utilities to hedge to the point where the risk profile of the fossil fuel option is similar to that of fuel-free power sources. This is what makes the fourth option interesting.
Minneapolis is Xcel’s home town, and a much bigger market than Boulder. The city is now talking about allowing their franchise agreement to lapse, in order to pursue more aggressive renewable energy policies than state law will allow if they’re served by the monopoly utility. The article gives a nod to Boulder’s votes over the last two years to explore the alternatives to franchise agreements, including the formation of a municipal utility. It’s great to see another much larger city looking at its options, and as far as pushing the overall utility business model to change, it’s great to see this happening within Xcel’s service territory. There’s a threshold out there somewhere, beyond which the current arrangement is no longer stable, and even the utility will start begging for something different. The faster we can get there, the better.
In the 2011 annual report to the state legislature on the cost effectiveness of Michigan’s Renewable Energy standard, it was revealed that wind bids have been coming in far cheaper than anyone expected they would. In fact, even without the federal production tax credits, they’re far cheaper than new coal fired generation ($61/MWh for wind vs. $107-133/MWh for new coal). Interestingly, Xcel’s 2011 resource plan lists the cheapest new generation option in Colorado as being natural gas combustion turbines… at $60/MWh. So wind is cheap. It’s also very low risk. So how do we get more of it?
It’s often been said that “time is money,” and it turns out to be more than an aphorism.
I’m going to try and tell you a story about discounting, which is one of the ways that we convert between time and money. The story has broad implications for the energy investments we choose. It’s not entirely straightforward, and if it’s going to make sense there are some background pieces you’re going to need. The background is important because the ending depends not only on understanding what is being done, but why. This story happens to be about Xcel Energy and Colorado, but the same thing happens in other places, with other companies, and in other contexts too.
To greens my argument may seem circumspect. I’m not going to challenge the doctrine of Everlasting Economic Growth. I’m not going to look at the large externalized costs of burning fossil fuels. I’m not going to argue against the monopoly electrical utility model. Those are important discussions to have — they’re just not the one I’m having here. What I’m trying to do is show that a minor change in the way we calculate the cost of future energy can drastically alter what kind of power we decide to invest in for the next century, even if we only look at the decision in selfish financial terms.
To the finance geeks among you, much of the background will be familiar, but the situation may seem strange unless you’re familiar with how regulated monopolies work. I haven’t been able to find anyone familiar with energy finance who thinks what we’re currently doing makes sense, but if you’ve got a thoughtful rebuttal, I’m genuinely interested to hear it.
Almost immediately after we empowered Boulder to form a utility, a spate of articles appeared in the national press talking about the relative costs of coal and renewables, and the trends in those costs. There was Krugman’s Here Comes Solar Energy Op-Ed in the NY Times, making the case that solar PV is already cheaper than coal-fired power once you remove all the subsidies we provide to both of them, and calling for the Feds to fix regulation to make that clear. Boulder’s own RMI had a bit of commentary on Krugman’s opinion: it’d be nice if Federal regulations were saner, but even without that fix, it makes sense to build this stuff now, and will only make more sense as time goes on and the balance of system costs (which currently make up 50% or more of the cost of a PV installation) are reduced through best practices, standardization and mass production.
From the industry side, GE’s Jeff Immelt also said that federal regulation was a little beside the point now… and that even without government support GE was going all-in, expecting something like 200GW of solar to be built in China and India by the end of the decade. That’d be a non-trivial amount of generation, on the order of 10 Three Gorges dams, or as much power as the entire US nuclear generation fleet. Meanwhile NRG Energy, a nationwide and largely traditional fossil-fuel based independent power producer is planning to spend the overwhelming majority of its capital investment funds over the next few years on solar, mostly small utility projects (20-100MW) and distributed rooftop generation.
In the same vein, Xcel Energy’s recently filed 2011 Electric Resource Plan foresees essentially no new generation facilities being built until close to the end of the decade. Some of this is attributable to the soft economy, but many people are saying it’s just as much a consequence of energy efficiency, demand side management, and increasing distributed (behind-the-meter) generation coming on line. Unfortunately, Xcel added a gigawatt of coal generation to its grid last year, and this lack of demand for more energy means the company is now walking away from the transmission lines that would have enabled large-scale solar-thermal with storage in the San Luis Valley. This means that the only way to shift Xcel’s power mix in the near future will be to accelerate the retirement of existing coal-fired generation, making room for more efficiency, wind, and solar.
The optimistic narrative that falls out of the articles above — that our energy systems are undergoing a transformation — seems plausible, and I hope that it’s true. Certainly it’s the one that the Boulder Light and Power effort is going to be built around. It’s comforting to see that we’re not alone on the world stage, and less daunting to imagine our job as facilitating an ongoing transformation, rather than starting one from scratch.
