Decoupling & Demand Side Management in Colorado

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.

  1. 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.
  2. 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.
  3. 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.
  4. 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.
  5. 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.
  6. 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.

Continue reading Decoupling & Demand Side Management in Colorado

A Decoupling Update

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?

Learn more about utility revenue decoupling on our resource page…

Featured image of binders (full of PUC filings…) courtesy of  Christian Schnettelker on Flickr. Used under a Creative Commons Attribution License.

Utilities Decoupling to Cover Their… Assets

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.

Continue reading Utilities Decoupling to Cover Their… Assets

Minneapolis eyes way to push utilities to be greener

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.

Arizona Public Service Diversifies Generation Sources | Renewable Energy Project Finance

Arizona has decided to include externalized costs like water use and pollution in their utility resource planning process, with the predictable result that they’ve selected a resource portfolio heavy on renewables and energy efficiency, and light on coal.  Hopefully other states will follow their lead!

A Power Company President Ties His Future to Green Energy

Yale Environment 360 has an interview with the CEO of NRG Energy, a fossil fuel based, nationwide independent power producer (IPP) that sells their 22GW of generation into the wholesale market.  He’s bullish on solar PV, much less so on wind.  No mention of solar thermal.  He believes storage will be vehicle batteries.  Net metering policies and pricing will be key to broad adoption.  Given the lack of forecast energy demand increase, he sees different sources of energy (esp. coal, gas, solar, wind) having to compete for market share for the first time.  It’s important to note that as an IPP his position and incentives are much different from those of regulated utilities like Xcel, who certainly do not want to “keep [their] rates to [their] consumers down and get these electrons onto its grid at a very cheap price”.  And I think regulated utilities still make up a large majority of electrical generation in the US.