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.
What is revenue decoupling?
Most utility customers get billed based on how much energy they use. If you use twice as many kWh, you pay roughly twice as much. This is called volumetric pricing. Seems reasonable, right? But there’s a problem: many of the costs of providing electricity are fixed costs, which means they’re pretty much the same, regardless of how much electricity customers buy. Fixed costs include transmission and distribution systems — stuff like the poles and wires and substations — as well as most of the (sunk) costs of building and maintaining the power plants that are already on the grid.
This creates a mismatched set of economic incentives — customers see electricity as a variable expense (buy more — pay more, buy less — pay less) but the utilities have a bunch of financial commitments that don’t depend on how much electricity their customers buy. This is a problem if we want to improve energy efficiency, because it creates an incentive (the so-called throughput incentive) for utilities to want to sell more kWh, even when it’s economically and environmentally sensible for their customers to invest in efficiency instead. If customers use half as much electricity, utilities collect half as much money, but their costs don’t get cut in half, so they end up being less profitable.
This is especially problematic when we put the electric utilities in charge of demand side management (DSM) programs that are supposed to facilitate improvements in end user energy efficiency, which is kind of like putting an oil company in charge of selling electric cars. If they’re legally required to do it, they’ll do it begrudgingly, and they won’t do any more of it than they absolutely have to, no matter how good it might be for their customers. Looking at Xcel Energy’s 2013 DSM report, we can see that they reduced peak demand and overall energy consumption just enough to meet their mandated DSM goals. At the same time, the cost-effectiveness was just low enough to ensure that they spent their entire DSM budget, which was set by the PUC. This outcome isn’t surprising, given their incentives. Under Colorado legislation passed in 2007 the utility is entitled to a higher rate of return on capital investments in DSM, so given that they’re required to meet the DSM targets set by the legislature, they might as well spend as much money as they’re allowed to, to save as little energy as they can get away with. This maximizes their returns from DSM investments, while minimizing the number of kWh they don’t get to sell. If we’re interested in increasing energy efficiency, this is not an ideal arrangement.
Revenue decoupling is one way to work around this problem. It allows utilities to automatically recover their fixed costs regardless of how much energy their customers use. If demand for electricity drops, the utility is empowered to raise their per kWh rates in a formulaic way, such that they still recover the same fixed costs that they would have recovered if electricity demand hadn’t changed at all. This means the amount of money they collect overall (their revenues) are no longer related (coupled) to the amount of electricity they sell — at least when it comes to the fixed costs of generation. The variable costs like fuel aren’t an issue here, since if you don’t have to generate the electricity, you don’t have to spend money on things like fuel.
Revenue decoupling alone is no panacea
On its own, decoupling just makes utilities indifferent as to whether their fixed assets are being used. It means that they don’t need to fear energy efficiency programs, distributed generation, and the possibility of a “utility death spiral” in which innovation behind the meter at the distribution edge of the grid reduces demand for their product, forcing them to recover the same costs over fewer kWh, increasing rates, making further investments in efficiency and distributed generation more attractive. This dynamic was well explored by Dave Roberts in his Utilities for Dummies series last year. It’s important to note that decoupling wouldn’t prevent the overall price dynamics of the death spiral, it just keeps those dynamics from harming the utility directly.
The business consequences of utility decoupling are different in a market where demand for electricity is increasing, vs. one where it’s flat or declining. In a market where demand is increasing, a decoupled utility faces a choice between building new generation facilities, and making DSM investments that obviate additional generation. In this scenario it’s easier for the DSM to be cost effective, since it’s competing against not just the marginal cost of an additional kWh, but the fixed capital/capacity costs as well. On the other hand, in a market where demand is stable or declining the generation assets that DSM might displace already exist, so you have to pay off the capital expenses somehow, regardless of whether you use them or not, which means only the operating expenses can truly be avoided.
According to US EIA data, Colorado’s regulated utilities appear to have pretty stable annual generation. They generated 42 TWh of electricity in 2001, and 41 TWh in 2013, with less than 10% annual variation in the intervening years. Xcel’s DSM programs saved a few hundred GWh each year between 2009 and 2013 (or about 1% of overall generation) so it seems unlikely that DSM played a large role in keeping the overall generation curve flat.
Cynically, we can look at the decoupling proposal as the utility trying to protect itself from the financial consequences of having made bad investments in generation capacity that’s actually less cost-effective than energy efficiency. Xcel’s DSM program reports from 2009 to 2013, show that overall they’ve spent the equivalent of $892/kW and avoided needing about 375MW of capacity. According to the US EIA this is comparable to the capital costs of the cheapest natural gas fired generation… and it comes with zero operating costs and thus zero fuel price risk — clearly a great deal for the rate paying public!
Decoupling would also insulate the utilities from any kind of “behind the meter insurgency”. Many of us think it would be great if utilities could be brought to the negotiating table with threats of locally funded efficiency and distributed generation cannibalizing demand and cutting into profits. If they decouple, then that threat loses any teeth it might have had, leaving only grander efforts available, like Boulder’s bid to condemn Xcel’s infrastructure and create its own green municipal utility.
The problem with this cynical take is that we’ve already made a bunch of investment mistakes, and our designated representatives at the PUC have entitled the utilities to recover their costs. There’s every reason to think that attempting to claw that bad money back from them — and their shareholder’s profits — would be a knock-down, drag-out fight to the death. And in this fight even winning could mean losing — if it results in years of litigation and delay — time we simply do not have in the context of climate change.
Our first task is to stop making enormous capital and carbon intensive investment mistakes! Our second task is to get the existing carbon intensive generation taken offline as quickly as possible. Satisfying though it might be ideologically, is it really the best strategy to go head-to-head with gigantic, well funded, politically connected corporations — especially in a country where they are allowed to make unlimited, secretive political contributions (something we should change!) and are treated as “persons” with free speech and even religious rights? Or is it easier to change the rules of the game such that they are rewarded for doing what we want them to do? Is it possible to defuse their opposition without precluding the democratization of our energy systems?
What else do we need?
Revenue decoupling is an enabling policy, but it could be transformational if it were applied in combination with a few other changes.
Colorado’s existing DSM legislation passed in 2007 (Colorado HB 07-1037) mandated modest demand reductions, and offered utilities a higher rate of return on investments made in DSM than those made in generation, but rate of return isn’t everything. Utilities often sell themselves to investors on the basis of their capital investment pipeline — the list of projects they’ve got lined up year after year, and the absolute amount of money they anticipate their regulators will allow them to deploy. For DSM to be attractive to utilities, it likely needs to be possible for them to deploy a large volume of capital toward it — at least an amount that’s comparable to what they would have spent on the generation it’s displacing. But this really doesn’t need to be a problem — both DSM and renewable power have a much higher proportion of their costs in capital expenses than operating expenses — in stark contrast to fossil fuel based generation — so in theory it should be possible to build a big fat capital investment pipeline around them, even while we potentially reduce costs to consumers.
The amount of money that can be deployed on DSM will depend largely on how we define what’s “cost effective.” There are several policies that could dramatically expand the DSM landscape:
- If we are to have any chance of keeping global temperatures from increasing by more than 2°C, we need to retire our carbon intensive power plants in the near future. This means writing off their capital costs is a foregone conclusion. If those plants are going to be retired, then DSM should really be competing against the combined capital and operating expenses of new generation, not just operating expenses of fossil plants we’ve got online today.
- As we’ve discussed in the context of Colorado’s Electric Commodity Adjustment, we should be fully pricing the risk of future fuel cost increases, which DSM is not exposed to.
- We should use a lower social discount rate on projected future fuel costs in our electric resource planning process, since those costs are reimbursed by rate payers as they are incurred, not financed many years in advance with capital raised by the utilities.
- We should be explicitly pricing climate change, public health impacts, and other negative externalities which DSM does not have.
The above policies mostly increase our estimates of the costs avoided by investing in DSM, making DSM (and renewable energy too) look more financially attractive in comparison.
Another option would be to change the way the cost of DSM itself is calculated. Today the metric we use is based on the Total Resource Cost (TRC) — which includes all the money that’s spent on a DSM project by both the utility and the customer (even though just the investment made by the utility is reimbursed from electricity sales revenues). This is supposed to account for the “broader cost to society” of the investment in DSM — to avoid participants inadvertently over-investing in energy efficiency that’s actually not efficient… in a macroeconomic sense.
But it’s hard not to see the irony dripping from our regulatory framework when just this one very narrow “broad cost to society” is taken into account, while financial risk, climate change, public health and other societal costs are excluded from the calculation.
The Business Construction
Does it seem strange that we would think about what outcomes we want, and then design the market such that those outcomes are the least cost options?
This is exactly what the utilities do in their ongoing dance with regulators. The difference is that they do it with their interests, not ours or our children’s, in mind. All markets are designed. It’s just a matter of by whom, and to what ends.
As Brockett notes early in his 215 pages of testimony:
The guiding principle for the design of the revenue decoupling mechanism should be the specific policy objective(s). In other words, the revenue decoupling mechanism should be consistent with the policy decision as to which risks and impacts should be mitigated and which should continue to be borne by the utility.
The utilities aren’t shy about making the case for their desired policy objectives. We shouldn’t be either.
Written in collaboration with Christina Gosnell. Utility Work Ahead featured image via Consumer Energy on Flickr, licensed under a Creative Commons Attribution, Non-Commercial, Share Alike license.