Smart Grid Doldrums - Re-Calibrating Smart Grid 1.0
- Rate case filings have demonstrated transparently that the benefits of AMI investments are less than the costs – AMI does not pay for itself
- The justification for AMI investments is based on value-added applications beyond AMI (“the Smart Grid”) – if they are not implemented, electricity bills will increase, by definition
- One must question using the same discount rate for benefits and costs, because they represent different levels of risk
- AMI business cases are flawed and might be challenged under the “used and useful” principle of rate-making
- Policy and regulatory changes necessary to realize the Smart Grid benefits of AMI infrastructure (Smart Grid 1.0) have lagged deployments; realizing key benefits of Smart Grid 2.0 investments is strongly dependent on the oft-discussed changes being implemented
- Value-added applications deployment have lagged vendors’ promises
- Investors have soured on AMI Smart Grid opportunities
- We have learned a lot from AMI deployment and operating experience to date
- We have only just begun – we need to plan for the second wave of investments in the Smart Grid: AMI 2.0 and Smart Grid 2.0, and we need to do a better job on the business cases
- Some aspects of the market won’t change no matter how much we complain about them – we need to recognize that in our business cases
- Regulatory policies will change, but very slowly, increasing our ability to realize the benefits of Smart Grid infrastructure
Prequel: The Story So Far
Since 1995, utilities have been successfully making the case to regulators, city councils and consumer boards for a major infrastructure (IX) investment: Advanced Metering Infrastructure, or AMI. The investment amount has been high – about $100 per end-point on average across their entire service area, although this number has been coming down.
In rate filings, the net present value (NPV) of the AMI investment for the metering automation was shown to be substantially negative – that is, the present value of the benefits was less than the present value of the costs.
But the case was made that AMI was also an “enabling” IX investment (Smart Grid 1.0) – the resulting communications and control network overlaying the service area could accommodate the value-added applications of Smart Grid 2.0 such as demand response (peak reduction, load control, capital avoidance), distribution automation, reliability improvement, and pollution reduction, adding to the “benefits” stack and taking the NPV into positive territory.
All of the costs and benefits were discounted at the utilities’ after-tax weighted average cost of capital, around 8%.
Big Cost Numbers, Thin Benefits?
Let's look at some historical information about how the original AMI business cases were justified.
In their AMI rate case filing in December 2006, SCE showed a positive NPV of $106 million on a total investment of $1.2 billion (PV). The PV of their benefits stack was $1.3 billion, with $626 million of this coming from demand response. Without these value-added applications, the AMI investment had a negative NPV of about -$525 million.
In their filing in June 2002, PG&E showed a negative NPV of about -$400 million for their AMI investment of $1.95 billion (PV), and estimated additional net benefits from five demand response scenarios to be in the range of $79 to $1,218 million, or $79 to $640 million, if an outlier scenario was eliminated.
Today, with the advantage of hindsight, we can say that these original AMI business cases were optimistic.
In a recent case, Connecticut Light & Power estimated in February 2011 an NPV of $87 million on a capital investment of $490 million assuming additional benefits from capital avoidance, peak reduction, energy reduction, value of reliability, and carbon dioxide reduction of $365 million.
So, the justification for the AMI investment depends on its ability to enable the value-added services of Smart Grid 2.0 that go beyond automated metering. AMI, by itself, will not pay for itself.
Aren’t The Benefits More Uncertain Than The Costs?
One must question using the same discount rate to value the benefits of the value-added services as was used for the costs of the IX investment. The costs would be more certain, given that they occur in the nearer-term and are better known. For the case of the investor-owned utilities, the IX investment would be placed in the rate-base with the opportunity to earn the allowed rate-of-return over its lifetime.
On the other hand, the benefit streams arising from the value-added applications would depend on new, non-commercial technologies, changing the behavior of electricity customers, and successful integration with utilities’ back-end processes – arguably involving a lot more uncertainty that earning an allowed return on a rate-based AMI investment.
If we were to increase the discount rate above the utilities’ weighted-average cost of capital and apply that to the benefits stack, its size would be reduced, and perhaps significantly so. Which cash flow stream would you choose? (!)
I would say that the analyses of the business cases were flawed. Enabling infrastructure investments were not distinguished from value-added investments that add intelligence to the grid, especially in terms of investment objectives and risks.
Ominously, at least one public utility commission is today questioning the “prudency” of a utility’s AMI investment with the possibility that some of the capital might not be allowed into the rate-base. We have justified Smart Grid 1.0 investments in terms of their value in enabling Smart Grid 2.0. Now, as a community, we need to implement Smart Grid 2.0, including the regulatory changes necessary to enable it.
No Surprise – The Chickens Have Come Home to Roost
Utilities selected AMI system vendors based on their AMI capability, but also, given the need to justify the business cases, on the systems’ ability to support the proposed value-added services beyond advanced metering itself.
The AMI vendors were challenged because they had little operational experience with their “smart metering systems” in the field. Costs to implement have been somewhat higher, there have been delays in deployments, and there have been some system performance issues. That is no worse than normal for new technology systems (“it’s complicated!”), but it hurt the vendors’ financial performance, and the credibility of the utilities.
More troubling, the AMI vendors’ core technology and capabilities have not emphasized the value added services (Smart Grid 2.0). They launched the required value-added services, but these were simply not ready for prime time – in particular, integration of AMI systems with utilities’ other operations has proved to be difficult, distribution automation applications have been sparse, and Home Automation Networks (HANs) have yet to prove their worth. Furthermore, customer behavior was slow to change – “we don’t need no automation” (if our bills don’t get smaller).
Most worrisome, the very regulatory policy shifts, market protocols, and tariff structure changes that were needed to incentivize energy savings and peak shifting behavior associated with Smart Grid 2.0 applications have lagged the AMI and value-added service deployments, and continue to do so. A clear example of the effects of this policy lag is the current inability of distributed energy storage (DES) applications to realize all of their potential benefits (see the subsequent dialog on SGiX for an analysis of the DES benefits "stack").
Notable Disappointments Have Affected the Availability of Investment Capital
As a result, high-public and private companies and initiatives involving AMI and Smart Grid applications have not performed up to expectations.
Examples include Elster (re-organized, taken private), Sensus (for sale), Beacon (declared bankruptcy, purchased by private equity fund), Echelon (high quality technology but too pricey), Silver Spring Networks (roll-out set-backs, unprofitable, difficulty in going public), City of Boulder’s Smart City (costs were $2,000/customer well over the target of $500/customer), Current Group (abandoned its high band-width offering), Comverge (stock price tumbled from $18 down to less than $2 when taken private recently), Itron (steep decline in stock price since 2008, flat) – not to pick on these few situations – I’m sure you can all add your own examples.
Many VCs invested in Smart Grid companies during the early euphoria. Some of these funds had extensive experience with the electricity sector, and some did not. Today, these investors have turned bearish as many Smart Grid companies struggle for growth, profitability and sometimes, liquidity.
The long sales cycle of Smart Grid infrastructure (IX) is a mismatch with the VC investment cycle. Quick learners, VCs are now limiting themselves to low capital requirement, early revenue-generating software and services companies, for the most part. And they are asking much more searching questions about business cases. However, their interest can be resurrected by Smart Grid 2.0 opportunities which may better match their investment objectives.
- Slow cycle, long-lived, capital-intensive, IX investments (Smart Grid 1.0) which enable:
- Faster-cycle, low-capital, smart subsystems, and value-added service business opportunities (Smart Grid 2.0), especially those that can reduce customers’ bills in the near-term. These faster-cycle applications are a prerequisite to achieving an overall benefit/cost ratio that is “right-side-up”.
But Today, There’s Some Good News Too – Market Drivers Are Shifting in Our Favor
There are some positives about the Smart Grid IX market that can lead to accelerated growth:
- Technology risk is decreasing as more experience is gained – we’ve learned a lot
- Some price reductions are being realized from automation and from volume manufacturing, and this trend is expected to continue
- As Smart Grid-related automation increases, there is an increase in electricity service reliability, e.g., better outage management systems
- ISO protocols and data collection (e.g., from synchrophasors) are being improved continuously, enabling wholesale players to take advantage of the “big data” and automation that the Smart Grid delivers, while providing the means to better use existing assets with smart “overlays”
- Much progress is being made on interoperability standards to overcome the “tower of babel” that currently exists in power systems
- Cyber-security is becoming a driver for modernizing the control systems of the grid and eliminating or protecting the large number of existing legacy systems
- The analog world is inevitably shifting to digital – Smart Grid technologies leverage this – eventually all of AMI and the Smart Grid will use the Internet as its operating system
The Sequel – We Have to Create Better, More Realistic, Business Cases
How does SGIX propose to help make the future different for the Smart Grid?
As Smart Grid professionals, we’ve all spent a great deal of money and effort analyzing, deploying, and operating Smart Grid systems over the past decade or more. There is a vast amount of mixed-quality information available – SGIX will curate it. There exists a widely dispersed community of now-experienced Smart Grid knowledge workers – SGIX will collect them together and provide the platform and the tools for them to collaborate and create better business cases.
We also feel certain that some early Smart Grid 2.0 applications have been short-changed – legitimate benefits have been omitted from the benefits stack, mainly due to the complexity of the analysis necessary to estimate distribution, transmission, and power system economic and service reliability benefits.
Some Smart Grid 2.0 investments will still involve substantial "lumpy" infrastructure investments, particularly in transmission and distribution systems. We need to distinguish those investments from the others, and evaluate them differently.
Our goal? Create more viable, more feasible, more realistic business cases for Smart Grid 2.0.
Let’s not fool ourselves – even though we have spent a lot of money on Smart Grid IX, we will need to have a second wave of substantial investments to add the enabling/value-added services to the basic IX – in effect to upgrade to AMI 2.0 and Smart Grid 2.0. – this next wave is our “sequel”.
Plus Ça Change, Plus C’est La Même Chose – “The Immutables” in Our Market
While we’re doing this, we need to admit to ourselves that some things will never change, and take proper account of them in our business cases -- take a heavy dose of realism, as it were:
- The pace of utility decision-making will not increase
- Regulatory policy-making will remain a viscous, confrontational, and slow process
- A fundamental business transformation to a smart-grid-based operation by utilities will take many decades
- The ability of regulated utilities to market new Smart Grid services will remain challenged
- There will be economic cycles
Let’s Not Be Too Fatalistic, Though
It makes sense, as part of our business cases, to develop a strategy for changing difficult-to-change but universally beneficial factors, such as:
- Regulations that support better use of resources and fairly allocate the costs and benefits of Smart Grid system deployments
- Incentives that change the traditional behavior of utilities and the indifference of customers
- Doing a better job of distinguishing between enabling infrastructure investments and value-added investments
Your comments on our “take” on the State of the Smart Grid are cordially invited (see box below).